Interim Results

RNS Number : 6757H

Diversified Energy Company PLC

05 August 2021

5 August 2021

Diversified Energy Company PLC

("Diversified," "DEC" or the "Group")

Interim Results for the Six Months Ended 30 June 2021

Diversified Energy Company PLC (LSE: DEC) is pleased to announce its Interim Results for the six months ended 30 June 2021 and other recent highlights.

Period Highlights, Announced Capital Markets Day & Declared Dividend

• Declared 2Q21 interim dividend of $0.0400 per share (2Q20: $0.0375 per share, +7%)

• Record average net daily production: 106 MBoepd (11% vs 1H20: 95 MBoepd); Exit rate of 116 MBoepd

• 1H21 Hedged Adjusted EBITDA¹ of $151 million ( +3% vs 1H20: $146 million) generating Free Cash Flow¹ of $117 million with Cash Margin¹ of more than 50%

• Net Income & Adjusted Net Income¹ (which excludes $278 million ($371 million, pre-tax) of non-cash hedge valuation losses)

◦ Net loss of $84 million or $0.11 per fully diluted share (1H20: +$18 million, +$0.03/share)

◦ Adjusted Net Income¹ of $204 million or $0.28 per fully diluted share (1H20: +$112 million, +$0.17/share)

◦ Net Income includes an estimated $81 million tax credit earned on wells producing >90 Mcf/day

• Announced upcoming Capital Markets Day in early October with an emphasis on outlining the Company's near and longer-term ESG initiatives

Central Region Acquisition Highlights

• Strategic entry into a new producing area acquiring three separate asset packages with net purchase prices totalling $342 million²

◦ Indigo Minerals LLC ("Indigo"): ~2.9x multiple producing 8 MBoepd (net) in the Cotton Valley (closed May 2021)

◦ Blackbeard Operating LLC ("Blackbeard"): ~3.5x multiple producing 16 MBoepd (net) producing in the Barnett shale (closed July 2021)

◦ Tanos Energy Holding III LLC ("Tanos"): ~2.8x multiple³ producing 14 MBoepd (net) in the Cotton Valley and Haynesville Shale (expected to close mid-August 2021)

◦ Oaktree Capital Management L.P. ("Oaktree") co-invests in the geographically overlapping Indigo & Tanos packages while contributing 2.5% of its working interesting as an up-front promote to DEC shareholders

◦ Healthy balance sheet and financing capacity optimally positions DEC for additional non-dilutive growth using organic cash flow and financing capacity following a successful $225 million (gross) equity raise to part fund the acquisitions

• Quickly building scale to drive synergies; 27% of the Company's consolidated production will come from the Central Region pro forma for closing the three acquisitions

• Successful integration underway on Indigo and Blackbeard assets; Implementing Smarter Asset Management programmes

Other Operational Highlights

• Environmental, Social and Governance ("ESG") progress

◦ Published 2020 Sustainability Report with expanded disclosure of ESG performance including TCFD reporting

◦ Created executive management position to enhance accountability and drive ESG and Sustainability efforts

◦ Improved emissions monitoring and reporting through significant progress on data warehouse and asset inventory

• Established an internal team dedicated to permanently retiring wells, reducing reliance on third-party services and driving further process quality and efficiencies

◦ Permanently retired 14 wells in West Virginia at an average cost per well of ~$19 thousand, 25% below typical third-party costs

• Permanently retired 65 wells in Appalachia at an average cost of ~$19 thousand per well

◦ Represents > 80% of annual state agreement required retirements

Other Financial Highlights

• Stakeholder distributions including $62 million of dividends and $34 million of debt repayments

• Leverage ratio⁴ of 1.9x¹ at 30 June 2021 (Net Debt¹ of $633 million)

• In April (Spring redetermination): Unanimous 16-bank Credit Facility syndicate vote to fully reaffirm the $425 million borrowing base with no changes to terms

• In August (Special post-acquisition redetermination): Lead lenders within the Credit Facility conditionally committing to increase the Facility's borrowing base to $625 million (+$200 million) following completion of Central Region acquisitions and satisfactory diligence

• Significantly improved pricing outlook for natural gas creates an opportunity to hedge at levels that support higher cash operating margins. Disciplined hedging strategy protects cash flows and provides dividend and debt repayment stability

• ~90% of 2021 natural gas production protected by hedges, with current forward hedge positions including

◦ ~90% of 2H21 natural gas hedged at a weighted average price of $2.98/Mcfe⁵ ($2.76/MMBtu)

◦ ~67% of 2022 natural gas hedged at a weighted average floor price of $2.91/Mcfe⁵ ($2.69/MMBtu)

1 This non-IFRS alternative performance measure referenced throughout is defined and reconciled within our Interim Results under the caption "Alternative Performance Measures".

2 Sum of previously announced net purchase price for Indigo at 51.25% proportionate working interest ($58 million), Blackbeard at 100% proportionate working interest ($166 million) and Tanos at 51.25% proportionate working interest, excluding assumed hedges ($118 million).

3 Calculated using estimated next 12 months Unhedged Adjusted EBITDA of $51 million and total consideration of approximately $142 million, inclusive of anticipated net purchase price of $118 million and assumed mark-to-market hedge losses valued at $24 million at the time of the acquisition announcement.

4 Leverage ratio defined as Net Debt-to-Hedged Adjusted EBITDA.

5 MMBtu hedges have been converted to Mcf using a conversion factor of 1.08 (reflective of our estimated Btu factor following asset integration of Central Region acquisitions).

Commenting on the results, CEO Rusty Hutson, Jr. said:

"I am thrilled with the progress we made in this active first half of 2021, successfully delivering on a number of key strategic initiatives in line with our long-term growth strategy. Our entry into a new operating region complements our continued focus in Appalachia and introduces a geographic diversity capable of providing improved margins from higher realised pricing and a significant new runway for further value accretive and synergistic opportunities. With a business model centred on an asset profile rather than a defined geologic region, we are confident in our ability to replicate our Appalachian success in the Central Region by delivering the same operating efficiencies and cost controls that result in strong margins and consistent shareholder returns. Of course, we remain committed to tangible shareholder returns, and are delighted to once again declare an additional $0.04 dividend of the second quarter, which will add an additional ~$34 million to the already more than $62 million we have paid so far this year.

"As we step into a new region that presents significant consolidation opportunities, we welcome Oaktree's participation in both the Indigo and Tanos acquisitions. Not only does their investment validate our views of the asset quality within the Central Region, it affirms their belief in the Diversified strategy grounded in stewardship, as we continue to focus on accretive, responsible growth and operatorship of primarily natural gas assets. Our balance sheet remains healthy as we continue into the second half of 2021 with ample financing capacity to consider further complementary growth opportunities.

"We have already delivered significant progress in the second half of the year by the closing of Blackbeard, announcing the Tanos acquisition and our near-term focus on the seamless integration and optimisation of all the Central Region acquisitions. Simultaneously, we are making great progress on a number of ESG initiatives as we strive to establish our baseline for emissions reporting, expand our TCFD disclosure efforts and define our path to a net zero carbon position by 2050 or sooner. To that end, I am pleased to announce our plans to host a Capital Markets Day in October when we will continue to provide greater detail about both our short and longer-term ESG efforts while also highlighting the importance in our growth strategy and Central Region integration and operations. We will provide additional details in the coming weeks, including a specific date, and hope you will join us."

Conference Call and Webcast

DEC will host a conference call today at 12:00pm BST (7:00am EST) to discuss these results. The conference call details are as follows:

US (toll-free)	+	1 877 407 5976
UK (toll-free)	+	44 (0)800 756 3429
Web Audio		https://www.div.energy/news-events/ir-calendarevents
Replay Information		https://ir. div.energy /financial-info

A mid-year results presentation will be posted to the Company's website before the conference call and webcast. The presentation can be found at the Web Audio location noted above or https://ir.div.energy/presentations .

Later today, at 6:00pm BST (1:00pm EST), DEC will host an investor webinar during which management will discuss the interim results and the second half 2021 outlook. To register for the webinar, please contact Yellowstone Advisory at info@yellowstoneadvisory.com.

Market Abuse Regulation

This announcement contains inside information for the purposes of article 7 of the UK version of regulation (EU) no. 596/2014 on market abuse ("UK MAR"), as it forms part of UK domestic law by virtue of the European Union (Withdrawal) Act 2018, and regulation (EU) no. 596/2014 on market abuse ("EU MAR").

For further information, please contact:

Diversified Energy Company PLC	+	1 (205) 408 0909
Teresa Odom
www. div.energy
ir@dgoc.com

Buchanan	+	44 (0)20 7466 5000
Financial Public Relations
Ben Romney
Chris Judd
Jon Krinks
James Husband
dec@buchanan.uk.com

About Diversified Energy Company PLC

Diversified Energy Company PLC is an independent energy company engaged in the production, marketing and transportation of primarily natural gas related to its synergistic US onshore upstream and midstream assets.

INTERIM REPORT

For the six months ended 30, June

2021

Diversified Energy Company PLC (the "Parent"), formerly Diversified Gas & Oil PLC, and its wholly owned subsidiaries (the "Group," "DEC," or "Diversified") is an independent energy company engaged in the production, marketing and transportation of primarily natural gas related to its synergistic US onshore upstream and midstream assets. Our assets are located within the Appalachian Basin of the US and more recently have expanded into the Central Region consisting of the Cotton Valley/Haynesville area and Barnett Shale located in the states of Louisiana, Texas, Oklahoma and Arkansas.

Our proven business model creates sustainable value in today's natural gas market by generating significant cash flow, a significant portion of which we return to shareholders as a quarterly dividend. Specifically, we create value by Acquiring, Optimising, Producing and Transporting natural gas rather than drilling, completing and fracture stimulating new wells. Essentially, Diversified exists to optimally steward the resource already developed by the industry, reducing the environmental footprint, while sustaining important jobs and tax revenues for many local communities. While most companies in our sector are built to explore for reserves and develop new wells, we remain focused on safely and efficiently operating existing wells to maximise their productive lives and economic capabilities.

We implement a disciplined valuation approach to acquire long-life, low-decline producing wells and complementary infrastructure, such as midstream assets, that we then efficiently manage and optimise through our Smarter Asset Management ("SAM") programme. Through SAM, we improve or restore production, reduce unit operating costs, and generate consistent Free Cash Flow.

With regard to our midstream assets, we believe that a vertically integrated model expands our operating margins and creates additional value for our shareholders. These assets allow us to move our production to the highest-priced end market while maintaining greater control over the flow of our production. Midstream assets also diversify our revenues by generating additional revenues from fees third-parties' pay to move their natural gas on our system.

At the end of a well's productive life, we safely and permanently retire it while restoring its site to its natural condition and, when appropriate, planting trees at the site.

The result of this model is predictable and consistent production, low operating costs and stable, hedge-protected cash flows which translates to strong margins and sustainable and significant Free Cash Flow that funds systematic debt repayments and reliable dividends for our shareholders.

	Page
STRATEGIC REVIEW	6
First Half 2021 Highlights	6
Financial & Operational Results Overview	8
Environmental, Social & Governance and Corporate Responsibility	9
Strategic Outlook	10
Results of Operations	12
Principal Risks & Uncertainties	19
INTERIM FINANCIAL STATEMENTS	21
Independent Review Report to Diversified Energy Company Plc	22
Consolidated Statement of Comprehensive Income	23
Consolidated Statement of Financial Position	24
Consolidated Statement of Changes in Equity	26
Consolidated Statement of Cash Flows	27
Notes to the Interim Financial Statements	28
ADDITIONAL INFORMATION	55
Alternative Performance Measures	55
Glossary of Terms	60

We have prepared our financial statements and the notes thereto in accordance with IFRS. To complement the financial information contained within the Interim Financial Statements and to provide metrics that we believe enhance the comparability of our results to similar companies, throughout this Interim Report, we refer to Alternative Performance Measures ("APMs"). Within the APMs section located in the Additional Information section, we define, provide calculations and reconcile each APM to its nearest IFRS measure. These APMs include "Average Dividend per Share," "Adjusted Net Income," "Adjusted EPS," "Hedged Adjusted EBITDA," "Net Debt," "Net Debt-to-Hedged Adjusted EBITDA," "Hedged Adjusted EBITDA per Share," "Adjusted Total Revenue," "Cash Margin," "Cash Operating Margin," "Free Cash Flow," "Free Cash Flow Yield," "Total Cash Cost per Boe," "Base G&A," and "Adjusted G&A."

FIRST HALF 2021 HIGHLIGHTS

EXPANDING OUR FOOTPRINT WHILE DELIVERING CONSISTENT, RELIABLE PERFORMANCE

In addition to celebrating our first anniversary as a Premium Listed company, we marked another major milestone by expanding our successful strategy beyond Appalachia into a newly defined Central Regional Focus Area (the "Central Region"). In addition to closing on the first of three announced acquisitions within the Central Region, I am pleased to provide an overview of our successes thus far in 2021:

Through 30 June 2021

• Announced our strategic entry into the prolific natural gas producing Central Region with two upstream acquisitions from Indigo Minerals LLC ("Indigo") and Blackbeard Operating LLC ("Blackbeard") totalling $315 million (gross) with net production of ~32 MBoepd;

• Maintained a healthy balance sheet to fund our acquisitions with borrowings on our low-cost Credit Facility and proceeds from a successful placing of 141.5 million new shares, generating gross proceeds of $225 million, including 135.4 million placing shares and 6.1 million retail offer shares;

• Generated production of 19 MMBoe, or 106 MBoepd, representing a 6% increase over our average daily production in 2020 and our highest average daily production to date;

• Paid $62 million in dividends to our shareholders as we declare an additional ~$34 million for the second quarter interim dividend payable at $0.04 per share on 17 December 2021 to shareholders on the register at 26 November 2021;

• Published our updated Environmental, Social and Governance ("ESG") Sustainability Report affirming our commitment to stewarding the industry's developed assets further solidified by appointing a Vice President of ESG & Sustainability initiatives to champion continued progress;

• Established a vertically-integrated asset retirement team to retain operating efficiencies afforded through process repetition while reducing reliance on third-party services and further establishing Diversified as a safe, efficient and cost effective operator retiring wells; and

• Completed a successful semi-annual redetermination of our Credit Facility with a unanimous bank syndicate vote to reaffirm the existing $425 million borrowing base with no changes to pricing, covenants or other material terms (in April 2021; prior to our recent acquisitions).

Post-period Highlights

• Announced additional acquisition activity in the Central Region, including:

◦ Producing assets from Blackbeard, that we announced in May and closed in early July;

◦ Producing assets from Tanos Energy Holdings III, LLC ("Tanos") for $308 million (gross) with net production of ~27 MBoepd (signed a conditional agreement in early July and expected to close in mid-August);

• Announced Oaktree Capital Management, L.P.'s ("Oaktree") inaugural participation in two of our three Central Region acquisitions given these assets' geographical overlap, affirming our confidence in the accretive and expansive opportunities within the region; and

• Received commitments from certain lead lenders in our bank syndicate to meaningfully increase our Credit Facility's capacity from $425 million to $625 million subject only to satisfactory documentation.

These successes demonstrate continued progression of our defined core strategy, and underscore our unwavering focus on opportunistic yet disciplined growth and shareholder returns.

The Central Region

Similar to the Appalachian Basin, the Central Region provides an inventory of long-life, low-decline producing assets that nicely align with our acquisition strategy. As we consolidate assets, the region is staged to afford us synergistic opportunities similar to those we achieved in Appalachia that widen cash operating margins and provide a platform to realise additional value through our SAM initiatives.

The region benefits from a widely developed infrastructure with proximity to favourable Gulf Coast pricing, which provides basis diversification within our upstream portfolio and supports excellent economics. This new focus region complements our continued efforts to further consolidate assets within Appalachia by diversifying our access to natural gas-producing assets with high cash operating margins and favourable end markets, which is particularly beneficial in periods when basis differentials widen within the Appalachian Basin.

Each of our three recent acquisitions discussed below, including assets from Indigo Minerals LLC ("Indigo"), Blackbeard and Tanos, are immediately accretive to Hedged Adjusted EBITDA per Share based on our reported 2020 results. Under our unique operatorship, we will seek to create additional value through scale and more efficient operations.

Replicating our continued success in the Appalachian Basin, our strategy of acquiring mature producing assets supported by their existing operational personnel is naturally and highly transferable to other producing regions across the US. Retaining the assets' assembled workforce with its collective understanding of the acquired assets while eliminating corporate and related management costs fuels our SAM programme and underpins our ability to create and sustain high cash operating margins.

The Central Region is well positioned for consolidation with fewer areas attracting new development capital, providing the opportunity to expand our footprint in the region in a manner similar to our growth in the Appalachian Basin. We expect that additional scale from future acquisitions in this area will allow us to reduce costs and further improve already strong cash operating margins as we establish ourselves as the region's consolidator and operator of choice for producing assets and their related infrastructure.

Early Success within the Central Region & Oaktree Co-Investment

Rapidly building momentum in this prolific, natural gas producing area, we announced three transactions in less than three months, increasing our consolidated daily production by more than a third versus our 2020 average daily production.

In April 2021, we announced our entry into this region with the acquisition of Cotton Valley assets producing ~16 MBoepd from Indigo for $135 million (before customary closing adjustments to the 1 March 2021 effective date). We closed this acquisition in May 2021.

Also in May, we announced a second Central Region acquisition of nearby Barnett producing assets producing an additional ~16 MBoepd from Blackbeard for $180 million (before customary closing adjustments to the 1 April 2021 effective date). We later closed the Blackbeard acquisition in early July 2021.

Representing our third acquisition of assets within the Central Region in as many months, in early July we also announced our signing of a conditional purchase and sale agreement for additional assets in the Cotton Valley/Haynesville producing regions from Tanos for $308 million (before customary closing adjustments to the 1 January 2021 effective date).

Concurrent with our announcement of the Tanos acquisition, we announced Oaktree's election to co-invest in both the Indigo and Tanos acquisitions under the joint participation agreement in which DEC and Oaktree will equally fund the purchase price of the transactions. The highly contiguous nature of the Indigo and Tanos assets in the Cotton Valley and Haynesville reservoirs made these two acquisitions ideal candidates for Oaktree's participation. In exchange for our role as operator of these assets and as a function of the upfront promote arrangement in the participation agreement, DEC and Oaktree will retain proportionate working interests of 51.25% and 48.75%, respectively. Given the Indigo acquisition closed in May before the Oaktree participation closing in July, Oaktree paid a total consideration of $58 million, at closing, to DEC for its 48.75% share of the Indigo assets, representing 50% of the net purchase price.

Liquidity and Financing

To fund our expansion in the Central Region, we drew on our Credit Facility and raised gross proceeds of $225 million through the issuance of 141.5 million new shares, consisting of 135.4 million placing shares and 6.1 million retail offer shares. We issued the new shares at £1.12 per placing share, which represented a ~2.5% discount to the immediately preceding 30-day volume-weighted average price, or an 8.3% discount, from the closing mid-market price on 20 May 2021. The dilutive effect of the issuance is immediately offset at the per share level when considering the incremental Hedged Adjusted EBITDA per share added from the Indigo and Blackbeard acquisitions given their accretive nature. We also expect the successful closing of our acquisition from Tanos, net of Oaktree's participation and inclusive of the promote Oaktree will award us as operator, will further enhance the fully dilutive per share accretion.

Reflecting our commitment to maintain a healthy balance sheet, and to position ourselves with strength when negotiating asset purchases, we have funded more than $2 billion of acquisitions with nearly equal portions of debt and equity capital since our initial public offering ("IPO") in 2017, inclusive of the May 2021 placing. Our hedged, and therefore stable, cash flow profile and amortising long-term financing structures support systematic debt repayment, which reduces the volatility of our leverage and affords us access to low-cost financing, even in markets where lenders are hesitant to lend to companies that drill and complete new wells.

As of 30 June 2021 approximately 76% of our total borrowings are in fully-amortising, 8-10 year structures. Demonstrating this natural de-leveraging and our commitment to reduce borrowings, since our IPO we have repaid approximately 34% of the $998 million we borrowed to finance our acquisitions with total outstanding borrowings of just $655 million at 30 June 2021, including $417 million we repaid during this half-year reporting period.

Just as we are committed to debt reduction, we are equally committed to providing tangible returns to our shareholders. Since our IPO, we have paid $280 million to shareholders in the form of dividends and made share buybacks of $84 million, representing 33% of the $1.1 billion total equity we raised. In addition to the $62 million of dividends we have paid in 2021, we are pleased to declare an additional ~$34 million of dividends (or $0.04/share) payable on 17 December 2021 to holders of record on 26 November 2021.

Collectively, these distributions to our stakeholders demonstrate the success on our long-life, low-decline producing asset focus.

Our disciplined and sustained commitment to responsibly fund growth is reflected in our leverage levels. Since our IPO, we have consistently maintained leverage below our preferred stated limit of 2.5x Net Debt-to-Hedged Adjusted EBITDA, ending the first half of 2021 at just 1.9x. Upon completion of the announced acquisitions we expect leverage will remain below our stated limit at 2.1x with significant leverage capacity for additional, non-dilutive growth.

This leverage profile speaks to our balance sheet's strength and provides ample opportunity for added liquidity as evidenced by the recent commitments from certain lead lenders in our bank syndicate for the expansion of the borrowing base on our Credit Facility from $425 million to $625 million, subject only to satisfactory documentation. These commitments emphasise the strong performance of our assets and provide ample liquidity to continue our growth as opportunities arise.

FINANCIAL & OPERATIONAL RESULTS OVERVIEW

For the six months ended 30 June 2021, we recorded a net loss of $84 million (or $0.11 per fully diluted share) including a $278 million non-cash mark-to-market valuation loss (or $0.38 per fully diluted share; $371 million pre-tax) related to the our multi-year portfolio of derivative contracts that provide price stability through periods of volatility. Hedged Adjusted EBITDA, which excludes non-cash mark-to-market and other non-recurring charges, was $151 million (or $0.20 per fully diluted share) for the same period.

When compared to the prior reporting period our Hedged Adjusted EBITDA per Share fell modestly, the change primarily relates to the timing of the equity issuance and the closing of the acquisitions for which the equity proceeds were funding. Specifically, our reported results included only a month and a half of contribution from just one of our three recently announced acquisitions, the Indigo assets, while neither Blackbeard or Tanos had closed prior to the end of the period.

Importantly, the equity proceeds position us to increase earnings per share in future periods as we can acquire additional assets using our financing capacity and our expected increase in cash flows from operations without issuing additional shares.

Average production of 106 MBoepd includes a month and a half of production from the Indigo acquisition and 102 MBoepd from our low-decline Appalachian assets. We will more fully realise the impact of the Blackbeard and Tanos acquisitions in the second half of 2021, given that their closing dates are subsequent to 30 June 2021 and with the condition that Tanos closes as expected.

Commodity prices continued their recovery in the first half of 2021 and, while basis differentials in the Appalachian region remain wide, the broader recovery in Henry Hub prices drove $116 million of the total $136 million increase in unhedged commodity revenue as compared to the six months ended 30 June 2020. These higher unhedged realised prices were partially offset by $22 million of settled commodity derivative contract losses as market prices exceeded our hedged prices.

Compared to the same period of 2020, the average Henry Hub natural gas spot price increased 51% from $1.83 to $2.76. Importantly, this improved price environment affords us opportunities to add future hedge protection at more attractive prices thereby protecting our cash flows over the longer-term. Currently, 90% of our production is hedged for the remainder of 2021 at an average NYMEX price of $2.98 per Mcfe, which provides a healthy cash operating margin that underpins our $0.04 per share ($0.16 per share, annualised) dividend. Our hedge portfolio also provides the foundation to secure the structured debt repayments in our amortising debt structures, allowing us to repay $34 million in borrowings during the six months ended 30 June 2021. While our hedges protect revenue for much of our production, our unhedged volumes still fully benefit from the elevated price environment.

Although we benefit from rising prices on our unhedged volumes, higher prices can generate non-cash mark-to-market valuation adjustments on hedged volumes, particularly those contracts that are long-dated with significant time-related option value. When adjusting our multi-year derivative portfolio to its fair value as of 30 June 2021, we recognised a pre-tax $371 million non-cash charge in earnings. This non-cash valuation charge primarily relates to higher prices on the forward price curve for natural gas, and drives our $132 million gross profit into a $344 million pre-tax net loss. When excluding this non-cash loss, we report $27 million in pre-tax net income and Adjusted Net Income of $204 million.

Our low ongoing capital-intense business model, coupled with the successful execution of our stated strategy, naturally lends itself to generating Free Cash Flow and strong margins. For the six months ended 30 June 2021, we reported a Cash Margin of 50%, which was impacted marginally from macroeconomic pressures that drove increases in fuel and third-party midstream rates in addition to general and administrative costs we incurred to expand our operating capabilities as we enter our next chapter of growth. These strong margins allowed us to generate Free Cash Flow of $117 million, an decrease of $2 million, or 2%, when compared to the $119 million generated during the same period in 2020. These results also compare favourably to Free Cash Flow for the six months ended 31 December 2020 of $123 million.

KEY PERFORMANCE INDICATORS

Please refer to the APMs section in Additional Information within this Interim Report for information on how these metrics are calculated and reconciled to IFRS measures.

	1H21			1H20			2H20
TTM Average Dividend per Share	$	0.0400		$	0.0356		$	0.0381
Net Debt-to-Pro forma TTM Hedged Adjusted EBITDA	1.9x			2.2x			2.2x
Hedged Adjusted EBITDA per Share	$	0.20		$	0.22		$	0.22
Cash Margin	50		%	55		%	54		%
Total Cash Cost per Boe	$	7.84		$	7.05		$	6.80
Actual Wells Retired	65			52			40

∗ Our State Asset Retirement Goals and Total Recordable Incident Rate ("TRIR") are reported on an annual basis. For the years ended 31 December 2021 and 2020, our State Asset Retirement Goal was 80 wells. For the year ended 31 December 2020 our TRIR was 1.35. Consult our 2020 Annual Report for additional information on State Asset Retirement Goals and TRIR.

ESG AND CORPORATE RESPONSIBILITY

Environment and Sustainability

Our Board and Senior Leadership continue to place consistent and significant focus on our corporate responsibility towards ESG and sustainability as it relates to our acquisitive growth model, daily operational activities and community interactions. A key indicator of that focus was our second quarter 2021 announcement and filling of a dedicated Vice President of ESG & Sustainability role focused solely on driving, developing and transparently reporting on our commitment to internal stewardship efforts and the impact of those efforts on our stakeholders. In April 2021 we also released a fulsome annual Sustainability Report, which included our initial disclosures under the Task Force on Climate-Related Financial Disclosures ("TCFD") framework and our stated commitment to outlining a path to net zero carbon by 2050. We are diligently engaged in seeking and developing initiatives that will not just afford us a path to net zero carbon by this 2050 date, but also permit us to create nearer term goals and related actions aimed at achieving net zero in the most timely and prudent manner to the benefit of all our stakeholders.

We believe responsible stewardship of the resources developed by our industry is central to ESG. Accordingly, we've placed particular emphasis on effectively managing late-in-life wells to fully realise their productive lives before safely and responsibly retiring those assets. Our nearly 20 years of experience in this unique approach to managing an energy resource portfolio, coupled with our transparent disclosures of the same, reflects our long-standing and unwavering commitment to environmental stewardship.

In our 2020 Sustainability Report, we stated that we had initiated a comprehensive process to enhance our understanding of our baseline emissions data through improved data collection and monitoring with an end goal to establish an accurate baseline against which to measure future initiatives and to determine the initiatives in which our emissions reduction efforts should be immediately focused. We expect the completion of our data measurement efforts to occur in the fall of 2021. Concurrent with this project, we are also identifying projects and vendors that will provide emission reducing solutions that will allow us to make meaningful progress towards our goal. We have also expanded our methane leak detection resources and updated our leak detection equipment to allow for more efficient detection and remediation practices. As part of expanding our leak detection efforts we have begun the use of aerial leak detection systems, which allow us to monitor and evaluate our assets for potential leaks more effectively, resulting in swift remediation when and where necessary. While these devices serve to aid in the detection of carbon emissions, they do not replace the daily efforts of our well tenders' inspection of wells, related equipment and midstream assets during their routine and frequent well site and midstream visits. During 2021, each well tender visited an average of ~10 well sites per day, resulting in ~100,000 total well site visits per month across our operating footprint.

Our stewardship emphasis extends to our proactive cooperative agreements for the retirement of wells within our operating states and to the appropriate funding of the same. As we seek to continuously improve time and cost efficiencies in this important area, in 2021 we purchased our first plugging rig and established an in-house asset retirement team in West Virginia. Bringing these vertically-integrated operations in-house for this portion of our asset retirement programme has allowed us to better manage our environmental impact and the retirement methods used. Our DEC team plugged its first well in March and has shown incremental improvements in efficiencies with each well retired. For example, our in-house average realised cost to retire a well in West Virginia is ~$2 thousand less than the cost of outsourcing. Currently, our asset retirement team has the capacity to plug ~40 wells a year, which could allow us to further reduce our outsourcing.

To date in 2021, we have retired a total of 65 wells at an average cost of ~$19 thousand per well as compared to our 2020 annual average cost of ~$25 thousand per well. Since inception of our retirement agreements with the states in 2018, we have now retired approximately 300 wells at an average cost of $24 thousand per well. The 2021 retirements represent approximately 81% of our current year retirement obligation as per the agreements, and we fully expect to meet or exceed our retirement commitments as we have successfully done in prior years.

Social

As we all continue to emerge from the uncertainty and concern ushered in by the Covid-19 era, DEC has been taking advantage of rising opportunities to directly and personally engage and interact with our communities again. During the first half of the year, we participated in a variety of community outreach efforts, including the following:

• We held a company-wide Earth Day clean up programme in April where employees from Ohio to Alabama spent a day picking up trash and litter in the streets and parks within our communities to ensure they stay beautiful. After the success we saw with this inaugural event, we participated in three additional clean up days across our communities;

• For Arbor Day, and in addition to our ongoing efforts to plant at least one tree for every well we retire, we planted more trees in support of this special environmental holiday;

• We teamed up with the Buffalo Creek Watershed Association for the 17th Annual Kid's Fishing Day event where we provided children in the community with fishing rods and tackle and enjoyed teaching them how to fish in an effort to encourage active participation in outdoor activities;

• We held numerous fitness challenges for our employees to promote good health, and in one of our recent challenges we donated $25,000 to local children's charities; and

• In June, we committed to a multi-year corporate sponsorship of West Virginia University Athletics, making us the "Official Energy Partner of WVU Athletics," with our investment focused on the sponsorship of sports, student-athletes, and the youth of West Virginia through the Climbing Higher campaign as well as scholarship initiatives, internships and mentoring specifically designed for minority and female student-athletes.

As our Diversified family grows so does the impact we can have on the communities in which we live, work and play. Our employees actively seek opportunities to encourage each other in their professional and personal lives and to contribute to their local communities and charities.

Governance

As we reported in our 2020 Annual Report, our ERM programme identified Cybersecurity Risk as one of our principal risks. Unfortunately, earlier this year the US experienced, first hand, the result of that kind of risk when the Colonial Pipeline was temporarily shut down due to a cyberattack. As a result of our ERM risk identification process, we had already begun investing in efforts to mitigate cybersecurity risks, starting with hiring additional security specialists to join our Information Technology ("IT") team. Further, recent IT investments to streamline our operations and better manage our technology needs have been made with cybersecurity at the forefront of every decision. Employees are our first line of defence against potential attacks, so we actively promote secure behaviours to help mitigate this growing risk, including through robust mandatory training and e-learning sessions delivered by our digital security team.

Board composition is another Governance topic that has been top of mind for our Board. The Board is currently comprised of seven directors consisting of a Non-Executive Chairman, our CEO, our Executive Vice President and COO, and four Non-Executive Directors (three of whom are considered independent). At present, two of our seven Board members, approximately 30%, are women. As stated in our 2020 Annual Report, we have accepted the recommendations of the Hampton-Alexander Review and the Parker Review to increase female Board membership to at least 33% by our 2022 Annual General Meeting, and as a result, we have engaged an executive search firm to assist in filling a new Board seat that will further enhance our Board's diversity, experience, and knowledge base.

STRATEGIC OUTLOOK

As we step into the second half of 2021, we will look to further progress the above noted initiatives while also turning our attention to the systematic and complete integration of our recent acquisitions. While working towards a smooth transition and integration, we are also conscious of the opportunities that current market dynamics can present for continued growth. While we have successfully grown the business in periods of low commodity prices, we fully expect that emerging periods of sustained higher prices also present compelling opportunities for growth as entities seek to divest of non-core assets to optimise their portfolios and generate capital for additional drilling and development. We look forward to these opportunities as we continue to engage in our proven daily, operational activities that minimise costs and maximise production, create value through opportunistic hedging practices, and maintain a clear line of sight to cash flows that provide strong shareholder returns and drive debt reductions.

As we focus on these near-term initiatives with a view to their long-term impacts, we will continue the execution of our core strategy to:

• Acquire long-life stable assets by remaining disciplined, staying agile, maintaining leverage, continuing synergistic growth, screening new basin opportunities, and exploring unconventional asset opportunities;

• Operate our assets in a safe, efficient and responsible manner by remaining focused, maintaining a safety-centred culture, expanding ESG initiatives, driving efficiencies, promoting and expanding SAM and measuring and improving emissions;

• Generate reliable Free Cash Flow by continuing to safely retire wells, continuing vertical integration and process quality, and maintaining healthy relationships with regulators; and

• Retire assets safely and responsibly by protecting cash flow, maintaining a hedging strategy and maintaining low financial cost, low leverage and ample liquidity.

Our future is bright at Diversified, and we are excited about our recent endeavours and the magnitude of opportunities they provide. Our Central Region expansion will serve as a platform for continued growth and provide us with the opportunity for the continuation of LSE industry leading distributions to our shareholders. We are excited to host our first ever Capital Markets Day in Houston, Texas in early October, where we will highlight our opportunities in this new region and provide a deeper look into our midstream, marketing and ESG efforts. Good things are on the horizon for DEC!

RESULTS OF OPERATIONS

Please refer to the APMs section within this Interim Report for information on how these metrics are calculated and reconciled to IFRS measures.

	Six Months Ended
	30 June 2021			30 June 2020			Change		% Change
Net production
Natural gas (MMcf)	104,888			94,043			10,845		12	%
NGLs (MBbls)	1,410			1,453			(43)		(3)	%
Oil (MBbls)	242			190			52		27	%
Total production (MBoe)	19,133			17,317			1,816		10	%
Average daily production (Boepd)	105,707			95,148			10,559		11	%
% Natural gas (Boe basis)	91		%	91		%
Average realised sales price (excluding impact of derivatives settled in cash)
Natural gas (Mcf)	$	2.46		$	1.67		$	0.79	47	%
NGLs (Bbls)	24.86			4.84			20.02		414	%
Oil (Bbls)	55.88			36.33			19.55		54	%
Total (Boe)	$	16.05		$	9.86		$	6.19	63	%
Average realised sales price (including impact of derivatives settled in cash)
Natural gas (Mcf)	$	2.43		$	2.34		$	0.09	4	%
NGLs (Bbls)	10.13			16.76			(6.63)		(40)	%
Oil (Bbls)	64.38			51.87			12.51		24	%
Total (Boe)	$	14.90		$	14.69		$	0.21	1	%
Revenue (in thousands)
Natural gas	$	258,453		$	156,900		$	101,553	65	%
NGLs	35,050			7,029			28,021		399	%
Oil	13,523			6,903			6,620		96	%
Total commodity revenue	$	307,026		$	170,832		$	136,194	80	%
Midstream revenue	15,089			13,383			1,706		13	%
Other revenue	1,201			663			538		81	%
Total revenue	$	323,316		$	184,878		$	138,438	75	%
Gain (loss) on derivative settlements (in thousands)
Natural gas	$	(3,246)		$	63,233		$	(66,479)	(105)	%
NGLs	(20,761)			17,321			(38,082)		(220)	%
Oil	2,058			2,952			(894)		(30)	%
Net gain (loss) on derivative settlements	$	(21,949)		$	83,506		$	(105,455)	(126)	%
Adjusted Total Revenue	$	301,367		$	268,384		$	32,983	12	%
Per Boe Metrics
Average realised sales price
(including impact of derivatives settled in cash)	$	14.90		$	14.69		$	0.21	1	%
Other revenue	0.85			0.81			0.04		5	%
Base LOE	2.77			2.50			0.27		11	%
Midstream operating expense	1.52			1.41			0.11		8	%
Adjusted G&A	1.59			1.34			0.25		19	%
Production taxes	0.48			0.45			0.03		7	%
Transportation expense	1.48			1.35			0.13		10	%
Operating margin	$	7.91		$	8.45		$	(0.54)	(6)	%
% Operating margin	50		%	55		%
Other financial metrics (in thousands)
Adjusted Net Income	$	203,742		$	112,209		$	91,533	82	%
Operating profit (loss)	$	(305,668)		$	(30,780)		$	(274,888)	893	%
Income (loss) available to shareholders after taxation	$	(83,957)		$	18,485		$	(102,442)	(554)	%

Production, Revenue and Hedging

Total revenue in the six months ended 30 June 2021 of $323 million increased 75% from $185 million reported for the six months ended 30 June 2020, primarily due to a 63% increase in the average realised sales price and 10% higher production. Including commodity hedge settlement losses of $22 million and gains of $84 million in 2021 and 2020, respectively, Total Adjusted Revenue increased by 12% to $301 million in 2021 from $268 million in 2020.

We sold approximately 19,133 MBoe in 2021 versus approximately 17,317 MBoe in 2020 with the increase driven by the full integration of the previously acquired Carbon and EQT assets in May 2020 as well as a month and a half of uplift from the Indigo acquisition. Higher average commodity prices drove our average realised sales prices higher as reflected in the table below for the periods presented:

	Six Months Ended
	30 June 2021		30 June 2020		$ Change		% Change
Henry Hub	$	2.76	$	1.83	$	0.93	51	%
Mont Belvieu	39.98		18.65		21.33		114	%
WTI	61.96		37.01		24.95		67	%

Refer to Note 4 in the Notes to the Group Interim Financial Statements for additional information regarding acquisitions.

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) for the six months ended 30 June 2021 by reflecting the effect of changes in volume and in the underlying prices:

(In thousands)	Natural Gas		NGLs		Oil		Total
Commodity revenue for the six months ended 30 June 2020	$	156,900	$	7,029	$	6,903	$	170,832
Volume increase (decrease)	18,111		(208)		1,889		19,792
Price increase (decrease)	83,442		28,229		4,731		116,402
Net increase (decrease)	101,553		28,021		6,620		136,194
Commodity revenue for the six months ended 30 June 2021	$	258,453	$	35,050	$	13,523	$	307,026

To manage our cash flows in a volatile commodity price environment, we utilise derivative contracts which allow us to fix the sales prices at a Boe level for approximately 90% of our production to mitigate commodity risk. The tables below set forth the commodity hedge impact on commodity revenue, excluding and including cash received for commodity hedge settlements with natural gas on a per Mcfe basis and NGLs and oil on a per Bbls basis:

(In thousands, except per unit data)	Six Months Ended 30 June 2021
	Natural Gas				NGLs				Oil				Total Commodity
	Revenue		Realised $		Revenue		Realised $		Revenue		Realised $		Revenue		Realised $
Excluding hedge impact	$	258,453	$	2.46	$	35,050	$	24.86	$	13,523	$	55.88	$	307,026	$	16.05
Commodity hedge impact	(3,246)		(0.03)		(20,761)		(14.73)		2,058		8.50		(21,949)		(1.15)
Including hedge impact	$	255,207	$	2.43	$	14,289	$	10.13	$	15,581	$	64.38	$	285,077	$	14.90

(In thousands, except per unit data)	Six Months Ended 30 June 2020
	Natural Gas				NGLs				Oil				Total Commodity
	Revenue		Realised $		Revenue		Realised $		Revenue		Realised $		Revenue		Realised $
Excluding hedge impact	$	156,900	$	1.67	$	7,029	$	4.84	$	6,903	$	36.33	$	170,832	$	9.86
Commodity hedge impact	63,233		0.67		17,321		11.92		2,952		15.54		83,506		4.83
Including hedge impact	$	220,133	$	2.34	$	24,350	$	16.76	$	9,855	$	51.87	$	254,338	$	14.69

Refer to Note 13 in the Notes to the Group Interim Financial Statements for additional information regarding derivative financial instruments.

Expenses

(In thousands, except per unit data)	Six Months Ended
			Per				Per		Total Change				Per Boe Change
	30 June 2021		Boe		30 June 2020		Boe		$		%		$		%
Base LOE ^(a)	$	52,836	$	2.77	$	43,368	$	2.50	$	9,468	22	%	$	0.27	11	%
Production taxes ^(b)	9,215		0.48		7,748		0.45		1,467		19	%	0.03		7	%
Midstream operating expense ^(c)	29,172		1.52		24,380		1.41		4,792		20	%	0.11		8	%
Transportation expense ^(d)	28,332		1.48		23,455		1.35		4,877		21	%	0.13		10	%
Total operating expense	$	119,555	$	6.25	$	98,951	$	5.71	$	20,604	21	%	$	0.54	9	%
Base G&A ^(e)	29,896		1.56		22,529		1.30		7,367		33	%	0.26		20	%
Non-recurring and/or non-cash G&A ^(f)	12,437		0.65		11,567		0.67		870		8	%	(0.02)		(3)	%
Total operating and G&A expense	$	161,888	$	8.46	$	133,047	$	7.68	$	28,841	22	%	$	0.78	10	%
Depreciation, depletion and amortisation	71,843		3.75		55,837		3.22		16,006		29	%	0.53		16	%
Allowance for credit losses ^(g)	602		0.03		600		0.04		2		-	%	(0.01)		(25)	%
Total expenses	$	234,333	$	12.24	$	189,484	$	10.94	$	44,849	24	%	$	1.30	12	%

(a) Base LOE is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.

(b) Production taxes include severance and property taxes. Severance taxes are generally paid on 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.

(c) Midstream operating expenses are daily costs incurred to operate our owned midstream assets inclusive of employee and benefit expenses.

(d) Transportation expenses are daily costs incurred to third parties to gather, process and transport our natural gas, NGLs and oil.

(e) Base G&A includes payroll and benefits for our administrative and corporate staff, costs of maintaining administrative and corporate offices, costs of managing our production operations, franchise taxes, public company costs, non-cash equity issuance, fees for audit and other professional services, and legal compliance.

(f) Non-recurring and/or non-cash G&A includes costs related to acquisitions, our up-list to the Main Market of the LSE in 2020, hedge modifications, non-cash equity compensation and one-time projects.

(g) Allowance for credit losses consists of expected credit losses and a non-recurring increase in the reserve of joint interest owner receivable.

We experienced increases in per unit expense of 12%, or $1.30 per Boe, resulting from:

• Higher per Boe Base LOE that rose 11%, or $0.27 per Boe, resulting from increases in cost from the acquired Carbon, EQT and Indigo assets and an increase in fuel cost;

• Higher per Boe production taxes that rose 7%, or $0.03 per Boe, primarily attributable to an increase in severance taxes as a result of an increase in unhedged revenue due higher commodity prices;

• Higher per Boe midstream operating expense that increased 8%, or $0.11 per Boe, primarily due to an increase in costs from our Carbon midstream assets acquired in May 2020 and due to an increase in employee wages for inflationary adjustments which allows us to attract and retain top talent;

• Higher per Boe transportation expense related to increases in third-party midstream rates; and

• Higher Base G&A as a result of investments made in staff and systems to support our enlarged operation.

Partially offsetting the per Boe increases was a decrease due to:

• Lower per Boe non-recurring and/or non-cash G&A due to cost associated with acquisition and integration costs during 2021 compared to per Boe non-recurring costs incurred in 2020 associated with our transition from listing on AIM to the Premium Segment of the Main Market on the LSE as well as prior year acquisitions.

Depreciation, depletion and amortisation ("DD&A") increased due to:

• Higher depreciation expense attributable to an increase of property, plant & equipment resulting from acquisitions and maintenance capital expenditures; and

• Higher depletion expense due to a 10% increase in production attributable to an increased number of producing wells from acquisitions.

Refer to Notes 4, 10, 11 and 13 in the Notes to the Group Interim Financial Statements for additional information regarding acquisitions, natural gas and oil properties, property, plant and equipment and derivative financial instruments, respectively.

Derivative Financial Instruments

We recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods presented:

(In thousands)	Six Months Ended
(In thousands)	30 June 2021		30 June 2020		$ Change		% Change
Net gain (loss) on commodity derivatives ^(a)	$	(21,949)	$	83,506	$	(105,455)	(126)	%
Net gain (loss) on interest rate swap ^(a)	(251)		-		(251)		(100)	%
Gain (loss) on foreign currency hedge ^(a)	(1,227)		-		(1,227)		(100)	%
Total gain (loss) on settled derivative instruments	$	(23,427)	$	83,506	$	(106,933)	(128)	%
Gain (loss) on fair value adjustments of unsettled financial instruments ^(b)	(371,458)		(109,680)		(261,778)		239	%
Total gain (loss) on derivative financial instruments	$	(394,885)	$	(26,174)	$	(368,711)	1,409	%

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

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

For the six months ended 30 June 2021, the total loss on derivative financial instruments of $395 million increased by $369 million compared to a loss of $26 million in 2020. Adjusting our unsettled derivative contracts to their fair values drove a loss of $371 million in 2021, an increase of $262 million, as compared to a loss of $110 million in 2020.

While the change in fair value is significant and reflective of higher prices on the forward price curve, our derivative contracts position us to secure our dividend and structured debt repayments. Additionally, a large portion of the unsettled hedge loss relates to the time option value of our long-dated portfolio. Specifically, approximately $47 million of the $536 million net liability reflected on our balance sheet relates to the time value rather than their settlement value based on the current futures price strip.

For the six months ended 30 June 2021, the total cash loss on settled derivative instruments was $23 million, a decrease of $107 million over 2020. The loss on settled derivative instruments is reflective of higher commodity market prices than our derivative contracts with fixed sales prices.

Refer to Note 13 in the Notes to the Group Interim Financial Statements for additional information regarding derivative financial instruments.

Finance Costs

(In thousands)	Six Months Ended
(In thousands)	30 June 2021		30 June 2020		$ Change		% Change
Interest expense, net of capitalised and income amounts ^(a)	$	18,172	$	17,476	$	696	4	%
Amortisation of discount and deferred finance costs	4,304		3,809		495		13	%
Other	36		127		(91)		(72)	%
Total finance costs	$	22,512	$	21,412	$	1,100	5	%

(a) Includes payments related to borrowings and leases

For the six months ended 30 June 2021, interest payments of $18 million increased $1 million compared to $17 million in 2020, primarily due to the increase in borrowings from the ABS II Note and the Term Loan I used to fund our May 2020 acquisitions. A full six months of interest was paid on these financing arrangements in 2021. Offsetting these increases is a decrease in interest expense on our Credit Facility and the ABS I Note as these balances were paid down. As of 30 June 2021 and 2020, total borrowings were $655 million and $771 million, respectively. This decline is reflective of our amortising debt structures and the utilisation of a portion of the proceeds from the May 2021 equity raise to repay borrowings until the close of the Blackbeard transaction which occurred in July 2021. For the period ended 30 June 2021, the weighted average interest rate on borrowings was 4.77% as compared to 4.60% as of 30 June 2020. This increase resulted from a change in the mix of our financing year-over-year provided the ABS II Note and Term Loan I were in place for a full six month period in 2021.

Refer to Notes 4, 19, and 20 in the Notes to the Group Interim Financial Statements for additional information regarding acquisitions, leases and borrowings, respectively.

Taxation

The effective tax rate is calculated on the face of the Statement of Comprehensive Income by dividing the amount of recorded income tax benefit (expense) by the income (loss) before taxation as follows:

(In thousands)	Six Months Ended
(In thousands)	30 June 2021			30 June 2020			$ Change		% Change
Income (loss) before taxation	$	(343,978)		$	(59,227)		$	(284,751)	481	%
Income tax benefit (expense)	260,021			77,712			182,309		235	%
Effective tax rate	75.6		%	131.2		%

The differences between the statutory US federal income tax rate and the effective tax rates are summarised as follows:

	Six Months Ended
	30 June 2021		30 June 2020
Expected tax at statutory US federal income tax rate	21.0	%	21.0	%
State income taxes, net of federal tax benefit	5.3	%	3.8	%
Federal credits	50.3	%	108.5	%
Other, net	(1.0)	%	(2.1)	%
Effective tax rate	75.6	%	131.2	%

For the six months ended 30 June 2021, we reported a tax benefit of $260 million, a change of $182 million, compared to a benefit of $78 million in 2020 which was a result of the change in the loss before taxation and a change in the amount of tax credits utilised relative to the pre-tax loss.

For the six months ended 30 June 2021 and 2020, Income tax expense was recognised based on management's estimate of the annual effective tax rate expected for the full financial year. The estimate of the annual effective tax rate is subject to variation due to several factors, including variability in forecasted pre-tax book income or loss by jurisdiction, tax credits, and changes in tax laws. Additionally, the effective tax rate can be more or less volatile based on the amount of pre-tax income or loss. For example, the impact of tax credits on our effective tax rate is greater when our pre-tax income or loss is lower.

The resulting effective tax rates for the months ended 30 June 2021 and 2020 were 75.6% and 131.2%, respectively. The effective tax rate is primarily impacted by recognition of the federal well tax credit available to qualified producers and due to management's estimate of the annual effective tax rate expected for the full financial year as previously discussed. The federal government provides these credits to encourage companies to continue producing lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local tax revenues they generate for communities to support schools, social programmes, law enforcement and other similar public services.

Refer to Note 7 in the Notes to the Group Interim Financial Statements for additional information regarding taxation.

Operating Profit, Net Income, EPS, Adjusted Net Income, Adjusted EPS and Hedged Adjusted EBITDA

(In thousands, except per unit data)	Six Months Ended
(In thousands, except per unit data)	30 June 2021		30 June 2020		$ Change		% Change
Operating profit (loss)	$	(305,668)	$	(30,780)	$	(274,888)	893	%
Income (loss) available to shareholders after taxation	(83,957)		18,485		(102,442)		(554)	%
Adjusted Net Income	203,742		112,209		91,533		82	%
Hedged Adjusted EBITDA	151,314		146,304		5,010		3	%

Earnings (loss) per share - diluted	$	(0.11)	$	0.03	$	(0.14)	(467)	%
Adjusted EPS - diluted	0.28		0.17		0.11		65	%
Hedged Adjusted EBITDA per Share - diluted	0.20		0.22		(0.02)		(9)	%

For the six months ended 30 June 2021, we reported a net loss of $84 million and loss per share of $0.11 compared to net income of $18 million and EPS of $0.03 in 2020, a decrease of 554% and 467%, respectively. We also reported an operating loss of $306 million compared with an operating loss of $31 million for the six months ended 30 June 2021 and 2020, respectively. This year-over-year decline in net income was primarily attributable to a mark-to-market loss of $371 million, discussed above in this Strategic Review .

Excluding the mark-to-market loss as well as other non-cash and non-recurring items, we reported Adjusted Net Income of $204 million and Adjusted EPS of $0.28 per share compared to Adjusted Net Income of $112 million and Adjusted EPS of $0.17 per share in 2020, increases of 82% and 65%, respectively.

Additional adjustments for depletion, depreciation, amortisation, interest, and taxes resulted in Hedged Adjusted EBITDA of $151 million and Hedged Adjusted EBITDA per Share of $0.20 compared to $146 million and $0.22 in 2020, representing an increase of 3% and a decrease of 9%, respectively. The decline in this metric at the share level is a result of the timing of the equity issuance and realisation of earnings from the acquisitions. While the nature of this calculation considers the weighted average number of diluted shares during the period it does not consider that the May 2021 equity issuance finances both the Indigo and Blackbeard transactions. Given the timing of when the transaction closed, only a month and a half of Indigo asset earnings has been included in our results for the six months ended 30 June 2021. Blackbeard earnings will be realised and reported in the second half of 2021.

Refer to Note 8 in the Notes to the Group Interim Financial Statements for information regarding Adjusted Net Income, Adjusted EPS, and Hedged Adjusted EBITDA. Please refer to the APMs section within this Interim Report for information on how these metrics are calculated and reconciled to IFRS measures.

Liquidity and Capital Resources

Our principal sources of liquidity have historically been cash generated from operating activities. To minimise financing costs, we apply our excess cash flow to reduce borrowings on our Credit Facility. When we acquire assets to grow, we complement our Credit Facility with long-term, fixed-rate, fully-amortising debt structures that better match the long-life nature of our assets. These structures afford us lower interest rates and also provide a visible path for reducing leverage as we make scheduled principal payments. For larger acquisitions, and to ensure we maintain a leverage profile that we believe is appropriate for the type of assets we acquire, we will also raise equity proceeds through a secondary offering.

We monitor our working capital to ensure that the levels remain adequate to operate the business with excess cash primarily being utilised for the repayment of debt or shareholder distributions. In addition to working capital management, we have a disciplined approach to managing operating costs and allocating capital resources, ensuring that we are generating returns on our capital investments to support the strategic initiatives in our business operations.

(In thousands)	Six Months Ended
(In thousands)	30 June 2021		30 June 2020		$ Change		% Change
Net cash provided by operating activities	$	108,121	$	123,359	$	(15,238)	(12)	%
Net cash used in investing activities	(143,971)		(231,396)		87,425		(38)	%
Net cash provided by financing activities	38,145		113,091		(74,946)		(66)	%
Net change in cash and cash equivalents	$	2,295	$	5,054	$	(2,759)	(55)	%

Net Cash Provided by Operating Activities

For the six months ended 30 June 2021, net cash provided by operating activities of $108 million decreased $15 million, or 12%, when compared to $123 million in 2020. The reduction in net cash provided by operating activities was predominantly attributable to the following:

• An increase in Adjusted Total Revenues, which was partially offset by the increases in expense described previously. This net increase in Hedged Adjusted EBITDA was then offset by hedge modification payments that were made to restructure the acquired Indigo hedge book to take advantage of the higher price environment we are currently operating in; and

• Working capital outflows have also increased, driven by increasing accounts receivable balances. This increase in accounts receivable is a function of the increase in revenues discussed earlier. We anticipate collecting these increased accounts receivable balances over the next two months.

Production, realised prices, operating expenses, and G&A are discussed above in this Strategic Review .

Net Cash Used in Investing Activities

For the six months ended 30 June 2021, net cash used in investing activities of $144 million decreased $87 million, or 38%, from outflows of $231 million in 2020. The change in net cash used in investing activities was primarily attributable to the following:

• During the six months ended 30 June 2021, we paid purchase consideration of approximately $116 million for the Indigo acquisition. During the six months ended 30 June 2020, we paid purchase consideration of $124 million and $123 million for the Carbon and EQT acquisitions, respectively. Refer to Note 4 in the Notes to the Group Interim Financial Statements for additional information regarding acquisitions;

• Capital expenditures were $16 million for the six months ended 30 June 2021 compared to $9 million for the six months ended 30 June 2020. This increase in capex is primarily driven by our growth through acquisitions year-over-year; and

• Restricted cash decreased by $10 million year-over-year as a result of the establishment of the interest expense reserve required by our long-term financing agreements for the ABS II Note and Term Loan I in the prior year. These reserves naturally decline over time with the amortising nature of the financing structure.

Net Cash Provided by Financing Activities

For the six months ended 30 June 2021, net cash provided by financing activities of $38 million decreased $75 million, or 66%, as compared to $113 million in 2020. This change in net cash provided by financing activities was primarily attributable to the following:

• Our Credit Facility activity resulted in net repayments of $57 million in 2021 versus net repayments of $225 million in 2020, with much of the decrease attributable to a $200 million refinancing of the Credit Facility borrowings through the ABS II Note in 2020;

• Our structured debt facilities resulted in repayments of $34 million in 2021, as compared to $9 million in 2020. This is a result of the May 2020 issuance of the ABS II Note and Term Loan I. Amortising principal payments had not yet begun on these financing arrangements during the six months ended 30 June 2020;

• An increase of $132 million in proceeds from equity issuances that raised $214 million in 2021 as compared to $82 million raised in 2020. These proceeds were used on investing activities during the six months ended 30 June 2020 while the proceeds in excess of the Indigo purchase price were used to pay down the Credit Facility until Blackbeard closed in July 2021;

• An increase of $15 million in dividends paid in 2021 as compared to 2020; and

• A decrease of $16 million in the repurchase of shares in 2021 as compared to 2020.

Refer to Notes 16, 17 and 20 in the Notes to the Group Interim Financial Statements for additional information regarding share capital, dividends and borrowings, respectively.

Our borrowings consist of the following as of the reporting date:

Credit Facility

In April 2021, we reaffirmed our borrowing base on the Credit Facility at $425 million, maturing in July 2023. The Credit Facility is secured by natural gas and oil properties and had an interest rate of 2.36% as of 30 June 2021. Available borrowings under the Credit Facility were $269 million as of 30 June 2021. Currently, the secured assets under the Credit Facility (the "Restricted Group") comprise $1.7 billion of our $3.0 billion in PV-10 reserve value as of 30 June 2021, inclusive of our announced acquisitions and Oaktree's participation. The Restricted Group contributed 8,653 Mboe and $69 million in Hedged Adjusted EBITDA to our consolidated results for the period ended 30 June 2021.

Under the terms of the Term Loan I, ABS I Note, and ABS II Note financing arrangements excess cash generated from the assets secured under these financing arrangements (the "Unrestricted Group"), as described below, is available to be contributed back to the Credit Facility to repay borrowings. Cash contributed from the Unrestricted Group to the Restricted Group was $36 million for the six months ended 30 June 2021. When including the cash contributions from the Unrestricted Group, Hedged Adjusted EBITDA for the Restricted Group increases to $105 million for the six months ended 30 June 2021.

On 4 August 2021 we received commitments from certain lead lenders in our bank syndicate to expand the borrowing base on our Credit Facility from $425 million to $625 million, subject only to satisfactory documentation.

Term Loan I

In May 2020, we formed DP Bluegrass LLC ("Bluegrass"), a limited-purpose, bankruptcy-remote, wholly owned subsidiary of DEC to enter into a securitised financing agreement for $160 million, which was structured as a secured term loan. We issued the Term Loan I at a 1% discount, generating proceeds of $158 million.

The Term Loan I is secured by the our producing assets acquired from Carbon and EQT discussed in Note 4.

The Term Loan I accrues interest at a stated 6.50% annual rate and has a maturity date of May 2030. Interest and principal payments on the Term Loan I are payable on a monthly basis. During the six months ended 30 June 2021 and 2020 and the year ended 31 December 2020, we incurred $5 million, $1 million and $6 million in interest related to the Term Loan I, respectively.

ABS II Note

In April 2020, we formed Diversified ABS Phase II LLC ("ABS II"), a limited-purpose, bankruptcy-remote, wholly owned subsidiary of DEC to enter into a securitised financing agreement for $200 million. The ABS II Note is BBB rated and was issued at a 2.775% discount generating proceeds of $184 million, net of discount, capital reserve requirement, and debt issuance costs.

The ABS II Note is secured by 29.4% of certain of our producing assets.

The ABS II Note accrues interest at a stated 5.25% rate and has a maturity date of July 2037. Interest and principal payments on the ABS II Note are payable on a monthly basis. For the six months ended 30 June 2021 and 2020 and the year ended 31 December 2020, we incurred $5 million, $3 million and $8 million in interest related to the ABS II Note, respectively. In the event that ABS II has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, we are required to pay down additional principal with the remaining proceeds remaining with us.

ABS I Note

In November 2019, we formed Diversified ABS LLC ("ABS I"), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary of DEC to enter into a securitised financing agreement for $200 million which was issued at par through a BBB- rated bond. The ABS I Note is secured by 21.6% of certain of our producing assets.

Interest and principal payments on the ABS I Note are payable on a monthly basis. For the six months ended 30 June 2021 and 2020 and the year ended 31 December 2020, we incurred $4 million, $5 million and $10 million of interest related to the ABS I Note, respectively. The legal final maturity date is January 2037 with an amortising maturity of December 2029. The ABS I Note accrues interest at a stated 5.00% rate. In the event that ABS I has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, we are required to pay down additional principal with the remaining proceeds remaining with us.

PRINCIPAL RISKS AND UNCERTAINTIES

The Directors have reconsidered our principal risks and uncertainties and determined that the principal risks and uncertainties published in the Annual Report for the year ended 31 December 2020 remain appropriate. The risks and associated risk management processes, can be found in our 2020 Annual Report, which is available in the Investor Resources section of our website at www.d iv.energy .

The risks referred to and which could have a material impact on our performance for the remainder of the current financial year relate to:

• Corporate Strategy and Acquisition Risk;

• Cybersecurity Risk;

• Health and Safety Risk;

• Regulatory and Political Risk;

• Climate and ESG Risk;

• Commodity Price Volatility; and

• Financial Strength and Flexibility Risk.

•

Going Concern

As described in Note 2 in the Notes to the Group Interim Financial Statements, the Directors have formed a judgement, at the time of approving the Interim Financial Statements, that there is a reasonable expectation that we are sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of the Interim Financial Statements. In making this judgement, they have considered the impacts of current and severe, but plausible, consequences arising from our identified principal risks and uncertainties to our activities. For this reason, the Directors continue to adopt the going concern basis in preparing the Interim Financial Statements.

Responsibility Statement

Each of the Directors confirm that, to the best of their knowledge:

• The Interim Financial Statements have been prepared in accordance with IAS 34 "Interim Financial Reporting," as contained in UK-adopted IFRS (UK-adopted international accounting standards);

• This half-yearly financial report includes a fair review of the information required by:

◦ DTR 4.2.7R of the Disclosure and Transparency Rules, being an indication of important events that have occurred during the first six months of the financial year and their impact on the set of financial statements; and a description of the principal risks and uncertainties for the remaining six months of the financial year; and

◦ DTR 4.2.8R of the Disclosure and Transparency Rules, being related parties' transactions that have taken place in the first six months of the current financial year and that have materially affected our financial position or performance during that period; and any changes in the related parties' transactions described in the last annual report that could do so.

◦

CONCLUSION

We have enjoyed an eventful and successful 2021 so far, and look forward to continued progress as we focus our attention towards the second half of 2021. I would like to thank the growing Diversified family for its commitment to safe and efficient operations, the Board for its diligent oversight and guidance, and our shareholders and stakeholders who entrust to us the capital to fuel our growth. I look forward to reporting back to you with our full-year results.

David E. Johnson

Chairman of the Board

5 August 2021

INTERIM FINANCIAL STATEMENTS

	Page
Independent Review Report to Diversified Energy Company Plc	22
Consolidated Statement of Comprehensive Income	23
Consolidated Statement of Financial Position	24
Consolidated Statement of Changes in Equity	26
Consolidated Statement of Cash Flows	27
Notes to the Interim Financial Statements	28

Independent review report to Diversified Energy Company PLC

Report on the consolidated interim financial statements

Our conclusion

We have reviewed Diversified Energy Company PLC's consolidated interim financial statements (the "interim financial statements") in the Interim Report of Diversified Energy Company PLC for the 6 month period ended 30 June 2021 (the "period").

Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with UK adopted International Accounting Standard 34, 'Interim Financial Reporting' and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

What we have reviewed

The interim financial statements comprise:

• the Consolidated Statement of Financial Position as at 30 June 2021;

• the Consolidated Statement of Comprehensive Income for the period then ended;

• the Consolidated Statement of Cash Flows for the period then ended;

• the Consolidated Statement of Changes in Equity for the period then ended; and

• the explanatory notes to the interim financial statements.

The interim financial statements included in the Interim Report of Diversified Energy Company PLC have been prepared in accordance with UK adopted International Accounting Standard 34, 'Interim Financial Reporting' and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the Directors

The Interim Report, including the interim financial statements, is the responsibility of, and has been approved by the Directors. The Directors are responsible for preparing the Interim Report in accordance with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

Our responsibility is to express a conclusion on the interim financial statements in the Interim Report based on our review. This report, including the conclusion, has been prepared for and only for the Company for the purpose of complying with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

What a review of interim financial statements involves

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures.

A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and, consequently, does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

We have read the other information contained in the Interim Report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants

London

5 August 2021

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Amounts in thousands, except per share and per unit data)

		Unaudited				Audited
		Six Months Ended				Year Ended
	Notes	30 June 2021		30 June 2020		31 December 2020
Revenue	5	$	323,316	$	184,878	$	408,693
Operating expense	6	(119,555)		(98,951)		(203,963)
Depreciation, depletion and amortisation	6	(71,843)		(55,837)		(117,290)
Gross profit		$	131,918	$	30,090	$	87,440
General and administrative expense	6	(42,333)		(34,096)		(77,234)
Allowance for expected credit losses	14	(602)		(600)		(8,490)
Gain (loss) on natural gas and oil programme and equipment	10,11	234		-		(2,059)
Gain (loss) on derivative financial instruments	13	(394,885)		(26,174)		(94,397)
Gain on bargain purchase	4	-		-		17,172
Operating profit (loss)		$	(305,668)	$	(30,780)	$	(77,568)
Finance costs	20	(22,512)		(21,412)		(43,327)
Accretion of asset retirement obligation	18	(10,216)		(7,395)		(15,424)
Other income (expense)	23	(5,582)		360		(421)
Income (loss) before taxation		$	(343,978)	$	(59,227)	$	(136,740)
Income tax benefit (expense)	7	260,021		77,712		113,266
Income (loss) available to shareholders after taxation		$	(83,957)	$	18,485	$	(23,474)
Other comprehensive income (loss)		51		(28)		(28)
Total comprehensive income (loss) for the year		$	(83,906)	$	18,457	$	(23,502)

Earnings (loss) per share - basic	9	$	(0.11)	$	0.03	$	(0.03)
Earnings (loss) per share - diluted	9	$	(0.11)	$	0.03	$	(0.03)

Weighted average shares outstanding - basic	9	736,559		662,804		685,170
Weighted average shares outstanding - diluted	9	740,682		667,293		688,348

The notes are an integral part of the Interim Financial Statements.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(Amounts in thousands, except per share and per unit data)

		Unaudited		Audited
	Notes	30 June 2021		31 December 2020
ASSETS
Non-current assets:
Natural gas and oil properties	10	$	2,009,270	$	1,755,085
Property, plant and equipment	11	386,129		382,103
Intangible assets	12	16,310		19,213
Restricted cash		18,736		20,100
Derivative financial instruments	13	139		717
Deferred tax asset	7	265,901		14,777
Other non-current assets	15	16,249		4,213
Total non-current assets		$	2,712,734	$	2,196,208
Current assets:
Trade receivables, net	14	$	85,772	$	66,991
Cash and cash equivalents		3,674		1,379
Restricted cash		313		250
Derivative financial instruments	13	-		17,858
Other current assets	15	11,101		7,996
Total current assets		$	100,860	$	94,474
Total assets		$	2,813,594	$	2,290,682
EQUITY AND LIABILITIES
Shareholders' equity:
Share capital	16	$	11,568	$	9,520
Share premium	16	1,052,959		841,159
Merger reserve		(478)		(478)
Capital redemption reserve		592		592
Share-based payment reserve		10,524		8,683
Retained earnings (accumulated deficit)		(120,854)		27,182
Total equity		$	954,311	$	886,658
Non-current liabilities:
Asset retirement obligations	18	$	510,775	$	344,242
Leases	19	21,093		13,865
Borrowings	20	565,401		652,281
Deferred tax liability	7	-		15,746
Derivative financial instruments	13	321,969		168,524
Other non-current liabilities	22	9,240		12,860
Total non-current liabilities		$	1,428,478	$	1,207,518
Current liabilities:
Trade and other payables	21	$	20,015	$	19,366
Leases	19	6,087		5,013
Borrowings	20	64,919		64,959
Derivative financial instruments	13	213,886		15,858
Other current liabilities	22	125,898		91,310
Total current liabilities		$	430,805	$	196,506
Total liabilities		$	1,859,283	$	1,404,024
Total equity and liabilities		$	2,813,594	$	2,290,682

The notes are an integral part of the Interim Financial Statements.

The Interim Financial Statements were approved and authorised for issue by the Board on 5 August 2021 and was signed on its behalf by:

David E. Johnson

Chairman of the Board

5 August 2021

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Amounts in thousands, except per share and per unit data)

	Notes	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings (Accumulated Deficit)		Total Equity
Balance at 31 December 2020		$	9,520	$	841,159	$	(478)	$	592	$	8,683	$	27,182	$	886,658
Income (loss) after taxation		$	-	$	-	$	-	$	-	$	-	$	(83,957)	$	(83,957)
Other comprehensive income (loss)		-		-		-		-		-		51		51
Total comprehensive income (loss)		$	-	$	-	$	-	$	-	$	-	$	(83,906)	$	(83,906)
Issuance of share capital	16	$	2,044	$	211,800	$	-	$	-	$	-	$	-	$	213,844
Equity compensation		4		-		-		-		3,270		(1,859)		1,415
Repurchase of shares	16	-		-		-		-		-		-		-
Dividends	17	-		-		-		-		-		(62,271)		(62,271)
Cancellation of warrants	16	-		-		-		-		(1,429)		-		(1,429)
Transactions with shareholders		$	2,048	$	211,800	$	-	$	-	$	1,841	$	(64,130)	$	151,559
Balance at 30 June 2021		$	11,568	$	1,052,959	$	(478)	$	592	$	10,524	$	(120,854)	$	954,311

	Notes	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings (Accumulated Deficit)		Total Equity
Balance at 31 December 2019		$	8,800	$	760,543	$	(478)	$	518	$	3,907	$	164,845	$	938,135
Income (loss) after taxation		$	-	$	-	$	-	$	-	$	-	$	18,485	$	18,485
Other comprehensive income (loss)		-		-		-		-		-		(28)		(28)
Total comprehensive income (loss)		$	-	$	-	$	-	$	-	$	-	$	18,457	$	18,457
Issuance of share capital	16	$	790	$	80,804	$	-	$	-	$	-	$	-	$	81,594
Equity compensation		-		-		-		-		1,506		-		1,506
Repurchase of shares	16	(74)		-		-		74		-		(15,634)		(15,634)
Dividends	17	-		-		-		-		-		(47,246)		(47,246)
Transactions with shareholders		$	716	$	80,804	$	-	$	74	$	1,506	$	(62,880)	$	20,220
Balance at 30 June 2020		$	9,516	$	841,347	$	(478)	$	592	$	5,413	$	120,422	$	976,812

	Notes	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings (Accumulated Deficit)		Total Equity
Balance at 31 December 2019		$	8,800	$	760,543	$	(478)	$	518	$	3,907	$	164,845	$	938,135
Income (loss) after taxation		$	-	$	-	$	-	$	-	$	-	$	(23,474)	$	(23,474)
Other comprehensive income (loss)		-		-		-		-		-		(28)		(28)
Total comprehensive income (loss)		$	-	$	-	$	-	$	-	$	-	$	(23,502)	$	(23,502)
Issuance of share capital	16	$	791	$	80,616	$	-	$	-	$	-	$	-	$	81,407
Equity compensation		3		-		-		-		4,776		-		4,779
Repurchase of shares	16	(74)		-		-		74		-		(15,634)		(15,634)
Dividends	17	-		-		-		-		-		(98,527)		(98,527)
Transactions with shareholders		$	720	$	80,616	$	-	$	74	$	4,776	$	(114,161)	$	(27,975)
Balance at 31 December 2020		$	9,520	$	841,159	$	(478)	$	592	$	8,683	$	27,182	$	886,658

The notes are an integral part of the Interim Financial Statements.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands, except per share and per unit data)

		Unaudited				Audited
		Six Months Ended				Year Ended
	Notes	30 June 2021		30 June 2020		31 December 2020
Cash flows from operating activities:
Income (loss) after taxation		$	(83,957)	$	18,485	$	(23,474)
Cash flows from operations reconciliation:
Depreciation, depletion and amortisation	6	71,843		55,837		117,290
Accretion of asset retirement obligations	18	10,216		7,395		15,424
Income tax (benefit) expense	7	(260,021)		(77,712)		(113,266)
(Gain) loss on fair value adjustments of unsettled financial instruments	13	371,458		109,680		238,795
Plugging costs of asset retirement obligations	18	(1,180)		(1,201)		(2,442)
(Gain) loss on natural gas and oil programme and equipment	10,11	(234)		377		1,356
(Gain) on bargain purchase	4	-		-		(17,172)
Finance costs	20	22,512		21,412		43,327
Revaluation of contingent consideration	4	5,597		-		567
Hedge modifications	13	(6,797)		-		(7,723)
Non-cash equity compensation	6	3,588		1,506		5,007
Working capital adjustments:
Change in trade receivables	14	(18,881)		6,280		2,390
Change in other current assets	15	(3,105)		(1,253)		1,958
Change in other assets	15	204		(6,706)		(1,173)
Change in trade and other payables	21	(270)		(3,897)		(4,772)
Change in other current and non-current liabilities	22	4,755		(6,714)		(8,532)
Cash generated from operations		$	115,728	$	123,489	$	247,560
Cash paid for income taxes		(7,607)		(130)		(5,850)
Net cash provided by operating activities		$	108,121	$	123,359	$	241,710
Cash flows from investing activities:
Consideration for Business Acquisitions, net of cash acquired	4	$	-	$	(98,121)	$	(100,138)
Consideration for Acquisition of Assets	4	(128,715)		(112,347)		(122,953)
Expenditures on natural gas and oil properties and equipment	10,11	(16,458)		(8,875)		(21,947)
(Increase) decrease in restricted cash		1,301		(9,153)		(12,637)
Proceeds on disposals of natural gas and oil properties and equipment	10,11	722		-		3,712
Other acquired intangibles	12	-		(2,900)		(2,900)
Contingent consideration payments	4	(821)		-		(893)
Net cash used in investing activities		$	(143,971)	$	(231,396)	$	(257,756)
Cash flows from financing activities:
Repayment of borrowings	20	$	(416,521)	$	(456,502)	$	(705,314)
Proceeds from borrowings	20	325,500		575,350		799,650
Cash paid for interest	20	(18,217)		(17,683)		(34,335)
Cost incurred to secure financing	20	(204)		(5,780)		(7,799)
Proceeds from equity issuance, net	16	213,844		81,594		81,407
Principal element of lease payments	19	(2,557)		(1,008)		(3,684)
Cancellation of warrants	16	(1,429)		-		-
Dividends to shareholders	17	(62,271)		(47,246)		(98,527)
Repurchase of shares	16	-		(15,634)		(15,634)
Net cash provided by financing activities		$	38,145	$	113,091	$	15,764
Net change in cash and cash equivalents		$	2,295	$	5,054	$	(282)
Cash and cash equivalents, beginning of period		1,379		1,661		1,661
Cash and cash equivalents, end of period		$	3,674	$	6,715	$	1,379

The notes are an integral part of the Interim Financial Statements.

NOTES TO THE INTERIM FINANCIAL STATEMENTS

(Amounts in thousands, except per share and per unit data)

INDEX TO THE NOTES TO THE INTERIM FINANCIAL STATEMENTS

	Page
Note 1 - General Information	28
Note 2 - Basis of Preparation	29
Note 3 - Significant Accounting Policies	31
Note 4 - Acquisitions	32
Note 5 - Revenue	33
Note 6 - Expenses by Nature	34
Note 7 - Taxation	35
Note 8 - Adjusted Net Income and Hedged Adjusted EBITDA	36
Note 9 - Earnings (Loss) Per Share	38
Note 10 - Natural Gas and Oil Properties	38
Note 11 - Property, Plant and Equipment	39
Note 12 - Intangible Assets	40
Note 13 - Derivative Financial Instruments	40
Note 14 - Trade and Other Receivables	44
Note 15 - Other Assets	45
Note 16 - Share Capital	45
Note 17 - Dividends	46
Note 18 - Asset Retirement Obligations	46
Note 19 - Leases	48
Note 20 - Borrowings	49
Note 21 - Trade and Other Payables	51
Note 22 - Other Liabilities	52
Note 23 - Fair Value and Financial Instruments	52
Note 24 - Contingencies	54
Note 25 - Related Party Transactions	54
Note 26 - Subsequent Events	54

NOTE 1 - GENERAL INFORMATION

Diversified Energy Company PLC (the "Parent"), formerly Diversified Gas & Oil PLC, and its wholly owned subsidiaries (the "Group") is an independent energy company engaged in the production, marketing and transportation of primarily natural gas related to its synergistic US onshore upstream and midstream assets. The Group's assets are located within the Appalachian Basin of the US and more recently have expanded into the Central Region consisting of the Cotton Valley/Haynesville area and Barnett Shale located in the states of Louisiana, Texas, Oklahoma and Arkansas. The Group is domiciled in the UK and headquartered in Birmingham, Alabama, US, with field offices located in the states of Pennsylvania, Ohio, West Virginia, Kentucky, Virginia, Tennessee, Texas and Louisiana.

The Parent was incorporated on 31 July 2014 in England and Wales as a public limited company under company number 09156132. The Group's registered office is located at 4th floor Reading Bridge House, George Street, Reading, Berkshire, RG1 8LS, UK.

In February 2017, the Group's shares were admitted to trading on AIM under the ticker "DGOC." In May 2020, the Group's shares were admitted to trading on the LSE's Main Market for listed securities. The shares trading on AIM were cancelled concurrent to their admittance on the LSE. With the change in corporate name in 2021, the Group's shares listed on the LSE began trading on 7 May 2021 as Diversified Energy Company PLC under the new ticker "DEC".

NOTE 2 - BASIS OF PREPARATION

Basis of Preparation

The Group's interim consolidated financial statements (the "Interim Financial Statements") have been prepared on the basis of the policies set out in the 2020 annual financial statements and in accordance with UK adopted IAS 34 and the Disclosure Guidance and Transparency Rules sourcebook of the UK's Financial Conduct Authority. The consolidated financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2020, which have been prepared in accordance with IFRS in conformity with the requirements of the Companies Act 2006 and IFRS adopted pursuant to Regulation (EC) No 1606/2002 as it applies to the European Union. In respect of accounting standards applicable to the Group in the current period, there is no difference between IFRS in conformity with the Companies Act 2006, the UK-adopted IFRS and IASB-adopted IFRS. For the year to 31 December 2021 the annual financial statements will be prepared in accordance with IFRS as adopted by the UK Endorsement Board. This change in basis of preparation is required by UK company law for the purposes of financial reporting as a result of the UK's exit from the EU on 31 January 2020 and the cessation of the transition period on 31 December 2020. This change does not constitute a change in accounting policy but rather a change in framework which is required to ground the use of IFRS in company law.

The Group Interim Financial Statements are unaudited and do not represent statutory accounts within the meaning of section 434 of the Companies Act 2006. The financial information for the year ended 31 December 2020 is based on the statutory accounts for the year ended 31 December 2020. Those accounts, upon which the auditors issued an unqualified opinion, have been delivered to the Registrar of Companies and did not contain statements under section 498(2) or (3) of the Companies Act.

Unless otherwise stated, the Interim Financial Statements are presented in US Dollars, which is the Group's subsidiaries' functional currency and the currency of the primary economic environment in which the Group operates, and all values are rounded to the nearest thousand dollars except per share and per unit amounts and where otherwise indicated.

Transactions in foreign currencies are translated into US Dollars at the rate of exchange on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the exchange ruling at the date of the Consolidated Statement of Financial Position. Where the Group has a different functional currency, its results and financial position are translated into the presentation currency as follows:

• Assets and liabilities for each Consolidated Statement of Financial Position presented are translated at the closing rate at the date of that Consolidated Statement of Financial Position;

• Income and expenses in the Consolidated Statement of Comprehensive Income are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and

• All resulting exchange differences are reflected within other comprehensive income in the Consolidated Statement of Comprehensive Income.

The Interim Financial Statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets and liabilities (including derivative instruments) held at fair value through profit and loss or through other comprehensive income.

Segment Reporting

The Group is an independent owner and operator of producing natural gas and oil wells with properties located in the states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, Pennsylvania, Texas and Louisiana. The Group's strategy is to acquire long-life producing assets, efficiently operate those assets to generate Free Cash Flow for shareholders and then to retire assets safely and responsibly at the end of their useful life. The Group's assets consist of approximately 69,000 geographically concentrated wells and approximately 17,000 miles of natural gas gathering pipelines and a network of compression and processing facilities which are complementary to the Group's assets. The Director's acquire and manage these assets in a complementary fashion to vertically integrate and improve margins rather than as separate options. Accordingly when determining operating segments under IFRS 8 the Group has identified one reportable segment that produces and transports natural gas, NGLs and oil in the Appalachian Basin of the US.

Going Concern

The Interim Financial Statements have been prepared on the going concern basis, which contemplates the continuity of normal business activity and the realisation of assets and the settlement of liabilities in the normal course of business. The Directors have reviewed the Group's overall position and outlook and are of the opinion that the Group is sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of this Interim Report.

The Directors closely monitor and carefully manage the Group's liquidity risk. Our financial outlook is assessed primarily through the annual business planning process, however it is also carefully monitored on a monthly basis. This process includes regular Board discussions, led by the Senior Leadership, at which the current performance of and outlook for the Group are assessed. The outputs from the business planning process include a set of key performance objectives, an assessment of the Group's primary risks, the anticipated operational outlook and a set of financial forecasts that consider the sources of funding available to the Group (the "Base Plan").

The Base Plan incorporates key assumptions which underpin the business planning process. These assumptions are as follows:

• Projected operating cash flows are calculated using a production profile which is consistent with current operating results and decline rates;

• Assumes commodity prices are in line with the current forward curve which considers basis differentials;

• Operating cost levels stay consistent with historical trends;

• The financial impact of our current hedging contracts in place, being approximately 90%, 67%, and 33% of total production volumes hedged for the years ending 31 December 2021, 2022 and 2023 respectively; and

• The scenario also includes the scheduled principal and interest payments on our current debt arrangements and the funding of a dividend utilising approximately 40% of Free Cash Flow.

The Directors and Senior Leadership also consider further scenarios around the Base Plan that primarily reflect a more severe, but plausible, downside impact of the principal risks, both individually and in the aggregate, as well as the additional capital requirements that downside scenarios could place on us.

Scenario 1: A sharp and sustained decline in pricing resulting in a 10% reduction to net realised prices.

Scenario 2: A operational stoppage or regulatory event occurs which results in reduced production by approximately 5%.

Scenario 3: A market or regulatory event triggers an increase in operating and midstream expenses by approximately 5%.

Under these downside sensitivity scenarios, the Group remains cash flow positive. The Group meets its working capital requirements, which presently primarily consist of derivative liabilities that when settled will be funded utilising the higher commodity revenues from which the derivative liability was derived. The Group will also continue to meet the covenant requirements under its Credit Facility as well as its other existing borrowing instruments, and continue to return cash flows to shareholders.

The Directors and Senior Leadership consider the impact that these principal risks could, in certain circumstances, have on the Group's prospects within the assessment period, and accordingly appraise the opportunities to actively mitigate the risk of these severe, but plausible, downside scenarios. In addition to its modelled downside going concern scenarios, the Board has reverse stress tested the model to determine the extent of downturn which would result in a breach of covenants. Assuming similar levels of cash conversion as seen in 2020, a decline in production volume and pricing, well in excess of that historically experienced by the Group, would need to persist throughout the going concern period for a covenant breach to occur, which is considered very unlikely. This stress test also does not incorporate certain mitigating actions or cash preservation responses, which the Group would implement in the event of a severe and extended revenue decline.

In addition to the scenarios above the Directors also considered the risk of a temporary shutdown resulting from the Covid-19 pandemic. Notwithstanding the modelling of this scenario, the Group is considered an essential service as the Group falls under the US Department of Homeland Security's definition of essential criteria infrastructure workers as defined on 19 March 2020. As a result of the announcement, the Group's employees are exempt from any lockdown in the US. Further the Group has not experienced any shutdown of this nature to date and the Group's business model naturally lends itself to a socially distant operating environment provided that the majority of our employees are most commonly working alone or in small teams in remote areas when servicing wells.

The Directors have reviewed the Group's overall position and outlook and are of the opinion that the Group is sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of the Interim Financial Statements.

Prior Period Reclassifications

The Group has reclassified certain amounts in its prior year Consolidated Statement of Comprehensive Income and Consolidated Statement of Cash Flows to conform to its current period presentation. These changes in classification do not affect total comprehensive income previously reported in the Consolidated Statement of Comprehensive Income or the Consolidated Statement of Cash Flows.

Reclassifications in the Consolidated Statement of Comprehensive Income. During the six months ended 30 June 2020, the Group reclassified $600 related to recurring credit losses from "General and administrative expense" to "Allowance for expected credit losses".

Reclassifications in the Consolidated Statement of Cash Flows. During the six months ended 30 June 2020, the Group reclassified $130 from "Change in other current and non-current liabilities" to "Cash paid for income taxes" and reclassified $2,900 related to investments made in our marketing and operations groups from "Expenditures on natural and oil properties and equipment" to "Other acquired intangibles". During the year ended 31 December 2020, the Group reclassified $893 in "Contingent consideration payments" from "Cash flows from financing activities" to "Cash flows from investing activities".

Basis of Consolidation

The Interim Financial Statements for the six months ended 30 June 2021 reflect the following corporate structure of the Group:

The Group, and its 100% wholly owned subsidiary:

• Diversified Energy Company PLC ("DEC'') as well as its wholly owned subsidiaries

• Diversified Gas & Oil Corporation

◦ Diversified Production, LLC

▪ Diversified ABS Holdings LLC

- Diversified ABS LLC

▪ Diversified ABS Phase II Holdings LLC

- Diversified ABS Phase II LLC

▪ DP Bluegrass Holdings LLC

- DP Bluegrass LLC

◦ Diversified Midstream LLC

▪ Cranberry Pipeline Corporation

▪ Coalfield Pipeline Company

◦ Diversified Energy Marketing LLC

◦ DGOC Holdings LLC

▪ DGOC Holdings Sub III LLC

▪

NOTE 3 - SIGNIFICANT ACCOUNTING POLICIES

The preparation of the Interim Financial Statements in compliance with IFRS requires management to make estimates and exercise judgment in applying the Group's accounting policies. In preparing the Interim Financial Statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the Group Financial Statements for the year ended 31 December 2020, with the exception of taxation which has been described in Note 7.

New Standards and Interpretations

Certain new accounting standards and interpretations have been published that are not mandatory for 30 June 2021 reporting periods and have not been early adopted by the Group. None of these new standards or interpretations are expected to have a material impact on the consolidated financial statements of the Group.

NOTE 4 - ACQUISITIONS

The assets acquired in all acquisitions include the necessary permits, rights to production, royalties, assignments, contracts and agreements that support the production from wells and operations of pipelines. The Group determines the accounting treatment of acquisitions using IFRS 3.

As part of the Group's corporate strategy it actively seeks to acquire assets complementary to its existing asset base when the assets meet the acquisition criteria stated in the Acquire Long-Life Stable Assets pillar of the corporate strategy discussed in the Strategy section of the Strategic Report within the Group's 2020 Annual Report.

2021 Acquisitions

Indigo Minerals LLC ("Indigo") Asset Acquisition

On 19 May 2021, the Group acquired 780 proved developed wells and related gathering infrastructure in the Central Region from Indigo. Given the concentration of assets this transaction was considered an acquisition of assets rather than a business combination. When making this determination management performed an asset concentration test considering the fair value of the acquired assets. The fair value of natural gas and oil properties was determined using an income approach while the fair value of the other acquired assets was determined under a market approach. The Group initially paid purchase consideration of $115,758, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were $473 and have been capitalised to natural gas and oil properties. The Group funded the purchase with proceeds from the May 2021 equity placement and a draw on the Credit Facility, discussed in Notes 16 and 20, respectively.

In the period from its acquisition to 30 June 2021 the acquisition of Indigo increased the Group's natural gas production by 3,305 MMcf. The Group is still finalising the valuation of the recently acquired assets. The provisional fair value of the assets and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	115,758
Total consideration	$	115,758

Net assets acquired
Natural gas and oil properties	$	135,341
Natural gas and oil properties (asset retirement obligation, asset portion)	33,695
Property, plant and equipment ^(a)	6,545
Other non-current assets	575
Derivative financial instruments, net	(5,248)
Leases, non-current	(6,445)
Asset retirement obligation, liability portion	(33,695)
Other current liabilities	(15,010)
Net assets acquired	$	115,758

(a) Includes $6,445 in right of use assets associated with the acquired leases.

Subsequent Events

Blackbeard Operating LLC ("Blackbeard") Acquisition

On 20 May 2021 the Group announced it entered a conditional agreement to acquire certain upstream assets and related infrastructure from Blackbeard. In connection with entering the conditional agreement the Group paid $13,502 as a deposit. The transaction subsequently closed on 5 July 2021 for a total purchase consideration of $166,000, inclusive of the initial deposit and exclusive of customary purchase price adjustments. The transaction adds 820 proved developed wells and related gathering infrastructure to the Group's Central Region and was funded with proceeds from the May 2021 equity placement and a draw on the Credit Facility, discussed in Notes 16 and 20, respectively.

Tanos Energy Holdings III, LLC ("Tanos") Acquisition

On 5 July 2021, the Group announced a conditional agreement to acquire certain upstream assets from Tanos, in conjunction with Oaktree, via the previously disclosed participation agreement between the two parties for a gross purchase price of $308,000. The Group and Oaktree will each fund 50% of the net purchase price in exchange for proportionate working interests of 51.25% and 48.75%, respectively, in the acquired assets. The Group's larger share reflects the up-front promote it will receive from Oaktree (2.5% of Oaktree's investment) and its working interest will further increase to 60% once Oaktree achieves a 10% unlevered internal rate of return based on its investment in the assets. The Group will serve as the sole operator of the assets.

Indigo Minerals LLC Divestiture

On 5 July 2021, the Group announced that given the contiguous nature of the Tanos and Indigo assets, Oaktree will also participate in the Indigo transaction, aligning both parties as working interest partners in the Cotton Valley/Haynesville region. Under the same participation terms detailed above, Oaktree will acquire from Diversified a 48.75% working interest in the Cotton Valley upstream assets and related infrastructure for $58,000 (or 50% of the Group's net purchase price for the Indigo assets). Diversified will use the proceeds to reduce outstanding balances on the Credit Facility, discussed in Note 20.

2020 Acquisitions

Carbon Energy Corporation ("Carbon") Business Combination

On 26 May 2020, the Group acquired approximately 6,100 conventional wells in the states of Kentucky, West Virginia and Tennessee from Carbon. When evaluating the transaction, the Group determined it had acquired an identifiable set of inputs, processes and outputs and concluded the transaction was a business combination. The Group initially paid purchase consideration of $98,120, excluding customary purchase price adjustments. Subsequent to the initial closing price the companies settled on a final closing statement and the Group paid an additional $3,370 in cash consideration for a total cash consideration of $101,490. Transaction costs associated with the acquisition were $1,118. The Group funded the cash consideration for the purchase with proceeds from the $160,000 Term Loan I, discussed in Note 20.

Carbon may earn additional contingent consideration of up to $15,000 in the aggregate. The contingent consideration will be calculated based on fixed volumes and the average settled natural gas pricing for 2020, 2021, and 2022 as compared to established benchmark pricing. Any payments due will be paid yearly by 5 January of each of 2021, 2022 and 2023 based on the contingent consideration calculation for the respective calendar years. Based on forward NYMEX natural gas prices the fair value of the contingent consideration as at the acquisition date was $5,463. As of 30 June 2021 the fair value of the contingent consideration was $11,626. No contingent consideration payment have been made to date.

EQT Corporation ("EQT") Asset Acquisition

On 21 May 2020, the Group acquired 889 proved developed wells and related gathering infrastructure in the states of Pennsylvania and West Virginia from EQT. Given the concentration of assets this transaction was considered an acquisition of assets rather than a business combination. The Group initially paid purchase consideration of $111,587, excluding customary purchase price adjustments. Subsequent to the initial closing price the companies settled on a final closing statement and the Group paid an additional $3,215 in cash consideration for a total cash consideration of $114,802. Transaction costs associated with the acquisition were $1,069 and have been capitalised to natural gas and oil properties. The Group funded the purchase with proceeds from the $160,000 Term Loan I and a short-term draw from the Credit Facility, both discussed in Note 20.

EQT may earn additional contingent consideration of up to $20,000 in the aggregate. The contingent consideration will be calculated based on the three-month average of the NYMEX Henry Hub natural gas settlement price relative to stated floor and target price thresholds beginning on 31 August 2020 and ending on 30 November 2022. Based on forward NYMEX natural gas prices the fair value of the contingent consideration as at the acquisition date was $7,082. As of 30 June 2021 the fair value of the contingent consideration was $14,379. The Group has made contingent consideration payments of $560 during six months ended 30 June 2021.

Other Asset Acquisitions of Natural Gas Properties

In December 2020, the Group acquired five gross unconventional Utica Shale horizontal wells in the state of Ohio. The Group paid purchase consideration of $7,083, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were insignificant. The Group funded the cash consideration for the purchase with a draw on its Credit Facility. The Group is still working to finalise the fair value estimates associated with this acquisition.

NOTE 5 - REVENUE

The Group extracts and sells natural gas, NGLs and oil to various customers in addition to operating a majority of these natural gas and oil wells for customers and other working interest owners. In addition, the Group provides gathering and transportation services to third parties. All revenue was generated in the US. The following table reconciles the Group's revenue for the periods presented:

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Natural gas	$	258,453	$	156,900	$	343,425
NGLs	35,050		7,029		23,173
Oil	13,523		6,903		15,064
Total commodity revenue	$	307,026	$	170,832	$	381,662
Midstream	15,089		13,383		25,389
Other	1,201		663		1,642
Total revenue	$	323,316	$	184,878	$	408,693

A significant portion of the Group's trade receivables represent receivables related to either sales of natural gas, NGLs and oil or operational services, all of which are uncollateralised, and are collected within 30 - 60 days.

During the six months ended 30 June 2021, two customers individually comprised more than 10% of total revenues, representing 22% of consolidated revenues, while during the six months ended 30 June 2020, three customers individually comprised more than 10% of total revenues, representing 36% of consolidated revenues.

NOTE 6 - EXPENSES BY NATURE

The following table provides a detail of the Group's expenses for the periods presented:

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Base LOE ^(a)	$	52,836	$	43,368	$	92,288
Production taxes ^(b)	9,215		7,748		13,705
Midstream operating expense ^(c)	29,172		24,380		52,815
Transportation expense ^(d)	28,332		23,455		45,155
Total operating expense ^(e)	$	119,555	$	98,951	$	203,963
Depreciation and amortisation	$	21,197	$	14,601	$	33,673
Depletion	50,646		41,236		83,617
Total depreciation, depletion and amortisation	$	71,843	$	55,837	$	117,290
Employees and benefits (administrative)	$	17,985	$	13,281	$	28,843
Other administrative ^(f)	6,687		4,466		8,820
Professional fees ^(g)	5,015		4,391		8,688
Rent	209		391		830
Base G&A	$	29,896	$	22,529	$	47,181
Non-recurring costs associated with acquisitions ^(h)	$	6,221	$	1,406	$	10,465
Other non-recurring costs ⁽ⁱ⁾	2,628		8,655		14,581
Non-cash equity compensation ^(j)	3,588		1,506		5,007
Non-recurring and/or non-cash G&A	$	12,437	$	11,567	$	30,053
Total G&A	$	42,333	$	34,096	$	77,234
Allowance for joint interest owner receivables	$	-	$	-	$	6,931
Recurring allowance for credit losses	602		600		1,559
Total allowance for credit losses ^(k)	$	602	$	600	$	8,490
Total expense	$	234,333	$	189,484	$	406,977
Aggregate remuneration (including Directors):
Wages and salaries	$	32,803	$	33,242	$	75,719
Payroll taxes	3,712		2,726		5,383
Benefits	9,252		7,329		14,926
Total employees and benefits expense	$	45,767	$	43,297	$	96,028

(a) Base LOE is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.

(b) 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 the Group's natural gas and oil properties and midstream assets.

(c) Midstream operating expenses are daily costs incurred to operate the Group's owned midstream assets inclusive of employee and benefit expenses.

(d) Transportation expenses are daily costs incurred from third-party systems to gather, process and transport the Group's natural gas, NGLs and oil.

(e) Total operating expense increased due to additional operating expense related to the Indigo acquisition in May 2021 and the EQT and Carbon acquisitions, both acquired in May 2020. Refer to Note 4 for additional information regarding acquisitions.

(f) Other administrative expense includes general liability insurance, IT services, other office expenses and travel.

(g) Professional fees include legal, marketing, payroll, auditor remuneration and consultation fees and costs associated with being a public company.

(h) Non-recurring costs associated with acquisitions primarily relate to transitional service arrangements with the acquiree, IT integration, and consulting costs directly related to acquisitions. This balance also includes expenses associated with an unused firm transportation agreement acquired as part of the Carbon acquisition.

(i) Other non-recurring costs for 2021 are associated with one-time projects and contemplated financing arrangements. For 2020, other non-recurring costs are associated with legal and professional fees related to the up-list to the Premium Segment of the Main Market of the LSE and expenses for a one-time hedge portfolio modification.

(j) Non-cash equity issuances in 2021 and 2020, reflect the expense recognition related to share-based compensation provided to certain key managers.

(k) Allowance for credit losses consists of expected credit losses and a non-recurring increase in the reserve for joint interest owner receivables. Refer to Note 14 for additional information regarding credit losses.

(a)

NOTE 7 - TAXATION

The Group files a consolidated US federal tax return, multiple state tax returns, and a separate UK tax return for the Parent entity. Income taxes are provided for the tax effects of transactions reported in the Interim Financial Statements and consist of taxes currently due plus deferred taxes related to differences between the basis of assets and liabilities for financial and income tax reporting.

For the six months ended 30 June 2021 and 2020, Income tax expense was recognised based on management's estimate of the annual effective tax rate expected for the full financial year. The estimate of the annual effective tax rate is subject to variation due to several factors including variability in forecasted pre-tax book income or loss by jurisdiction, tax credits, and changes in tax laws. Additionally, the effective tax rate can be more or less volatile based on the amount of pre-tax income or loss. For example, the impact of tax credits on our effective tax rate is greater when our pre-tax income or loss is lower.

The effective tax rate used for the six months ended 30 June 2021 was 75.6%, compared to 131.2% for the six months ended 30 June 2020. The effective tax rate is primarily impacted by the Group's recognition of the federal well tax credit available to qualified producers in 2020, who operate lower-volume wells during a low commodity pricing environment. The federal government provides these credits to encourage companies to continue producing lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local tax revenues they generate for communities to support schools, social programmes, law enforcement and other similar public services. The federal tax credit is prescribed by Internal Revenue Code Section 45I and is available for certain natural gas production from qualifying wells. In June 2021, the US Internal Revenue Service released Notice 2021-34 which quantified the amount of credit per Mcf of qualified natural gas production for tax years beginning in 2020 and also detailed the calculation methodology for future years. The federal tax credit is intended to provide a benefit for wells producing less than 90 Mcfe per day when market prices for natural gas are relatively low. The Group benefits from this credit given its portfolio of long-life, low-decline conventional wells. The Group projects a $81,183 tax credit for the tax year 2021. Other impacts to the effective rate include changes in state tax rates as a result of acquisitions and recurring permanent differences, such as meals and entertainment.

The Group had a net deferred tax asset of $265,901 at 30 June 2021 compared to a net deferred tax liability of $969 at 31 December 2020. The change was primarily due to an improving commodity price environment generating unrealised losses for unsettled derivatives not recognised for tax purposes and the recognition of federal tax credits. While subject to the volatility associated with commodity markets, if commodity prices were to settle in line with the forward strip as of 30 June 2021, we anticipate many of these deferred tax assets to become realised in the second half of the year as the current portion of unsettled derivatives becomes settled. The presentation of deferred taxes in the balance sheet takes into consideration the offsetting of deferred tax assets and deferred tax liabilities within the same tax jurisdiction, where permitted. The overall deferred tax position in a particular tax jurisdiction determines if a deferred tax balance related to that jurisdiction is presented within deferred tax assets or deferred tax liabilities.

The effective tax rates and differences between the statutory US federal income tax rate and the effective tax rates are summarised as follows:

	Six Months Ended						Year Ended
	30 June 2021			30 June 2020			31 December 2020
Income (loss) before taxation	$	(343,978)		$	(59,227)		$	(136,740)
Income tax benefit (expense)	260,021			77,712			113,266
Effective tax rate	75.6		%	131.2		%	82.8		%

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Expected tax at statutory US federal income tax rate	21.0	%	21.0	%	21.0	%
State income taxes, net of federal tax benefit	5.3	%	3.8	%	5.4	%
Federal credits	50.3	%	108.5	%	58.8	%
Other, net	(1.0)	%	(2.1)	%	(2.4)	%
Effective tax rate	75.6	%	131.2	%	82.8	%

NOTE 8 - ADJUSTED NET INCOME AND HEDGED ADJUSTED EBITDA

Adjusted Net Income and Hedged Adjusted EBITDA are defined as operating profit (loss) plus or minus the items detailed in the table below. These metrics are of particular interest to the industry and the Group. Adjusted Net Income represents net income when excluding non-cash and non-recurring amounts while Hedged Adjusted EBITDA is essentially the cash generated from operations that the Group has free for principal and interest payments, capital investments and dividend payments. Adjusted Net Income and Hedged Adjusted EBITDA should not be considered as an alternative to operating profit (loss), comprehensive income, cash flow from operating activities or any other financial performance or liquidity measure presented in accordance with IFRS.

The Directors believe Adjusted Net Income and Hedged Adjusted EBITDA are useful measures because they enable a more effective way to evaluate operating performance and compare results of operations from period-to-period and against their peers without regard to the Group's financing methods or capital structure. The Directors exclude the items listed in the table below from operating profit (loss) in arriving at Adjusted Net income and Hedged Adjusted EBITDA for the following reasons:

• Certain amounts are non-recurring from the operation of the business such as;

◦ Gains or losses on foreign currency hedges;

◦ Costs associated with acquisitions or other one-time events; or

◦ Gains or losses on natural gas and oil programme and equipment.

• Certain amounts are non-cash such as;

◦ Amortisation, depreciation and depletion;

◦ Gains or losses on the valuation of unsettled financial instruments; or

◦ Equity compensation costs included in G&A.

The following table reconciles income (loss) available to shareholders after taxation to Adjusted Net Income and Hedged Adjusted EBITDA for the periods presented:

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Income (loss) available to shareholders after taxation	$	(83,957)	$	18,485	$	(23,474)
Allowance for joint interest owner receivables	-		-		6,931
Gain on bargain purchase	-		-		(17,172)
(Gain) loss on fair value adjustments of unsettled financial instruments	371,458		109,680		238,795
(Gain) loss on natural gas and oil programme and equipment	(234)		-		2,059
Other non-recurring and acquisition related costs	8,849		10,061		25,046
Non-cash equity compensation	3,588		1,506		5,007
(Gain) loss on foreign currency hedge	1,227		-		-
(Gain) loss on interest rate swap	251		-		202
Tax effect on adjusting items ^(a)	(97,440)		(27,523)		(62,608)
Adjusted Net Income	$	203,742	$	112,209	$	174,786
Less: Tax effect on adjusting items to Adjusted Net Income	97,440		27,523		62,608
Depreciation, depletion and amortisation	71,843		55,837		117,290
Finance costs	22,512		21,412		43,327
Accretion of asset retirement obligations	10,216		7,395		15,424
Other (income) expense	5,582		(360)		421
Income tax (benefit) expense	(260,021)		(77,712)		(113,266)
Hedged Adjusted EBITDA	$	151,314	$	146,304	$	300,590

Weighted average shares outstanding - basic	736,559		662,804		685,170
Weighted average shares outstanding - diluted	740,682		667,293		688,348

Adjusted EPS - basic	$	0.28	$	0.17	$	0.26
Adjusted EPS - diluted	$	0.28	$	0.17	$	0.25

Hedged Adjusted EBITDA per Share - basic	$	0.21	$	0.22	$	0.44
Hedged Adjusted EBITDA per Share - diluted	$	0.20	$	0.22	$	0.44

(a) The tax effect on adjusting items to Adjusted Net Income is calculated using the Group's expected federal and state statutory rates for the periods presented. Refer to Note 7 for additional information regarding expected statutory rates.

(a)

NOTE 9 - EARNINGS (LOSS) PER SHARE

The calculation of basic earnings (loss) per share is based on the income (loss) available to shareholders after taxation and on the weighted average number of shares outstanding during the period. The calculation of diluted earnings per share is based on the income (loss) available to shareholders after taxation and the weighted average number of shares outstanding plus the weighted average number of shares that would be issued if dilutive options and warrants were converted into shares on the last day of the reporting period. Basic and diluted earnings (loss) per share are calculated as follows for the periods presented:

		Six Months Ended				Year Ended
	Calculation	30 June 2021		30 June 2020		31 December 2020
Income (loss) available to shareholders after taxation	A	$	(83,957)	$	18,485	$	(23,474)

Weighted average shares outstanding - basic	B	736,559		662,804		685,170
Weighted average shares outstanding - diluted	C	740,682		667,293		688,348

Earnings (loss) per share - basic	= A/B	$	(0.11)	$	0.03	$	(0.03)
Earnings (loss) per share - diluted	= A/C	$	(0.11)	$	0.03	$	(0.03)

Hedged Adjusted EBITDA per Share - basic	Note 8	$	0.21	$	0.22	$	0.44
Hedged Adjusted EBITDA per Share - diluted		$	0.20	$	0.22	$	0.44

NOTE 10 - NATURAL GAS AND OIL PROPERTIES

The following table summarises the Group's natural gas and oil properties for the periods presented:

	Six Months Ended		Year Ended
	30 June 2021		31 December 2020
Costs
Beginning balance	$	1,968,557	$	1,625,884
Additions ^(a)	304,831		346,385
Disposals ^(b)	-		(3,712)
Ending balance	$	2,273,388	$	1,968,557
Depletion and impairment
Beginning balance	$	(213,472)	$	(129,855)
Period changes	(50,646)		(83,617)
Disposals	-		-
Ending balance	$	(264,118)	$	(213,472)

Net book value	$	2,009,270	$	1,755,085

(a) For the six months ended 30 June 2021, $169,036 in additions related to the acquisition of Indigo and $119,284 resulted from normal revisions to the Group's asset retirement obligations. The remaining change is primarily attributable to recurring capital expenditures. For the year ended 31 December 2020, $103,991, $117,149 and $7,083 in additions related to the acquisitions of Carbon, EQT and the Utica wells, respectively. The remaining change is primarily attributable to revisions in the Group's asset retirement obligations as a result of changes in the discount rate. Refer to Notes 4 and 18 for additional information regarding acquisitions and asset retirement obligations, respectively.

(b) In September 2020 the Group sold 662 wells in McKean, Forest, and Warren Counties, Pennsylvania.

Impairment of Natural Gas and Oil Properties

For the period ended 30 June 2021, the Directors assessed the indicators of impairment, noting strong pricing along the forward curve and an improving economic outlook to the Group. This assessment also included a comparison of the carrying value of the Group's natural gas and oil properties to their fair values and an assessment of the projected impact of climate change on the Group. As a result of their assessments no impairment indicators were identified.

NOTE 11 - PROPERTY, PLANT AND EQUIPMENT

The following tables summarise the Group's property, plant and equipment for the periods presented:

	Six Months Ended 30 June 2021
	Buildings and Leasehold Improvements		Equipment		Motor Vehicles		Midstream Assets		Other Property and Equipment		Total
Costs
Beginning balance	$	28,190	$	6,768	$	35,129	$	367,331	$	5,600	$	443,018
Additions ^(a)(b)	5,481		152		5,296		5,651		4,413		20,993
Disposals ^(c)	-		(11)		(945)		-		-		(956)
Ending balance ^(d)	$	33,671	$	6,909	$	39,480	$	372,982	$	10,013	$	463,055
Accumulated depreciation
Beginning balance	$	(1,007)	$	(2,860)	$	(12,409)	$	(43,597)	$	(1,042)	$	(60,915)
Period changes	(235)		(529)		(4,071)		(11,475)		(272)		(16,582)
Disposals	-		2		569		-		-		571
Ending balance	$	(1,242)	$	(3,387)	$	(15,911)	$	(55,072)	$	(1,314)	$	(76,926)

Net book value	$	32,429	$	3,522	$	23,569	$	317,910	$	8,699	$	386,129

	Year Ended 31 December 2020
	Buildings and Leasehold Improvements		Equipment		Motor Vehicles		Midstream Assets		Other Property and Equipment		Total
Costs
Beginning balance	$	22,654	$	4,438	$	19,099	$	306,537	$	2,205	$	354,933
Additions ^(a)(b)	5,536		2,415		19,127		60,794		3,395		91,267
Disposals ^(c)	-		(85)		(3,097)		-		-		(3,182)
Ending balance ^(d)	$	28,190	$	6,768	$	35,129	$	367,331	$	5,600	$	443,018
Accumulated depreciation
Beginning balance	$	(559)	$	(1,987)	$	(7,251)	$	(23,455)	$	(728)	$	(33,980)
Period changes	(448)		(876)		(5,770)		(20,142)		(314)		(27,550)
Disposals	-		3		612		-		-		615
Ending balance	$	(1,007)	$	(2,860)	$	(12,409)	$	(43,597)	$	(1,042)	$	(60,915)

Net book value	$	27,183	$	3,908	$	22,720	$	323,734	$	4,558	$	382,103

(a) Of the $20,993 in 2021 additions, $10,859 was associated with right-of-use asset additions for new and acquired leases. Of the $91,267 in 2020 additions, $46,713 and $10,956 were related to the acquisitions of Carbon and EQT, respectively, while $19,820 was associated with right-of-use asset additions for new and amended leases. Refer to Note 4 for additional information regarding acquisitions.

(b) Remaining additions are related to routine capital projects on the Group's compressor and gathering systems, vehicle and equipment additions.

(c) Disposals in 2020 were primarily related to $1,945 of vehicles acquired as part of the Carbon acquisition being transferred to the Group's fleet management lease programme.

(d) Buildings and Leasehold Improvements and Motor Vehicles are inclusive of right-of-use assets associated with the Group's leases. Refer to Note 19 for additional information regarding leases.

The Group continued to utilise certain fully depreciated assets during the year to 30 June 2021 and 31 December 2020 with an original cost basis of $3,296 and $3,313, respectively.

NOTE 12 - INTANGIBLE ASSETS

Intangible assets consisted of the following for the periods presented:

	Six Months Ended 30 June 2021
	Software		Other Acquired Intangibles		Total
Costs
Beginning balance	$	24,271	$	2,900	$	27,171
Additions ^(a)	1,526		-		1,526
Disposals	-		-		-
Ending balance	$	25,797	$	2,900	$	28,697
Accumulated amortisation
Beginning balance	$	(7,246)	$	(712)	$	(7,958)
Period changes	(3,954)		(475)		(4,429)
Disposals	-		-		-
Ending balance	$	(11,200)	$	(1,187)	$	(12,387)

Net book value	$	14,597	$	1,713	$	16,310

	Year Ended 31 December 2020
	Software		Other Acquired Intangibles		Total
Costs
Beginning balance	$	17,822	$	-	$	17,822
Additions ^(a)	6,449		2,900		9,349
Disposals	-		-		-
Ending balance	$	24,271	$	2,900	$	27,171
Accumulated amortisation
Beginning balance	$	(1,841)	$	-	$	(1,841)
Period changes	(5,405)		(712)		(6,117)
Disposals	-		-		-
Ending balance	$	(7,246)	$	(712)	$	(7,958)

Net book value	$	17,025	$	2,188	$	19,213

(a) For the six months ended 30 June 2021 additions were related to software enhancements. For the year ended 31 December 2020 additions were related to software enhancements and $2,900 in other acquired intangibles.

(a)

NOTE 13 - DERIVATIVE FINANCIAL INSTRUMENTS

The Group is exposed to volatility in market prices and basis differentials for natural gas, NGLs and oil, which impacts the predictability of its cash flows related to the sale of those commodities. The Group is also exposed to volatility in interest rate markets, which impacts the predictability of its cash flows related to interest payments on the Group's variable rate debt obligations. These risks are managed by the Group's use of certain derivative financial instruments. As of 30 June 2021, the Group's derivative financial instruments consisted of swaps, collars, basis swaps, stand-alone put and call options, and swaptions. A description of the Group's derivative financial instruments is provided below:

• Swaps: If the Group sells a swap, it receives a fixed price for the contract and pays a floating market price to the counterparty;

• Collars : Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net costs. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Group pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Group will receive the difference between the floor price and the index price.

Certain collar arrangements may also include a sold put option with a strike price below the purchased put option. Referred to as a three-way collar, the structure works similar to the above description except that when the index price settles below the sold put option the Group pays the counterparty the difference between the index price and sold put option, effectively enhancing realised pricing by the difference between the price of the sold and purchased put option;

• Basis swaps : Arrangements that guarantee a price differential for commodities from a specified delivery point. If the Group sells a basis swap, it receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract;

• Put options : The Group purchases and sells put options in exchange for a premium. If the Group purchases a put option, it receives from the counterparty the excess (if any) of the market price below the strike price of the put option at the time of settlement, but if the market price is above the put's strike price, no payment is due from either party;

• Call options : The Group purchases and sells call options in exchange for a premium. If the Group purchases a call option, it receives from the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call's strike price, no payment is due from either party. If the Group sells a call option, it pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call's strike price, no payment is due from either party; and

• Swaptions : If the Group sells a swaption, the counterparty will receive the option to enter into a swap contract at a specified date and receives a fixed price for the contract and pays a floating market price to the counterparty.

The Group may elect to enter into offsetting transactions for the above instruments for the purpose of cancelling or terminating certain positions.

The following tables summarise the Group's calculated net fair value of derivative financial instruments as of the reporting date as follows:

NATURAL GAS CONTRACTS		Weighted Average Price per Mcfe ^(a)
	Volume			Sold		Purchased		Sold		Purchased		Basis		Fair Value at
	(MMcf)	Swaps		Puts		Puts		Calls		Calls		Differential		30 June 2021
For the Remainder of 2021
Swaps	130,954	$	2.99	$	-	$	-	$	-	$	-	$	-	$	(116,000)
Stand-Alone Calls	3,680	-		-		-		2.81		-		-		(3,900)
Basis Swap	88,119	-		-		-		-		-		(0.48)		28,305
Total 2021 contracts	222,753													$	(91,595)
2022
Swaps	180,289	$	2.91	$	-	$	-	$	-	$	-	$	-	$	(91,912)
Stand-Alone Calls	32,050	-		-		-		3.00		3.02		-		(15,353)
Basis Swap	95,549	-		-		-		-		-		(0.35)		16,382
Total 2022 contracts	307,888													$	(90,883)
2023
Swaps	78,457	$	2.60	$	-	$	-	$	-	$	-	$	-	$	(31,974)
Collars	5,400	-		2.16		2.84		3.62		-		-		(1,430)
Stand-Alone Calls	85,392	-		-		-		2.98		-		-		(32,379)
Basis Swap	900	-		-		-		-		-		(0.50)		165
Total 2023 contracts	170,149													$	(65,618)
2024
Swaps	71,679	$	2.57	$	-	$	-	$	-	$	-	$	-	$	(23,308)
Stand-Alone Calls	37,698	-		-		-		2.93		-		-		(14,350)
Total 2024 contracts	109,377													$	(37,658)
2025
Swaps	65,864	$	2.57	$	-	$	-	$	-	$	-	$	-	$	(22,378)
2026
Swaps	42,454	$	2.55	$	-	$	-	$	-	$	-	$	-	$	(16,995)
2027
Swaps	33,820	$	2.53	$	-	$	-	$	-	$	-	$	-	$	(13,731)
2028
Swaps	32,190	$	2.52	$	-	$	-	$	-	$	-	$	-	$	(13,910)
2029
Swaps	29,190	$	2.51	$	-	$	-	$	-	$	-	$	-	$	(13,325)
2030
Swaps	5,450	$	2.45	$	-	$	-	$	-	$	-	$	-	$	(3,313)
Swaptions
1/1/2022-1/12/2022 ^(b)	14,600	$	-	$	-	$	-	$	2.86	$	-	$	-	$	(7,701)
1/10/2024-1/9/2028 ^(c)	2,740	-		-		-		2.94		-		-		(5,047)
1/1/2025-1/12/2029 ^(d)	7,300	-		-		-		2.80		-		-		(9,780)
1/4/2026-1/3/2030 ^(e)	97,277	-		-		-		2.59		-		-		(39,944)
1/4/2030-1/3/2032 ^(f)	42,627	-		-		-		2.59		-		-		(24,905)
Total 2025-2032 contracts	373,512													$	(171,029)
Total natural gas contracts	1,183,679													$	(456,783)

(a) Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.08.

(b) Option expires on 23 December 2021.

(d) Option expires on 23 December 2024.

(e) Option expires on 23 March 2026.

(f) Option expires on 22 March 2030.

NGLs CONTRACTS		Weighted Average Price per Bbl
	Volume			Sold		Purchased		Sold		Purchased		Basis		Fair Value at
	(MBbls)	Swaps		Puts		Puts		Calls		Calls		Differential		30 June 2021
For the Remainder of 2021
Swaps ^(a)	1,516	$	24.33	$	-	$	-	$	-	$	-	$	-	$	(32,688)
2022
Swaps ^(a)	2,920	$	26.37	$	-	$	-	$	-	$	-	$	-	$	(37,579)
2023
Stand-Alone Calls	365	$	-	$	-	$	-	$	24.78	$	-	$	-	$	(1,877)
Total NGLs contracts	4,801													$	(72,144)

(a) Certain portions of NGL swaps include effects of purchased oil swaps intended to provide a final NGL price as a percentage of WTI.

OIL CONTRACTS		Weighted Average Price per Bbl
	Volume			Sold		Purchased		Sold		Purchased		Basis		Fair Value at
	(MBbls)	Swaps		Puts		Puts		Calls		Calls		Differential		30 June 2021
For the Remainder of 2021
Sold Swaps	151	$	46.91	$	-	$	-	$	-	$	-	$	-	$	(3,641)
Long Swaps	153	32.63		-		-		-		-		-		5,890
Collars	62	-		-		47.58		65.43		-		-		(465)
Total 2021 contracts	366													$	1,784
2022
Swaps	110	$	43.06	$	-	$	-	$	-	$	-	$	-	$	(2,582)
2023
Swaps	70	37.00		-		-		-		$	-	-		(1,649)
Stand-Alone Calls	117	-		-		-		53.20		$	-	-		(1,481)
2024
Swaps	64	37.00		-		-		-		$	-	-		(1,277)
2025
Swaps	56	37.00		-		-		-		$	-	-		(984)
2026
Swaps	13	37.00		-		-		-		$	-	-		(224)
Total oil contracts	796													$	(6,413)

INTEREST					Fair Value at
	Principal Hedged		Fixed Rate		30 June 2021
2022
LIBOR Interest Rate Swap	$	150,000	0.45	%	$	(376)

Net fair value of derivative financial instruments at 30 June 2021					$	(535,716)

Netting the fair values of derivative assets and liabilities for financial reporting purposes is permitted if such assets and liabilities are with the same counterparty and a legal right of set-off exists, subject to a master netting arrangement. The Directors have elected to present derivative assets and liabilities net when these conditions are met. The following table outlines the Group's net derivatives as of the reporting date as follows:

Derivative Financial Instruments	Consolidated Statement of Financial Position	30 June 2021		31 December 2020
Assets:
Non-current assets	Derivative financial instruments	$	139	$	717
Current assets	Derivative financial instruments	-		17,858
Total assets		$	139	$	18,575
Liabilities
Non-current liabilities	Derivative financial instruments	$	(321,969)	$	(168,524)
Current liabilities	Derivative financial instruments	(213,886)		(15,858)
Total liabilities		$	(535,855)	$	(184,382)
Net assets (liabilities):
Net assets (liabilities) - non-current	Other non-current assets (liabilities)	$	(321,830)	$	(167,807)
Net assets (liabilities) - current	Other current assets (liabilities)	(213,886)		2,000
Total net assets (liabilities)		$	(535,716)	$	(165,807)

The Group's policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Group's recognised assets and liabilities for the periods indicated:

	As at 30 June 2021
	Presented without Effects of Netting		Effects of Netting		As Presented with Effects of Netting
Non-current assets	$	22,896	$	(22,757)	$	139
Current assets	62,809		(62,809)		-
Total assets	$	85,705	$	(85,566)	$	139

Non-current liabilities	$	(344,726)	$	22,757	$	(321,969)
Current liabilities	(276,695)		62,809		(213,886)
Total liabilities	$	(621,421)	$	85,566	$	(535,855)

Total net assets (liabilities)	$	(535,716)	$	-	$	(535,716)

	As at 31 December 2020
	Presented without Effects of Netting		Effects of Netting		As Presented with Effects of Netting
Non-current assets	$	25,159	$	(24,442)	$	717
Current assets	42,023		(24,165)		17,858
Total assets	$	67,182	$	(48,607)	$	18,575

Non-current liabilities	$	(192,967)	$	24,443	$	(168,524)
Current liabilities	(40,022)		24,164		(15,858)
Total liabilities	$	(232,989)	$	48,607	$	(184,382)

Total net assets (liabilities)	$	(165,807)	$	-	$	(165,807)

The Group recorded the following gain (loss) on derivative financial instruments in the Consolidated Statement of Comprehensive Income for the periods presented:

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Net gain (loss) on commodity derivatives ^(a)	$	(21,949)	$	83,506	$	144,600
Net gain (loss) on interest rate swap ^(a)	(251)		-		(202)
Gain (loss) on foreign currency hedge ^(a)	(1,227)		-		-
Total gain (loss) on settled derivative instruments	$	(23,427)	$	83,506	$	144,398
Gain (loss) on fair value adjustments of unsettled financial instruments ^(b)	(371,458)		(109,680)		(238,795)
Total gain (loss) on derivative financial instruments	$	(394,885)	$	(26,174)	$	(94,397)

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

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

All derivatives are defined as Level 2 instruments as they are valued using inputs and outputs other than quoted prices that are observable for the assets and liabilities.

From time to time, when making acquisitions, the Group will acquire certain hedge contracts associated with the acquired natural gas properties. Infrequently, the Group will terminate or adjust acquired derivative contracts to modify the quantum of production, the swap or floor price or other similar elements of the contracts. Given the increasing price environment at the time of the Indigo acquisition and favourable forward curve the Group elected to early terminate certain legacy Indigo positions resulting in a cash payment of $6,797 which the Group recorded on its Consolidated Statement of Financial Position. New contracts were subsequently entered into more favourable pricing in order to secure the cash flows associated with these producing assets.

NOTE 14 - TRADE AND OTHER RECEIVABLES

Trade receivables include amounts due from customers, entities that purchase the Group's natural gas, NGLs and oil production, and also include amounts due from joint interest owners, entities that own a working interest in the properties operated by the Group. The majority of trade receivables are current and the Group believes these receivables are collectible. At 30 June 2021 and 31 December 2020, the Group recorded an allowance for current expected credit losses of $11,585 and $11,082, respectively. The following table summarises the Group's trade receivables. The fair value approximates the carrying value as at the periods presented:

	30 June 2021		31 December 2020
Commodity receivables	$	87,184	$	70,199
Other receivables ^(a)	10,173		7,874
Total trade receivables	$	97,357	$	78,073
Allowance for credit losses ^(b)	(11,585)		(11,082)
Total trade receivables, net	$	85,772	$	66,991

(a) Other receivables primarily relate to hedge settlement receivables and amounts due to the Group from acquirees under transitional service arrangements for asset operations being transitioned to the Group.

(b) The allowance for credit losses was primarily related to amounts due from joint interest owners.

(a)

NOTE 15 - OTHER ASSETS

The following table includes a detail of other assets as at the periods presented:

	30 June 2021		31 December 2020
Other non-current assets
Other non-current assets ^(a)	$	16,249	$	2,376
Indemnification receivable ^(b)	-		1,837
Total other non-current assets	$	16,249	$	4,213
Other current assets
Prepaid expenses	$	5,012	$	1,681
Inventory	6,089		6,315
Total other current assets	$	11,101	$	7,996

(a) As of 30 June 2021, $13,502 related to a deposit on the Blackbeard acquisition. Refer to Note 4 for additional information regarding acquisitions.

(b) At the date of acquisition, the Directors determined that Alliance Petroleum had taken uncertain tax positions, and as a result, an indemnification agreement was executed. The Group recorded a uncertain tax position liability and indemnification receivable for the amount of $1,837 as at 31 December 2020. During 2021 the statute of limitations associated with the uncertain tax position was met and the Group is no longer subject to potential tax liability associated with the tax position. As a result, the provision for the uncertain tax position and the indemnification receivable were removed.

(a)

NOTE 16 - SHARE CAPITAL

Share capital represents the nominal (par) value of shares (£0.01) that have been issued. Share premium includes any premiums received on issue of share capital above par. Any transaction costs associated with the issuance of shares are deducted from share premium, net of any related income tax benefits. The components of share capital include:

Issuance of Share Capital

In May 2021, the Group placed 141,541 new shares at $1.59 per share (£1.12) to raise gross proceeds of $225,050 (approximately £158,526). Associated costs of the placing were $11,206. The Group used the proceeds to pay down the Credit Facility and partially fund the Indigo and Blackbeard acquisitions, discussed in Notes 20 and 4, respectively.

In May 2020, the Group placed 64,281 new shares at $1.33 per share (£1.08) to raise gross proceeds of $85,415 (approximately £69,423). Associated costs of the placing were $4,008. The Group used the proceeds to partially fund the acquisition of certain assets of Carbon and EQT, discussed in Note 4.

Repurchase of Shares

During the year ended 31 December 2020, the Group repurchased 12,958 treasury shares at an average price of $1.21 totalling $15,634. The Group has accounted for the repurchase of these shares as a direct reduction to retained earnings.

All repurchased treasury shares have been cancelled.

Cancellation of Warrants

In January 2021, the Group entered into an agreement to cancel 2,377 warrants (the "Warrants") held by Mirabaud Securities Limited ("Mirabaud") and certain former Mirabaud employees for an aggregate principal amount of approximately $1,429 (approximately £1,040). Mirabaud and its former employees surrendered the Warrants to the Group for cancellation. Following this purchase, 1,123 warrants remain outstanding.

The following tables summarise the Group's share capital, net of customary transaction costs, for the periods presented:

	Number of Shares	Total Share Capital		Total Share Premium
Balance at 31 December 2020	707,377	$	9,520	$	841,159
Issuance of share capital	141,541	$	2,044	$	211,800
Repurchase of shares	-	-		-
Other issues ^(a)	516	4		-
Balance at 30 June 2021	849,434	$	11,568	$	1,052,959

	Number of Shares	Total Share Capital		Total Share Premium
Balance at 31 December 2019	655,730	$	8,800	$	760,543
Issuance of share capital	64,281	$	791	$	80,616
Repurchase of shares	(12,958)	(74)		-
Other issues ^(a)	324	3		-
Balance at 31 December 2020	707,377	$	9,520	$	841,159

(a) During the six months and year ended 30 June 2021 and 31 December 2020, the Group issued 516 and 324 RSUs, respectively, to certain key managers. The RSUs had no impact on share premium.

(a)

NOTE 17 - DIVIDENDS

The following table summarises the Group's dividends declared and paid on the dates indicated:

	Dividend per Share
Date Dividends Declared/Paid	USD		GBP		Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid
Declared on 29 October 2020	$	0.0400	£	0.0285	5 March 2021	26 March 2021	707,525	$	28,301
Declared on 8 March 2021	$	0.0400	£	0.0281	28 May 2021	24 June 2021	849,434	33,970
Paid during the six months ended 30 June 2021								$	62,271

Declared on 10 December 2019	$	0.0350	£	0.0276	6 March 2020	27 March 2020	642,805	$	22,498
Declared on 9 March 2020	$	0.0350	£	0.0274	29 May 2020	26 June 2020	707,086	24,748
Paid during the six months ended 30 June 2020								$	47,246
Declared on 4 May 2020	$	0.0350	£	0.0269	4 September 2020	25 September 2020	707,274	$	24,755
Declared on 10 August 2020	$	0.0375	£	0.0278	27 November 2020	18 December 2020	707,377	26,526
Paid during the year ended 31 December 2020								$	98,527

On 30 April 2021 the Group proposed a dividend of $0.04 per share. The dividend will be paid on 24 September 2021 to shareholders on the register on 3 September 2021. This dividend was not approved by shareholders, thereby qualifying it as an "interim" dividend. No liability was recorded in the Interim Financial Statements in respect of this interim dividend as at 30 June 2021.

Subsequent Events

On 5 August 2021 the Directors recommended a dividend of $0.04 per share. The dividend will be paid on 17 December 2021 to shareholders on the register on 26 November 2021. This dividend was not approved by shareholders, thereby qualifying it as an "interim" dividend. No liability has been recorded in the Interim Financial Statements in respect of this dividend as at 30 June 2021.

NOTE 18 - ASSET RETIREMENT OBLIGATIONS

The Group records a liability for the future cost of decommissioning its natural gas and oil properties, which it expects to incur at the end of the long-producing life of a well. Production lives vary within the Group's well portfolio and presently the Group expects all of its existing wells to have reached the end of their economic lives by approximately 2095.

The Group also records a liability for the future cost of decommissioning its production facilities and pipelines if required by contract or statute. The decommissioning liability represents the present value of estimated future decommissioning costs. No such contractual agreements or statutes were in place for the Group for the year to 30 June 2021 and 31 December 2020.

In estimating the present value of future decommissioning costs of natural gas and oil properties the Group takes into account the number and state jurisdictions of wells, current costs to decommission by state and the average well life across its portfolio. The Directors' assumptions are based on the current economic environment and represent what the Directors believe is a reasonable basis upon which to estimate the future liability. However, actual decommissioning costs will ultimately depend upon future market prices at the time the decommissioning services are performed. Furthermore, the timing of decommissioning will vary depending on when the fields cease to produce economically, making the determination dependent upon future natural gas and oil prices, which are inherently uncertain.

The Group applies a contingency allowance for annual cost increases and discounts the resulting cash flows using a credit adjusted risk free discount rate. The Group considers the Bloomberg 15-year US Energy BB bond to most closely align with the underlying long-term and unsecured liability and has derived its risk adjusted rate by reference to that. The net discount rate used in the calculation of the decommissioning liability in 2021 and 2020 was 2.9% and 3.7%, respectively.

The composition of the provision for asset retirement obligations at the reporting date was as follows for the periods presented:

	Six Months Ended		Year Ended
	30 June 2021		31 December 2020
Balance at beginning of period	$	346,124	$	199,521
Additions ^(a)	38,209		26,995
Accretion	10,216		15,424
Plugging costs	(1,180)		(2,442)
Disposals	-		(3,838)
Revisions to estimate ^(b)(c)	119,284		110,464
Balance at end of period	$	512,653	$	346,124
Less: Current asset retirement obligations	1,878		1,882
Non-current asset retirement obligations	$	510,775	$	344,242

(a) Refer to Note 4 for additional information regarding acquisitions.

(b) At 30 June 2021, the Group performed normal revisions to its asset retirement obligations, which resulted in a $119,284 increase in the liability. This increase was a result of macroeconomic factors spurred by the Covid-19 recovery, which reduced bond yields and increased inflation, driving a decrease in the Group's discount rate.

(c) At 31 December 2020, the Group performed normal revisions to its asset retirement obligations which resulted in a $110,464 adjustment, of which $102,686 relates to macroeconomic factors stemming largely from the Covid-19 pandemic that reduced bond yields and resulted in a lower discount rate applied to our asset retirement obligations liability. The remaining $7,778 relates to pricing-related adjustments based on historical costs incurred to retire wells.

Changes to assumptions used as inputs for the estimation of the Group's asset retirement obligations could result in a material change in the carrying value of the liability. A reasonably possible fifty basis point decline in the gross discount rate could have an approximately $105,054 impact on the Group's asset retirement obligations as at 30 June 2021.

NOTE 19 - LEASES

The Group leased automobiles, equipment and real estate for the periods presented below. A reconciliation of leases arising from financing activities and the balance sheet classification of future minimum lease payments as at the reporting periods presented were as follows:

	Present Value of Minimum Lease Payments
	30 June 2021		31 December 2020
Balance at beginning of period	$	18,878	$	1,813
Additions ^(a)	10,859		19,820
Interest expense ^(b)	577		929
Cash outflows	(3,134)		(3,684)
Balance at end of period	$	27,180	$	18,878
Classified as:
Current liability	$	6,087	$	5,013
Non-current liability	21,093		13,865
Total	$	27,180	$	18,878

(a) Of the $10,859 in lease additions at 30 June 2021, $6,445 was attributable to the Indigo acquisition. Of the $19,820 in lease additions at 31 December 2020, $3,500 was attributable to the Carbon acquisition. The remainder is a result of fleet expansion and the Group transitioning owned vehicles to a fleet management lease programme.

(b) Included as a component of finance cost.

Set out below is the movement in the right-of-use assets:

	Right-of-Use Assets
	30 June 2021		31 December 2020
Balance at beginning of period	$	18,026	$	1,868
Additions ^(a)	10,859		19,558
Depreciation	(2,637)		(3,400)
Balance at end of period	$	26,248	$	18,026
Classified as:
Motor vehicles	$	17,456	$	14,614
Buildings and leasehold improvements	8,792		3,412
Total	$	26,248	$	18,026

(a) Of the 10,859 in lease additions at 30 June 2021, $6,445 was attributable to the Indigo acquisition. Of the 19,558 in lease additions at 31 December 2020, $3,500 was attributable to the Carbon acquisition. The remainder is a result of fleet expansion and the Group transitioning owned vehicles to a fleet management lease programme.

The range of discount rates applied in calculating right-of-use assets and related lease liabilities, depending on the lease term, is presented below:

	30 June 2021		31 December 2020
Discount rates range	1.8% - 4.4%		1.8% - 3.3%

Expenses related to short-term and low-value lease exemptions applied under IFRS 16 are disclosed in Note 6.

The following table reflects the maturity of leases as of the periods presented:

	30 June 2021		31 December 2020
Not Later Than One Year	$	6,087	$	5,013
Later Than One Year and Not Later Than Five Years	20,743		13,865
Later Than Five Years	350		-
Total	$	27,180	$	18,878

NOTE 20 - BORROWINGS

The Group's borrowings consist of the following amounts as of the reporting date as follows:

	30 June 2021		31 December 2020
Credit Facility (Interest rate of 2.36% and 2.96%, respectively)	$	156,500	$	213,400
ABS I Note (Interest rate of 5.00%)	168,150		180,426
ABS II Note (Interest rate of 5.25%)	180,177		191,125
Term Loan I (Interest rate of 6.50%)	146,786		156,805
Miscellaneous, primarily for real estate, vehicles and equipment	3,851		4,730
Total borrowings	$	655,464	$	746,486
Less: Current portion of long-term debt	(64,919)		(64,959)
Less: Deferred financing costs	(19,623)		(23,068)
Less: Original issue discounts	(5,521)		(6,178)
Total non-current borrowings, net	$	565,401	$	652,281

Credit Facility

In April 2021, the Group reaffirmed its borrowing base on the $1,500,000 Credit Facility at $425,000, which maintains the maturity date of the previous facility of July 2023. The Credit Facility is secured by natural gas and oil properties and has an interest rate of one-month LIBOR plus 2.50% and is subject to a pricing grid that fluctuates from 2.00% to 3.00% plus LIBOR based on utilisation. Interest and principal payments on the Credit Facility are paid on a monthly basis. The next redetermination is in November 2021. Available borrowings under the Credit Facility were $268,500 as of 30 June 2021.

The Credit Facility contains certain customary representations and warranties and affirmative and negative covenants, including covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset sales, certain debt payments and amendments, restrictive agreements, investments, restricted payments and hedging. It also requires the Group to maintain a ratio of total debt to EBITDAX (the "Leverage Ratio") of not more than 3.75 to 1.00 and a ratio of current assets (with certain adjustments) to current liabilities (the "Current Ratio") of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of 30 June 2021 the Group was in compliance with all financial covenants. The fair value of the Credit Facility approximates the carrying value as at 30 June 2021.

Term Loan I

In May 2020, the Group formed DP Bluegrass LLC ("Bluegrass"), a limited-purpose, bankruptcy-remote, wholly owned subsidiary of the Group to enter into a securitised financing agreement for $160,000, which was structured as a secured term loan. The Group issued the Term Loan I at a 1% discount, and used the proceeds of $158,400 to fund the Carbon and EQT acquisitions, discussed in Note 4.

The Term Loan I is secured by the Group's producing assets acquired from Carbon and EQT, discussed in Note 4.

The Term Loan I accrues interest at a stated 6.50% annual rate and has a maturity date of May 2030. Interest and principal payments on the Term Loan I are payable on a monthly basis beginning May 2020 and November 2020, respectively. During the six months ended 30 June 2021 and 2020 and the year ended 31 December 2020, the Group incurred $5,091, $1,039 and $6,371 in interest related to the Term Loan I, respectively, which is recognised under the effective interest rate method. The fair value of the Term Loan I approximates the carrying value as at 30 June 2021.

The Term Loan I is subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the Term Loan I, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified premium payments in the case of an optional prepayment, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral for the Term Loan I are used in stated ways defective or ineffective, and (iv) covenants related to recordkeeping, access to information and similar matters.

The Term Loan I is also subject to customary accelerated amortisation events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, certain change of control and management termination events, and event of default and the failure to repay or refinance the Term Loan I on the applicable scheduled maturity date.

The Term Loan I is subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the Term Loan I, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of 30 June 2021 the Group was in compliance with all financial covenants.

ABS II Note

In April 2020, the Group formed Diversified ABS Phase II LLC ("ABS II"), a limited-purpose, bankruptcy-remote, wholly owned subsidiary of the Group to enter into a securitised financing agreement for $200,000. The ABS II Note is BBB rated and was issued at a 2.78% discount. The Group used the proceeds of $183,617, net of discount, capital reserve requirement, and debt issuance costs, to pay down its Credit Facility.

The ABS II Note is secured by 29.4% of certain producing assets of the Group. Natural gas production associated with the 29.4% working interest was hedged at 85% at the close of the agreement with long-term derivative contracts.

The ABS II Note accrues interest at a stated 5.25% rate and has a maturity date of July 2037. Interest and principal payments on the ABS II Note are payable on a monthly basis beginning July 2020 and August 2020, respectively. For the six months ended 30 June 2021 and 2020 and the year ended 31 December 2020, the Group incurred $5,421, $2,657 and $7,563 in interest related to the ABS II Note, respectively, which is recognised under the effective interest rate method. In the event that ABS II has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, the Group is required to pay down additional principal with the remaining proceeds remaining with the Group. The fair value of the ABS II Note approximates the carrying value as at 30 June 2021.

The ABS II Note is subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS II Note, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified premium payments in the case of an optional prepayment, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral for the ABS II Note are used in stated ways defective or ineffective, and (iv) covenants related to recordkeeping, access to information and similar matters.

The ABS II Note is also subject to customary early amortisation events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS II Note on the applicable scheduled maturity date.

The ABS II Note is subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the ABS II Note, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of 30 June 2021 the Group was in compliance with all financial covenants.

ABS I Note

In November 2019, the Group formed Diversified ABS LLC ("ABS I"), a limited-purpose, bankruptcy-remote, wholly-owned subsidiary of the Group to enter into a securitised financing agreement for $200,000 which was issued at par through a BBB- rated bond. The ABS I Note is secured by 21.6% of certain producing assets of the Group. Natural gas production associated with the 21.6% working interest was hedged at 85% at the close of the agreement using a 10-year swap and rolling 2-year basis hedge.

Interest and principal payments on the ABS I Note are payable on a monthly basis beginning 28 February 2020. For the six months ended 30 June 2021 and 2020 and the year ended 31 December 2020, the Group incurred $4,383, $4,962 and $9,661 of interest related to the ABS I Note, respectively. The legal final maturity date is January 2037 with an amortising maturity of December 2029. The ABS I Note accrues interest at a stated 5% rate. In the event that ABS I has cash flow in excess of the required payments, 25% to 100% of the excess cash, contingent on certain performance metrics, the Group is required to pay down additional principal with the remaining proceeds remaining with the Group. The fair value of the ABS I Note approximates the carrying value as at 30 June 2021.

The ABS I Note is subject to a series of covenants and restrictions customary for transactions of this type, including (i) that the Issuer maintains specified reserve accounts to be used to make required interest payments in respect of the ABS I Note, (ii) provisions relating to optional and mandatory prepayments and the related payment of specified amounts, including specified make-whole payments in the case of the ABS I Note under certain circumstances, (iii) certain indemnification payments in the event, among other things, that the assets pledged as collateral for the ABS I Note is used in stated ways defective or ineffective, and (iv) covenants related to recordkeeping, access to information and similar matters.

The ABS I Note is also subject to customary rapid amortisation events provided for in the indenture, including events tied to failure to maintain stated debt service coverage ratios, failure to maintain certain production metrics, certain change of control and management termination events, and event of default and the failure to repay or refinance the ABS I Note on the applicable scheduled maturity date.

The ABS I Note is subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the ABS I Note, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments.

As of 30 June 2021 the Group was in compliance with all financial covenants.

In August 2020, in conjunction with Munich Re Reserve Risk Financing, Inc. ("MRRF"), the Group requested to withdraw the public ratings on the ABS I Note. Following MRRF's further investment in the Group through the Term Loan I to fund a portion of the Group's most recent acquisitions from EQT and Carbon, MRRF dedicated internal resources to both the ABS I Note and the Term Loan I, and given these resources, believed the rating agencies' reviews and oversight were unnecessary. Both Fitch and Morningstar affirmed the BBB- rating of the ABS I Note concurrent with the ratings withdrawal, which was not the result of any disagreement with the rating agencies or MRRF.

For clarity, the ABS II Note is unaffected by this reporting change to the ABS I Note, and Fitch will continue to cover the ABS II Note, which remains BBB rated at the time of this report.

The following table provides a reconciliation of the Group's future maturities of its total borrowings as of the reporting date as follows:

	30 June 2021		31 December 2020
Not later than one year	$	64,919	$	64,959
Later than one year and not later than five years	393,755		450,503
Later than five years	196,790		231,024
Total borrowings	$	655,464	$	746,486

The following table represents the Group's finance costs for each of the periods presented:

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Interest expense, net of capitalised and income amounts ^(a)	$	18,172	$	17,476	$	34,391
Amortisation of discount and deferred finance costs	4,304		3,809		8,334
Other	36		127		602
Total finance costs	$	22,512	$	21,412	$	43,327
Loss on early retirement of debt	$	-	$	-	$	-

(a) Includes payments related to borrowings and leases

Reconciliation of borrowings arising from financing activities:

	Six Months Ended				Year Ended
	30 June 2021		30 June 2020		31 December 2020
Balance at beginning of period	$	717,240	$	622,288	$	622,288
Proceeds from borrowings	325,500		575,350		799,650
Repayments of borrowings	(416,521)		(456,502)		(705,314)
Costs incurred to secure financing	(204)		(5,780)		(7,799)
Amortisation of discount and deferred financing costs	4,304		3,809		8,334
Cash paid for interest	(18,217)		(17,683)		(34,335)
Finance costs and other	18,218		17,816		34,416
Balance at end of period	$	630,320	$	739,298	$	717,240

Subsequent Events

On 4 August 2021 the Group received commitments from certain lead lenders in its bank syndicate to expand the borrowing base on its Credit Facility from $425,000 to $625,000, subject only to satisfactory documentation.

NOTE 21 - TRADE AND OTHER PAYABLES

The following table includes a detail of trade and other payables. The fair value approximates the carrying value as at the periods presented:

	30 June 2021		31 December 2020
Trade payables	$	19,996	$	19,218
Other payables	19		148
Total trade and other payables	$	20,015	$	19,366

Trade and other payables are unsecured, non-interest bearing and paid as they become due.

NOTE 22 - OTHER LIABILITIES

The following table includes details of other liabilities as at the periods presented:

	30 June 2021		31 December 2020
Other non-current liabilities
Uncertain tax position ^(a)	$	-	$	1,837
Other non-current liabilities ^(b)	9,240		11,023
Total other non-current liabilities	$	9,240	$	12,860
Other current liabilities
Accrued expenses	$	45,088	$	28,582
Taxes payable	16,861		18,025
Net revenue clearing ^(c)	15,147		12,561
Asset retirement obligations - current	1,878		1,882
Revenue to be distributed ^(d)	46,924		30,260
Total other current liabilities	$	125,898	$	91,310

(a) At the date of acquisition, the Directors determined that Alliance Petroleum had taken uncertain tax positions, and as a result, an indemnification agreement was executed. The Group recorded a uncertain tax position liability and indemnification receivable for the amount of $1,837 as at 31 December 2020 During 2021 the statute of limitations associated with the uncertain tax position was met and the Group is no longer subject to potential tax liability associated with the tax position. As a result, the provision for the uncertain tax position and the indemnification receivable were removed.

(b) Other non-current liabilities includes the long-term portion of the contingent consideration for the Carbon and EQT acquisitions as at 31 December 2020.

(d) Revenue to be distributed is revenue that is payable to third-party working interest owners, but has yet to be paid due to title, legal, ownership or other issues. The Group releases the underlying liability as the aforementioned issues become resolved. As the timing of resolution is unknown, the Group records the balance as a current liability.

(b)

NOTE 23 - FAIR VALUE AND FINANCIAL INSTRUMENTS

Fair Value

The fair value of an asset or liability is the price that would be received to sell that asset or paid to transfer that liability in an orderly transaction occurring in the principal market (or most advantageous market in the absence of a principal market) for such asset or liability. In estimating fair value, the Group utilises valuation techniques that are consistent with the market approach, the income approach and/or the cost approach. Such valuation techniques are consistently applied. Inputs to valuation techniques include the assumptions that market participants would use in pricing an asset or liability. IFRS 13, Fair Value Measurement ("IFRS 13"), establishes a fair value hierarchy for valuation inputs that gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The fair value hierarchy is defined as follows:

Level 1: Inputs are unadjusted, quoted prices in active markets for identical assets at the measurement date.

Level 2: Inputs (other than quoted prices included in Level 1 can include the following):

(1) Observable prices in active markets for similar assets;

(2) Prices for identical assets in markets that are not active;

(3) Directly observable market inputs for substantially the full term of the asset; and

(4) Market inputs that are not directly observable but are derived from or corroborated by observable market data.

Level 3: Unobservable inputs which reflect the Directors' best estimates of what market participants would use in pricing the asset at the measurement date.

The carrying values of cash and cash equivalents, trade receivables, other current assets, accounts payable and other current liabilities on the Consolidated Balance Sheet approximate fair value because of their short-term nature. For trade receivables, the Group applies the simplified approach permitted by IFRS 9, Financial Instruments ("IFRS 9"), which requires expected lifetime losses to be recognised from initial recognition of the receivables. Financial liabilities are initially measured at fair value and subsequently measured at amortised cost.

For borrowings, derivative financial instruments, and leases the following methods and assumptions were used to estimate fair value:

Borrowings. The fair values of the Group's ABS I Note, ABS II Note and Term Loan I are considered to be a Level 2 measurement on the fair value hierarchy. The carrying values of the borrowings under the Group's Credit Facility (to the extent utilised) approximates fair value because the interest rate is variable and reflective of market rates. The Group considers the fair value of its Credit Facility to be a Level 1 measurement on the fair value hierarchy.

Derivative Financial Instruments. The Group measures the fair value of its derivative financial instruments based upon a pricing model that utilises market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the LIBOR curve, and volatility factors.

The Group has classified its derivative financial instruments into the fair value hierarchy depending upon the data utilised to determine their fair values. The Group's fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the NYMEX futures index for natural gas and oil derivatives and OPIS for NGLs derivatives. The Group utilises discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Group's interest rate derivative contracts as of 30 June 2021 are based on (i) the contracted notional amounts, (ii) active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

The Group's call options, put options, collars and swaptions (Level 2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness. Inputs to the Black-Scholes model, including the volatility input are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. A change in volatility would result in a change in fair value measurement, respectively.

The Group's basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.

Leases. The Group initially measures the lease liability at the present value of the future lease payments. The lease payments are discounted using the interest rate implicit in the lease. When this rate cannot be readily determined the Group uses its incremental borrowing rate.

Contingent consideration. These liabilities represent the estimated fair value of potential future payments the Group may be required to remit under the terms of historical purchase agreements entered into for asset acquisitions and business combinations. In instances when the contingent consideration relates to the acquisition of a group of assets, the Group records changes in the fair value of the contingent consideration through the basis of the asset acquired rather than through the Consolidated Statement of Comprehensive Income as it does for business combinations. During the six months ended 30 June 2021 the Group recorded $6,348 in revaluations related to contingent consideration associated with assets acquisitions and $5,597 associated with business combinations.

The Group remeasures the fair value of the contingent consideration at each reporting period. This estimate requires assumptions to be made, including forecasting the NYMEX Henry Hub natural gas settlement prices relative to stated floor and target prices in future periods. In determining the fair value of the contingent consideration liability, the Group used the Monte Carlo simulation model, which considers unobservable input variables, representing a Level 3 measurement. The following table represents the impact of a 100 basis point adjustment in the discount rate and commodity price assumptions:

	+100 Basis Points		-100 Basis Points
Assumption sensitivity	$	119	$	(128)

There were no transfers between fair value levels for the six months ended 30 June 2021.

Financial Instruments

The following table includes the Group's financial instruments as at the periods presented:

	30 June 2021		31 December 2020
Cash and cash equivalents at amortised cost	$	3,674	$	1,379
Trade receivables and accrued income at amortised cost	85,772		66,991
Other non-current assets ^(a)	16,249		2,376
Other non-current liabilities ^(b)	(9,240)		(11,023)
Other current liabilities ^(c)	(107,159)		(71,403)
Derivative financial instruments at fair value	(535,716)		(165,807)
Leases	(27,180)		(18,878)
Borrowings	(655,464)		(746,486)
Total	$	(1,229,064)	$	(942,851)

(a) Excludes indemnification receivables.

(b) Excludes uncertain tax positions.

(a)

NOTE 24 - CONTINGENCIES

Litigation and Regulatory Proceedings

The Group is involved in various pending legal issues that have arisen in the normal course of business. The Group accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of 30 June 2021 the Group does not currently have any material amounts accrued related to litigation or regulatory matters. For any matters not accrued for, it is not possible at this time to estimate the amount of any additional loss, or range of loss that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Group's financial position, results of operations or cash flows.

The Group has no other contingent liabilities that would have a material impact on the Group's financial position or results of operations.

Environmental Matters

The Group's operations are subject to environmental regulation in all the jurisdictions in which it operates and was in compliance as of 30 June 2021. The Group is unable to predict the effect of additional environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would adversely affect its operations. The Group can offer no assurance regarding the significance or cost of compliance associated with any such new environmental legislation once implemented.

NOTE 25 - RELATED PARTY TRANSACTIONS

UK Legal Counsel

Martin K. Thomas is a partner at Wedlake Bell LLP, the UK legal advisor to the Group.

	Six Months Ended								Year Ended
	30 June 2021				30 June 2020				31 December 2020
Fees paid to related party legal advisor	$	-	£	-	$	22	£	18	$	41	£	33

NOTE 26 - SUBSEQUENT EVENTS

The Group determined the need to disclose the following material transactions that occurred subsequent to 30 June 2021, which have been described within each relevant footnote as follows:

Description		Footnote
Acquisitions		Note 4
Dividends		Note 17
Borrowings		Note 20

ADDITIONAL INFORMATION

ALTERNATIVE PERFORMANCE MEASURES

DEC uses APMs to improve the comparability of information between reporting periods and to more accurately evaluate cash flows, either by adjusting for uncontrollable or non-recurring factors, or by aggregating measures, to aid the users of this Interim Report in understanding the activity taking place across DEC. APMs are used by the Directors for planning and reporting. The measures are also used in discussions with the investment analyst community and credit rating agencies.

Average Dividend per Share	Average Dividend per Share is reflective of the average of the dividends per share declared throughout the year which gives consideration to changes in dividend rates and changes in the amount of shares outstanding.
	This is a key metric for the Directors as they seek to provide a consistent and reliable dividend to shareholders.

	1H21		1H20		2H20
Declared on first quarter results 2021, 2020 and 2020, respectively	$	0.0400	$	0.0350	$	0.0350
Declared on second quarter results 2021, 2020 and 2020, respectively	0.0400		0.0375		0.0375
Declared on third quarter results 2020, 2019 and 2020, respectively	0.0400		0.0350		0.0400
Declared on fourth quarter results 2020, 2019 and 2020, respectively	0.0400		0.0350		0.0400
TTM Average Dividend per Share	$	0.0400	$	0.0356	$	0.0381
TTM Total Dividends per Share	$	0.1600	$	0.1425	$	0.1525

Adjusted Net Income and Adjusted EPS	As used herein, Adjusted Net Income and Adjusted EPS represent income (loss) available to shareholders after taxation, but exclude mark-to-market adjustments related to DEC's hedge portfolio.
	The Directors believe these metrics are useful to investors because they provide a meaningful measure of DEC's profitability before recording certain items whose timing or amount cannot be reasonably determined.

	1H21		1H20		2H20
Income (loss) available to shareholders after taxation	$	(83,957)	$	18,485	$	(41,959)
Allowance for joint interest owner receivables	-		-		6,931
Gain on bargain purchase	-		-		(17,172)
(Gain) loss on fair value adjustments of unsettled financial instruments	371,458		109,680		129,115
(Gain) loss on natural gas and oil programme and equipment	(234)		-		2,059
Other non-recurring and acquisition related costs	8,849		10,061		14,985
Non-cash equity compensation	3,588		1,506		3,501
(Gain) loss on foreign currency hedge	1,227		-		-
(Gain) loss on interest rate swap	251		-		202
Tax effect on adjusting items ^(a)	$	(97,440)	$	(27,523)	$	(35,085)
Adjusted Net Income	$	203,742	$	112,209	$	62,577

Adjusted EPS - basic	$	0.28	$	0.17	$	0.09
Adjusted EPS - diluted	$	0.28	$	0.17	$	0.09

(a) The tax effect on adjusting items to Adjusted Net Income is calculated using DEC's expected federal and state statutory rates for the periods presented.

(a)

Hedged Adjusted EBITDA and Unhedged Adjusted EBITDA

As used herein, EBITDA represents earnings before interest, taxes, depletion, depreciation and amortisation. Hedged Adjusted EBITDA includes adjustments for non-recurring and non-cash items such as gain on the sale of assets, acquisition related expenses and integration costs, mark-to-market adjustments related to DEC's hedge portfolio, non-cash equity compensation charges and items of a similar nature, while Unhedged Adjusted EBITDA excludes mark-to-market adjustments related to DEC's hedge portfolio

Hedged Adjusted EBITDA and Unhedged 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, the Directors believe it is useful to an investor in evaluating DEC's financial performance because this measure (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 DEC's 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 DEC's Credit Facility financial covenants; and (4) is used by the Directors as a performance measure in determining executive compensation.

	1H21		1H20		2H20
Operating profit (loss)	$	(305,668)	$	(30,780)	$	(46,788)
Depreciation, depletion and amortisation	71,843		55,837		61,453
Loss on joint and working interest owners receivable	-		-		6,931
Gain on bargain purchase	-		-		(17,172)
(Gain) loss on fair value adjustments of unsettled financial instruments	371,458		109,680		129,115
(Gain) loss on natural gas and oil programme and equipment	(234)		-		2,059
Other non-recurring and acquisition related costs	8,849		10,061		14,985
Non-cash equity compensation	3,588		1,506		3,501
(Gain) loss on foreign currency hedge	1,227		-		-
(Gain) loss on interest rate swap	251		-		202
Total adjustments	$	456,982	$	177,084	$	201,074
Hedged Adjusted EBITDA	$	151,314	$	146,304	$	154,286
Less: Cash portion of settled commodity hedges	21,949		(83,506)		(61,094)
Unhedged Adjusted EBITDA	$	173,263	$	62,798	$	93,192

Net Debt and Net Debt-to-Hedged Adjusted EBITDA	As used herein, Net Debt represents total debt as recognised on the balance sheet less cash and restricted cash. Total debt includes DEC's current portion of debt, Credit Facility borrowings and secured financing borrowings. Net Debt is a useful indicator of DEC's leverage and capital structure.
	As used herein, Net Debt-to-Hedged Adjusted EBITDA, or Leverage, is measured as Net Debt divided by pro forma Hedged Adjusted EBITDA. The Directors believe that this metric is a key measure of DEC's financial liquidity and flexibility and is used in the calculation of a key metric in one of DEC's Credit Facility financial covenants.

	1H21		1H20		2H20
Cash	$	3,674	$	6,715	$	1,379
Restricted cash	19,049		16,865		20,350
Credit Facility	(156,500)		(211,300)		(213,400)
ABS I Note	(168,150)		(193,353)		(180,426)
ABS II Note	(180,177)		(200,000)		(191,125)
Term Loan I	(146,786)		(160,000)		(156,805)
Other	(3,851)		(6,398)		(4,730)
Net Debt	$	(632,741)	$	(747,471)	$	(724,757)

Hedged Adjusted EBITDA	$	151,314	$	146,304	$	154,286
Pro forma TTM Hedged Adjusted EBITDA ^(a)	$	339,214	$	345,231	$	330,071

Net Debt-to-Pro forma TTM Hedged Adjusted EBITDA	1.9x		2.2x		2.2x

(a) Pro forma TTM Hedged Adjusted EBITDA includes adjustments for the trailing twelve months ended 30 June 2021 for the Indigo acquisition to pro forma its results for a full twelve months of operations. In this pro forma presentation our adjustment reflects the 100% ownership of Indigo which is consistent with DEC's borrowings as of the 30 June 2021 reporting date.

Similar adjustments were made for the trailing twelve months ended 30 June 2020 for the EQT and Carbon acquisitions as well as in the trailing twelve months ended 31 December 2020 for the EQT, Carbon and Utica Shale acquisitions.

Pro Forma Net Debt-to-Pro Forma TTM Hedged Adjusted EBITDA (inclusive of acquisition activity subsequent to the reporting date)

Given the acquisition activity subsequent to the reporting period, DEC is providing a pro forma leverage calculation, inclusive of the Blackbeard acquisition, DEC's respective 51.25% share of the Tanos acquisition, and the divestiture of 48.75% of the Indigo acquisition in exchange for 50% of the net purchase price, reflecting the joint participation with Oaktree.

The Net Debt position has been pro forma adjusted to reflect the inclusion of the estimated borrowings for the Blackbeard and Tanos transactions as well as the proceeds received from the Indigo divestiture to Oaktree. Hedged Adjusted EBITDA represents the trailing twelve months ended 30 June 2021, pro forma adjusted to include the impact of the ownership of Indigo, Blackbeard and Tanos, and inclusive of Oaktree's participation for the full trailing twelve month period.

	1H21
Net Debt	$	(632,741)
Pro forma adjustments for acquisitions and divestitures	(260,020)
Pro Forma Net Debt	$	(892,761)

TTM Hedged Adjusted EBITDA	$	305,600
Pro forma adjustments for acquisitions and divestitures ^(a)	112,896
Pro Forma TTM Hedged Adjusted EBITDA (inclusive of acquisition activity subsequent to the reporting date)	$	418,496

Pro Forma Net Debt-to-Pro forma TTM Hedged Adjusted EBITDA (inclusive of acquisition activity subsequent to the reporting date)	2.1x

(a) Pro forma adjustments for acquisitions and divestitures were derived from the cumulative $119 million in annualised EBITDA generated by DEC's share of the assets associated with the Indigo, Blackbeard and Tanos transactions utilising consolidated actual Indigo and Tanos assets' pricing, production, and expense for the first quarter of 2021. The pro forma annualised EBITDA for the Blackbeard assets is based on consolidated actual Blackbeard asset's pricing for the first quarter of 2021 and production and expense for the fourth quarter of 2020, due to the severe weather-related disruptions in Texas in the first quarter of 2021. Indigo, Blackbeard and Tanos assets' pro forma annualised EBITDA is not intended in any way to constitute a projection of actual results attributable to the Indigo, Blackbeard and Tanos assets. The cumulative $119 million in pro forma annualised EBITDA was then reduced by the EBITDA earned in May and June of 2021 associated with the Indigo acquisition, which is included in DEC's results for the six months ended 30 June 2021.

(a)

Hedged Adjusted EBITDA per Share	The Directors believe that Hedged Adjusted EBITDA per Share provides direct line of sight into DEC's ability to measure the accretive growth we seek to acquire while providing shareholders with a depiction of cash earnings at the share level.
	In this calculation we utilise weighted average shares as to not disproportionately weight the calculation for equity issued for acquisitive growth at varying periods throughout the year.

	1H21		1H20		2H20
Weighted average shares outstanding - diluted	740,682		667,293		711,324
Hedged Adjusted EBITDA	$	151,314	$	146,304	$	154,286
Hedged Adjusted EBITDA per Share	$	0.20	$	0.22	$	0.22

Adjusted Total Revenue	As used herein, Adjusted Total Revenue includes the impact of derivatives settled in cash. The Directors believe that Adjusted Total Revenue is a useful measure because it enables investors to discern DEC's realised revenue after adjusting for the settlement of derivative contracts.
Cash Operating Margin	As used herein, Cash Operating Margin is measured by reducing Adjusted Total Revenue for operating expenses. The resulting margin on Cash Operating Income is considered DEC's Cash Operating Margin. The Directors believe that Cash Operating Margin is a useful measure of DEC's profitability and efficiency as well as its earnings quality.
Cash Margin	As used herein, Cash Margin is measured as Hedged Adjusted EBITDA, as a percentage of Adjusted Total Revenue. The key distinction between Cash Operating Margin and Cash Margin is the inclusion of Adjusted G&A. The Directors believe that Cash Margin is a useful measure of DEC's profitability and efficiency as well as its earnings quality.

	1H21			1H20			2H20
Total revenue	$	323,316		$	184,878		$	223,815
Commodity hedge impact	(21,949)			83,506			61,094
Adjusted Total Revenue	$	301,367		$	268,384		$	284,909
LESS: Operating expense	(119,555)			(98,951)			(105,012)
Total Cash Operating Income	$	181,812		$	169,433		$	179,897
LESS: Adjusted G&A	(29,896)			(22,529)			(24,652)
LESS: Allowance for credit losses - recurring	(602)			(600)			(959)
Hedged Adjusted EBITDA	$	151,314		$	146,304		$	154,286

Cash Margin	50		%	55		%	54		%
Cash Operating Margin	60		%	63		%	63		%

Free Cash Flow and

Free Cash Flow Yield

As used herein, Free Cash Flow represents Hedged Adjusted EBITDA less recurring capital expenditures, asset retirement costs, cash interest expense and cash paid for income taxes. The Directors believe that Free Cash Flow is a useful indicator of DEC's ability to internally fund its activities and to service or incur additional debt.

As used herein, Free Cash Flow Yield represents Free Cash Flow as a percentage of DEC's total market capitalisation. The Directors believe that, like Free Cash Flow, Free Cash Flow Yield is an indicator of financial stability and reflects DEC's operating strength relative to its size as measured by market capitalisation.

	1H21			1H20			2H20
Hedged Adjusted EBITDA	$	151,314		$	146,304		$	154,286
LESS: Recurring capital expenditures	(7,522)			(8,208)			(7,773)
LESS: Plugging and abandonment costs	(1,180)			(1,201)			(1,241)
LESS: Cash interest expense	(18,217)			(17,683)			(16,652)
LESS: Cash paid for income taxes	(7,607)			(130)			(5,720)
Free Cash Flow	$	116,788		$	119,082		$	122,900

Average share price	$	1.55		$	1.13		$	1.35
Weighted average shares outstanding - diluted	740,682			667,293			711,324
Free Cash Flow Yield	10		%	16		%	13		%
TTM Free Cash Flow Yield	23		%	31		%	29		%

Total Cash Cost per Boe

Total Cash Cost per Boe is a metric which allows us to measure the cumulative operating cost it takes to produce each Boe. This metric includes operating expense and Adjusted G&A, both of which include fixed and variable cost components.

	1H21		1H20		2H20
Total production (MBoe)	19,133		17,317		19,221

Total operating expense	$	119,555	$	98,951	$	105,012
Adjusted G&A	30,498		23,129		25,611
Total Cash Cost	$	150,053	$	122,080	$	130,623

Total Cash Cost per Boe	$	7.84	$	7.05	$	6.80

Base G&A	As used herein, Base G&A represents total administrative expenses excluding non-recurring and/or non-cash acquisition and integration costs. The Directors use Base G&A because this measure excludes items that affect the comparability of results or that are not indicative of trends in the ongoing business.
Adjusted G&A	As used herein, Adjusted G&A represents Base G&A plus recurring allowances for expected credit losses. The Directors use Adjusted G&A because this measure excludes items that affect the comparability of results or that are not indicative of trends in the ongoing business.

	1H21		1H20		2H20
Total G&A	$	42,333	$	34,096	$	43,138
LESS: Non-recurring and/or non-cash G&A ^(a)	(12,437)		(11,567)		(18,486)
Base G&A ^(b)	$	29,896	$	22,529	$	24,652
Recurring allowance for expected credit losses	602		600		959
Adjusted G&A ^(c)	$	30,498	$	23,129	25,611

(a) Non-recurring and/or non-cash G&A includes costs related to acquisitions, DEC's up-list to the main market in 2020, and one-time projects.

(b) Base G&A includes payroll and benefits for our corporate and administrative staff, costs of maintaining corporate and administrative offices, costs of managing our production operations, franchise taxes, public company costs, non-cash equity issuance, fees for audit and other professional services, and legal compliance.

(a)

GLOSSARY OF TERMS

1H20		First-half 2020, or the six month period ended 20 June 2020
1H21		First-half 2021, or the six month period ended 30 June 2021
2H20		Second-half 2020, or the six month period ended 31 December 2020
£		British pound sterling
$		US dollar
Adjusted EBITDA		Adjusted EBITDA is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Adjusted EPS		Adjusted EPS is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Adjusted G&A		Adjusted G&A is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Adjusted Net Income		Adjusted Net Income is an APM. Please refer to the APM section in Additional Information within this Annual Report for information on how this metric is calculated and reconciled to IFRS measures.
Adjusted Total Revenue		Adjusted Total Revenue is an APM. Please refer to the APM section in Additional Information within this Annual Report for information on how this metric is calculated and reconciled to IFRS measures.
AIM		Alternative Investment Market
APM		Alternative Performance Measure
Average Dividend per Share		Average Dividend per Share is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Base G&A		Base G&A is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Base LOE		Base lease operating expense is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.
Bbl		Barrel or barrels of oil or natural gas liquids
Bcfe		Billions of cubic feet equivalent
Board		Board of Directors
Boe		Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
Boepd		Barrels of oil equivalent per day
Btu		A British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
Cash Margin		Cash Margin is an APM. Please refer to the APM section in Additional Information within this Annual Report for information on how this metric is calculated and reconciled to IFRS measures.
Cash Operating Margin		Cash Operating Margin is an APM. Please refer to the APM section in Additional Information within this Annual Report for information on how this metric is calculated and reconciled to IFRS measures.
DD&A		Depreciation, depletion and amortisation
E&P		Exploration and production
EBITDA		Earnings before interest, tax, depreciation and amortisation
EPS		Earnings per share
ERM		Enterprise Risk Management
EU		European Union
Free Cash Flow		Free Cash Flow is an APM. Please refer to the APM section in Additional Information within this Annual Report for information on how this metric is calculated and reconciled to IFRS measures.
Free Cash Flow Yield		Free Cash Flow Yield is an APM. Please refer to the APM section in Additional Information within this Annual Report for information on how this metric is calculated and reconciled to IFRS measures.
FTSE		Financial Times Stock Exchange
G&A		General and administrative expense
GBP		British pound sterling
Hedged Adjusted EBITDA		Hedged Adjusted EBITDA is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Hedged Adjusted EBITDA Per Share		Hedged Adjusted EBITDA per Share is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Henry Hub		A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
IAS		International Accounting Standard
IASB		International Accounting Standards Board
IFRS		International Financial Reporting Standards as adopted by the EU
LIBOR		London Inter-bank Offered Rate
LOE		Lease operating expense is defined as Base LOE, plus owned midstream operating expense, third-party transportation expense, and production taxes.
LSE		London Stock Exchange
MBbls		Thousand barrels
MBoe		Thousand barrels of oil equivalent
Mcf		Thousand cubic feet of natural gas
Mcfe		Thousand cubic feet of natural gas equivalent
Midstream		Midstream activities include the processing, storing, transporting and marketing of natural gas, NGLs and oil.
MMBoe		Million barrels of oil equivalent
MMBtu		Million British thermal units
MMcf		Million cubic feet of natural gas
Mont Belvieu		A mature trading hub with a high level of liquidity and transparency that sets spot and futures prices for NGLs.
Net Debt		Net Debt is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Net Debt-to-Hedged Adjusted EBITDA		Net Debt-to-Hedged Adjusted EBITDA is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
NGLs		Natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.
NYMEX		New York Mercantile Exchange
Oil		Includes crude oil and condensate
OPIS		Oil Price Information Service
Pro Forma TTM Hedged Adjusted EBITDA		Pro Forma Hedged Adjusted EBITDA is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Pro Forma Net Debt-to-Pro Forma TTM Hedged Adjusted EBITDA (inclusive of acquisition activity subsequent to the reporting date)		Pro Forma Net Debt-to-Pro Forma TTM Hedged Adjusted EBITDA (inclusive of acquisition activity subsequent to the reporting date) is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
PV-10		A calculation of the present value of estimated future natural gas and oil revenues, net of forecasted direct expenses, and discounted at an annual rate of 10%.
Realised price		The cash market price less all expected quality, transportation and demand adjustments.
TCFD		Task Force on Climate-Related Financial Disclosures
Total Cash Cost		Total Cash Cost is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
Total Cash Cost per Boe		Total Cash Cost per Boe is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
TTM		Trailing twelve months
Unhedged Adjusted EBITDA		Unhedged Adjusted EBITDA is an APM. Please refer to the APM section in Additional Information within this Interim Report for information on how this metric is calculated and reconciled to IFRS measures.
UK		United Kingdom
US		United States
USD		US dollar
WTI		West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

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