Final Results for the Year Ended 31 December 2020

RNS Number : 4573R

Diversified Gas & Oil PLC

08 March 2021

8 March 2021

DIVERSIFIED GAS & OIL PLC

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

Final Results for the Year Ended 31 December 2020

Diversified Gas & Oil PLC (LSE: DGOC) is pleased to announce its annual results for the full-year ended 31 December 2020.

Key Highlights

• December exit rate production of 103 MBoepd (617 MMcfepd), 8% higher than 2019 exit (95 MBoepd)

◦ Exceptionally low corporate annual decline rate of ~7% including both conventional and unconventional wells

◦ DGO stands as the largest independent producer on the London Stock Exchange ("LSE")

• Hedged Adjusted EBITDA¹ of $301 million (up 10% over $273 million in 2019) bolstered by hedge cash settlements of $145 million that significantly offset low natural gas prices

◦ Indicative of the improved natural gas pricing outlook that creates a non-cash pre-tax mark-to-market hedge valuation loss of $239 million, the Group reported a net loss of $23 million in 2020 (2019: $99 million net income inclusive of a pre-tax non-cash mark-to-market hedge valuation gain of $20 million)

◦ Adjusted Net Income of $175 million represents an 83% increase over prior year (2019: $96 million) and excludes the mark-to-market valuation change and other non-cash and non-recurring items

• Adjusted Total Revenue (which includes $145 million of cash hedge settlements) of $553 million was 8% higher in 2020 vs 2019 ($512 million including $49 million of hedge cash settlements)

◦ Total revenue (which excludes hedge settlements) of $409 million in 2020 vs. $462 million in 2019 due to lower commodity prices in 2020 partially offset by higher production from our acquired production (Carbon and EQT assets)

• Cash Margin¹ of 54% driven by a 10% reduction in total cash expenses² to $1.15/Mcfe ($6.92/Boe) and hedge cash settlements

• Dividend increased >14% with two consecutive quarterly raises during 2020

• Recommending a final quarterly dividend of $0.04/share, bringing the full-year 2020 dividend to $0.1525/share, 10% higher than 2019 ($0.1392/share), supported by accretive growth of its low-decline, long-life assets

Other Operational Highlights

• Record full-year average daily net production of ~100 MBoepd, up 18% vs 2019 (85 MBoepd)

◦ Average daily production from conventional (Legacy³) assets consistent with 2019 at ~69 MBoepd reflective of effective Smarter Asset Management

• Acquired and fully integrated ~$243 million (gross) of assets which expand scale and reduce unit costs:

◦ May 2020 conventional upstream and midstream assets from Carbon ($110 million) and primarily unconventional upstream assets from EQT ($125 million)

◦ 4Q20 acquisition of five unconventional wells in Ohio for $8 million

• ESG enhancements included broader leak detection and repair programme and progress on further refining the Group's comprehensive facilities inventory contributing to lower reported emissions

• Exceeded our 80-well annual well retirement commitment by retiring 92 wells averaging ~$25K each

◦ Proactively worked with regulators in Ohio to extend our retirement agreement to 10-year term

Other Financial Highlights

• Remain proactive and opportunistic to protect cash flows and provide dividend stability through hedging:

◦ ~90% of 2020 production protected by natural gas hedges, with current forward hedge positions including:

▪ ~90% of 2021 natural gas hedged at a weighted average floor price of $2.94/Mcfe ($2.67/MMBtu)

▪ ~65% of 1H2022 natural gas hedged at a weighted average floor price of $2.84/Mcfe ($2.59/MMBtu)

• Significant field operating efficiencies reduced total unit cash costs inclusive of higher Adjusted G&A¹. The additional administrative expense supports the enlarged business, positions the Group with a scalable corporate platform for additional growth and reflects enhanced corporate governance following its transition from AIM to the Premium Segment of the Main Market:

◦ Base lease operating expense down 24%: $0.42/Mcfe ($2.53/Boe) (2019: $0.55/Mcfe ($3.31/Boe)

◦ Total operating expense down 15%: $0.93/Mcfe ($5.58/Boe) (2019: $1.09/Mcfe ($6.54/Boe)

◦ Adjusted G&A¹ expense up 14%: $0.22/Mcfe ($1.33/Boe) (2019: $0.19/Mcfe ($1.17/Boe)

• Distributions benefiting shareholders in 2020 totalled $115 million

◦ Dividends paid in 2020: $99 million ($0.1425/share), up 5% (2019: $0.1362/share)

◦ Share repurchases: $16 million (~13 million shares) (2019: $53 million)

• Net Debt of $725 million resulting in Net Debt-to-Hedged Adjusted EBITDA¹ of 2.2x at 31 December 2020

◦ Debt reductions in 2020, adjusted for acquisitions, total $82 million, driven largely by repayments of scheduled amortising debt structures

• Year-end liquidity >$210 million

◦ Full reaffirmation of $425 million borrowing base twice during 2020, despite volatile commodity price market, with no changes to terms and full support of 17 lenders in the Credit Facility

Corporate Highlights

• Successful move to the Main Market of the London Stock Exchange

• Inclusion in FTSE250 Index

• Established strategic partnership with Oaktree Capital Management, L.P. who committed $1 billion to jointly identify and fund future proved developed producing ("PDP") acquisition opportunities as a non-operating working interest partner

◦ For completed acquisitions, the Agreement compensates DGO through an upfront promote and includes reversion interest opportunities to the Group

• Successful financings support growth platform: $200 million (gross) asset securitisation to term out a portion of the Group's revolving Credit Facility and the combination of an $85 million (gross) share placing and $160 million (gross) 10-year amortising secured term loan to primarily fund acquisitions during 2020

• Significant ESG initiatives reflect stewardship emphasis and transparency:

◦ Published inaugural year 2019 Sustainability Report with plans to issue the Group's 2020 Sustainability Report in April 2021

◦ Initiated comprehensive Enterprise Risk Management reviews

◦ Initiated Task Force for Climate-related Disclosure reporting practices

◦ Adopted new corporate policies on human rights, environmental, health and safety and corporate responsibility

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

2 Total cash expenses represent total operating expense plus recurring general and administrative costs. Total operating expense includes base lease operating expense, production taxes, midstream operating expense and transportation expense. Recurring administrative expenses is a non-IFRS financial measure defined as total administrative expenses excluding non-recurring acquisition & integration costs and non-cash equity compensation.

3 Legacy Assets owned as at 31 December 2018 and excluding the Group's 2020 acquisitions of Carbon and EQT and 2019 acquisitions of HG Energy and EdgeMarc.

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

"I am exceptionally pleased with our results in 2020 as they reflect the resilience of our business model and its proven ability to consistently deliver shareholder value and returns, even in the most challenging of markets. Our commitment to value-accretive growth, operational excellence, cost discipline, and risk mitigation drove the Group's solid performance through turbulent times. Our long-standing strategy of focusing on low-risk assets and reliable cash flows position DGO for further growth, and enables us to maintain our firm commitment to shareholder returns, evidenced by the increase in our per-share dividend, which we raised twice, or 14%, during the year.

"With a business model grounded in asset and environmental stewardship, we made significant strides in developing plans and adopting disclosure frameworks aimed at improving our environmental footprint. Additionally, we strengthened our track record of accretive growth with the successful acquisitions of both upstream and midstream assets, contributing to a consistent, strong cash margin and enlarging our portfolio of Smarter Asset Management opportunities on a base of assets with an exceptionally low corporate decline rate of ~7%. Our commitment to acquire low-decline assets enables us to replace production declines with approximately 10% of our Adjusted EBITDA while meeting our operating and ESG commitments, reducing our debt and making consistent quarterly dividend payments to shareholders.

"Our move in May 2020 to the premium segment of the Main Market and subsequent inclusion in FTSE250 reflects the evolution of our business and enables us to solidify our position as the leading independent producer on the LSE. Even so, with the shifting market dynamics of the last few years, we are seeing a generational opportunity to accelerate our accretive consolidation strategy, and our strategic partnership with Oaktree Capital uniquely positions us to capitalise on these opportunities, whether within or outside the Appalachian Basin. The positive fundamentals and outlook for US natural gas are creating a supportive tailwind, which gives us confidence in our ability to sustain our dividend and create value for our stakeholders."

Results Presentation and Audiocasts

DGO will host a conference call today at 2:00pm GMT (9:00am 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		www.dgoc.com/news-events/events
Replay Information		https://ir.dgoc.com/financial-info

Additionally, on 10 March 2021 at 6:00pm GMT (1:00pm EST), DGO is pleased to host an investor webinar featuring CEO Rusty Hutson, COO Brad Gray and CFO Eric Williams during which management will discuss the full-year results. To register for the webinar, please contact Yellowstone Advisory at info@yellowstoneadvisory.com, or refer to the following link:

https://us02web.zoom.us/webinar/register/5816106105281/WN_u6UZAWCXTXaT_8uqF9rPEg

Diversified Gas & Oil PLC	+	1 (205) 408 0909
Teresa Odom, Vice President, Investor Relations
www.dgoc.com
ir@dgoc.com

Buchanan	+	44 (0)20 7466 5000
Financial Public Relations
Ben Romney
Chris Judd
Kelsey Traynor
James Husband
dgo@buchanan.uk.com

About Diversified Gas & Oil PLC

Diversified Gas & Oil 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.

CHAIRMAN'S STATEMENT

I am delighted to report another year of tremendous progress for the Group. Against both a challenging industry backdrop and the extraordinary impact of the Covid-19 pandemic, our business model has proven not only to be resilient and sustainable but also extremely strong.

We have continued with the relentless focus on our strategy to deliver consistent, profitable cash flow from our low-cost asset base. During the year we made three accretive acquisitions which have been successfully integrated. We also enhanced our borrowing base with a securitised and fully-amortising financing, and entered into an innovative joint arrangement with Oaktree Capital, which positions us well for future acquisitions earning enhanced returns. Our Smarter Asset Management programme has once again been effective in maintaining steady production to offset natural declines.

We successfully obtained admission of our shares to the Premium Listing Segment of the Official List of the Financial Conduct Authority and to trading on the Main Market of the LSE, and subsequently entered the LSE FTSE 250 Index. In advance of this move, and as reported last year, we appointed three new Independent Non-Executive Directors to the Board. The current Board has seven members, with four being independent. I am extremely pleased with how the Board and Committees have functioned this year, in particular given the difficulties of meeting in person. Each Board member demonstrated a clear commitment to the Group and support for its strategy while being willing to challenge each other as we strive to continue building a business that benefits all stakeholders. We appointed Leadership Advisor Group to conduct an external Board Performance Review, and we will use their advice to further examine our corporate governance and strategic thinking. At present, two of our seven Board members (or approximately 30%) are women. We are mindful of the recommendations of the Hampton-Alexander Review and the Parker Review, and will be looking to comply with them in the coming year as we strive to further enhance our Board's diversity, experience, and knowledge base.

During the year we launched our inaugural Sustainability Report which detailed the economic, environmental, social and governance impacts of our activities. The report describes our firm commitment to sustainability and to the communities in which we operate and outlines our plans to remain fully engaged on these important initiatives. We also embarked on a project with Critical Resource, a global consultancy focused on climate strategies, to ensure that our metrics and targets, as well as our governance, risk management, and strategic planning align with the Task Force on Climate Related Financial Disclosures ("TCFD") recommendations. Additionally, we are examining investments in technology and operational changes to help further reduce emissions, as well as evaluating various offset measures with our target to achieve a net zero carbon footprint by 2050. You can find additional details of our ongoing sustainability efforts in our upcoming 2020 Sustainability Report.

We fully support the desire to reduce the world's carbon emissions, and believe that our unique business model continues to be well positioned to help us do so. Natural gas in the US has been a major contributor to the substantial reductions in CO2 emissions as energy supplies have switched from coal and oil. Future energy demands must be met from multiple sources, including renewables, nuclear, hydro, and our own low-carbon natural gas, which will continue to be affordable and reliable. As such, we believe that natural gas is an ideal partner to renewable energy sources like wind and solar, thereby providing a solution to a more sustainable world for future generations.

Our business model is based on sustainability. We are one of the lowest cost operators in the industry, and we are well positioned to perform in even the toughest of markets. We acquire undervalued assets, that are non-core to other operators, and then focus on optimising their productivity or usefulness until the end of their natural lives. We are responsible operators with a commitment to the safety of our employees and the public at large, the well-being and vibrancy of the communities in which we live and work, and the care of the natural world around us. This is what we do. As we acquire more assets, we believe we can play a key role in improving the environmental stewardship of them, as well as reducing the need for further exploration and drilling elsewhere, with its resultant impact on emissions and risk of stranded assets. We also continue to embrace our responsibility to safely retire wells at the end of their productive lives, and we've demonstrated this commitment to the states in which we operate each year through our exceptional well retirement programme.

Our extensive hedge portfolio and low-cost debt profile has meant that our cash flow has remained stable and strong this year. Combined with our accretive acquisitions, we increased our quarterly dividend twice, and by 14% since the start of the year from $0.0350 per share to $0.0400 per share. Accordingly, the Board is recommending a final quarter dividend of $0.0400 per share, making the total dividend attributable to the full-year $0.1525 per share (2019: $0.1392 per share.) If approved, the final dividend will be paid on 24 June 2021 to those shareholders on the register on 28 May 2021.

This year was another very successful one for DGO, and I would like to thank our executive team and all our employees for the hard work and dedication that continues to drive our performance. They represent the best in our industry and are a credit to the Group. We understand the extraordinary impacts of the Covid-19 pandemic on the personal lives of our employees and recognise that their continued commitment has ensured we have not only delivered a successful 2020 but are well positioned to continue to deliver the long term sustainable success of our business. I also wish to thank our shareholders, debt holders and other stakeholders for their support. Looking ahead, the opportunities to continue our growth are significant, and we are well placed to capitalise on them. We along with the entire Diversified team will remain focused in 2021 and beyond on our strategy and continue to deliver sustainable value to our shareholders.

David E. Johnson

Chairman of the Board

CHIEF EXECUTIVE'S STATEMENT

This past year was unlike any other in the history of our company. In a year filled with global uncertainty, driven largely by the Covid-19 pandemic, political unrest and economic disruption, which led to the lowest NYMEX natural gas prices in 25 years, our consistent performance and the strength of our business model proved among the few certainties. From our founding nearly 20 years ago, we've proactively and intentionally built our business to reliably perform in any commodity price environment, and the result of our strategic actions is demonstrated through our ability to deliver significant financial results contrary to sector and macro-economic headwinds. Deemed an essential business in the midst of the pandemic, our company continues to successfully navigate the new economic and social environment in which we now find ourselves. Our success is reflective of a resilient, vertically integrated business model and strategy executed by dedicated personnel, who are focused on delivering strong operational and financial results, resulting in significant shareholder value.

Our resilience demonstrates the solid foundations upon which DGO is built. Our unwavering focus on opportunistic yet disciplined acquisitive growth, portfolio optimisation and shareholder returns differentiates us from our peers. The Board's commitment to shareholder returns is resolved and represents a core principle of our strategy and investment thesis. Currently, our dividend yield is one of the most compelling amongst LSE listed companies, evidenced by two dividend increases during a period when many of our peers reduced or cancelled dividends, highlighting the strength of our business model and the effectiveness of our execution.

A relentless focus on operational excellence across our portfolio continues to serve as the bedrock of our stable performance. During the year, our operations team delivered impressive results through the successful application of our Smarter Asset Management programme. Production remained steady throughout the year as we effectively offset natural declines in our portfolio through our operational techniques to optimise production and to drive efficiency, and we achieved this result while simultaneously reducing our emissions. These effective operations continue to drive solid financial performance by ensuring we remain a low-cost operator with clear visibility to reliable cash flows. The capabilities of our midstream activities continue to expand and were further bolstered by the acquisitions in May, which increased opportunities for margin-enhancing diversification, pricing optionality and third-party revenue generation.

Even with the recovery and stabilisation of prices through the fourth quarter of 2020 and into the start of 2021, the market backdrop remains challenging for the natural gas industry. Despite these headwinds, our business model gives us comfort, knowing that we are uniquely positioned to make the most of the numerous opportunities we see in the market today.

Positive momentum is building for natural gas pricing which bodes well for our business. For many however, the positive momentum may have come too late, and consolidation will be a natural consequence. As a result, we continue to evaluate a robust acquisition pipeline as we look to capitalise on market opportunities, seeking value accretive growth.

With this backdrop, we established a major strategic partnership through our agreement with Oaktree Capital. The agreement aligns us with a strong partner with whom we can capitalise on the growing pipeline of opportunities, both in the near-term and over the long-term. The agreement validates our strategy, and helps to expand our market intelligence and network through Oaktree's unrivalled standing in the market. The partnership also strengthens our acquisition bid credibility, and enables us to comfortably pursue larger transactions that can deliver a measurable change in accretive cash flow growth and shareholder returns. The deal structure positions us to capture long-term value for our shareholders as Oaktree's co-ownership of assets presents a foreseeable inventory of acquisition opportunities whereby DGO, as the operator of those assets, is the natural buyer when Oaktree seeks to monetise its investment.

The strong position that we have established for ourself through years of delivering results aligned with our stated commitments leaves us well placed to maintain our growth trajectory. Financial discipline at the corporate and operational levels remains a key tenet to our strategy. We will seek to continue to maintain a healthy balance sheet with appropriate liquidity to safeguard our dividend, and reduce Leverage while working to capture prudent growth opportunities.

I am very proud that we have been able to maintain our progress through the economic and social challenges we faced during the last year. The Board's focus on continuous improvement of all aspects of governance has enabled us to take considerable strides forward and provides a springboard for future growth. Our move to the Main Market and subsequent inclusion in the FTSE 250 Index reflects our evolution, maturity and growth into the largest independent producer by volume on the London market, and I am excited for the opportunities that lie ahead for our company.

Robert R. ("Rusty") Hutson Jr.

Chief Executive Officer

FINANCIAL REVIEW

A MESSAGE FROM OUR CHIEF FINANCIAL OFFICER

We have spoken to the challenges and opportunities that 2020 presented to companies across all sectors. I echo Rusty's pride in our dedicated and talented employees who delivered exceptional results. In a year marked by uncertainty and unprecedented commodity demand and price volatility, we steadied ourselves, remained focused on our strategic objectives and used the many tools within our chest to advance our business while many companies around us struggled. Ultimately, we achieved record production and Hedged Adjusted EBITDA, closed three acquisitions, repaid borrowings, and raised our dividend twice… all during a pandemic and amidst the lowest natural gas commodity price environment we have seen in the past two decades.

By design, we built Diversified to be resilient in even the most challenging environments. Our strategy to acquire and nurture mature producing assets not only affords us a stable positive Free Cash Flow profile, but importantly it provides us with a highly predictable and largely controllable cost structure that we can comfortably hedge to secure healthy margins. If any series of events were to reinforce the importance of responsible hedging, it was those we witnessed during 2020, when we observed even the largest, investment-grade established names within our industry dramatically cut spending, reduce staffing, increase borrowings and lower - or even eliminate - their dividends to shareholders. By contrast, we not only expanded our team as we added additional high-quality producing assets to our portfolio, but we also responsibly managed our debt and increased our quarterly dividend twice and by over 14% to $0.04 per share or $0.16 per share annualised. In fact, since our IPO four years ago and demonstrating the true accretive nature of our growth, we have increased our per-share dividend nine times and grown it by nearly 70% compounded annually.

The past few years, and 2020 in particular, have reinforced the importance of hedging, which you have come to appreciate is part of our strategic DNA. Our hedge portfolio extends more than a decade to support each of our long-term, fixed rate and fully amortising financing structures, which today comprise approximately 70% of our total borrowings. We were rewarded handsomely for our decision to hedge approximately 90% of our natural gas production this year, receiving nearly $145 million in hedge proceeds that significantly adds to our $409 million of total revenue. Not only were we able to fund our growth, reduce our borrowings adjusting for acquisitions and maintain a strong balance sheet, we also paid $99 million of dividend distributions to our shareholders and repurchased $16 million of our outstanding shares.Recognising that acquiring quality producing assets, rather than drilling and completing wells, fuels our growth, we actively manage our balance sheet by using a prudent mix of debt and equity financing to maintain Leverage below our stated limit of 2.5x Net Debt-to-Hedged Adjusted EBITDA. In fact, we ended 2020 and sit today at just 2.2x. During 2020, we were rewarded for our fiscal discipline with investors willing to entrust additional debt and equity growth capital to DGO when others had no access. We also enjoy a healthy and supportive bank group and lenders like Munich Re and Nuveen, a TIAA company. Not only did we term-out $200 million of borrowings on our Credit Facility through a low-cost asset-backed securitisation, we successfully raised $160 million of long-term financings and $85 million of equity proceeds to fund our acquisition of assets from EQT Corporation, Carbon Energy Corporation and other sellers. We also exited the year strong with a full re-affirmation of our $425 million Credit Facility borrowing base and more than $210 million of liquidity.

Importantly, we enter 2021 with optimism underpinned by our past success, lean operating costs, solid financial footing and an enhanced platform following investments in people, processes and technology to become a Premium Listed, Main Market company. We are further encouraged to see higher commodity prices on the forward curve as positive sentiment regarding natural gas' longer-term outlook creates an improved price outlook. This optimism is particularly impactful to us since natural gas comprises over 91% of our production. In a higher price environment, not only will we realise the full value of the hedged prices we locked as part of our commitment to protect our cash flow, we'll also benefit from higher market prices on our unhedged volumes.

As I turn to a discussion of our reported earnings, it is important to link the positive price momentum I discussed to its associated earnings impact. As we adjust our 10+ year derivative portfolio to their fair values, we recognised a $239 million non-cash charge that we report in our earnings, which represents the change in the fair value of our entire unsettled hedge portfolio from 31 December 2019 to 31 December 2020. This non-cash valuation change primarily relates to higher prices on the forward price curve for natural gas, and drives our $87 million gross profit into a $137 million pre-tax loss. When excluding this non-cash loss, just as we have excluded our valuation-related non-cash gains in prior years, we report a $102 million pre-tax gain compared to $131 million in 2019. Ultimately, while we report a net loss in 2020 of $24 million compared to net income in 2019 of $99 million, we grew Hedged Adjusted EBITDA by 10% to $301 million compared to $273 million in 2019.

Protecting our cash flow and its payment of dividends and debt will always be paramount. While hedging may, at times, cause us to forgo upside to commodity prices, we believe our shareholders and lenders value the high visibility into our distributions that hedging affords us. Importantly and as I mentioned earlier, not only do we stand to earn a healthy Cash Margin in 2021 from our natural gas hedges' weighted average floor price of $2.93 per Mcf compared to Total Cash Cost per Mcfe $1.15 ($6.92 per Boe), but should prices settle higher than this value, the earnings and cash flow on our unhedged volumes will increase. You will find the full financial results of our operations in the following pages, which I hope will be helpful as you review our performance.

In summary, 2021 is shaping up to be another exceptional year for Diversified, and I look forward to serving alongside a team eager to deliver the same excellence you have come to expect from us.

Eric Williams

Chief Financial Officer

RESULTS OF OPERATIONS

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

	Year Ended
	31 December 2020			31 December 2019			Change		% Change
Net production
Natural gas (MMcf)	199,667			166,377			33,290		20	%
NGLs (MBbls)	2,843			2,807			36		1	%
Oil (MBbls)	417			407			10		2	%
Total production (MBoe)	36,538			30,944			5,594		18	%
Average daily production (Boepd)	99,831			84,778			15,053		18	%
% Natural gas (Boe basis)	91		%	90		%
Average realised sales price
(excluding impact of derivatives settled in cash)
Natural gas (Mcf)	$	1.72		$	2.31		$	(0.59)	(26)	%
NGLs (Bbls)	8.15			12.00			(3.85)		(32)	%
Oil (Bbls)	36.12			50.30			(14.18)		(28)	%
Total (Boe)	$	10.45		$	14.16		$	(3.71)	(26)	%
Average realised sales price
(including impact of derivatives settled in cash)
Natural gas (Mcf)	$	2.33		$	2.47		$	(0.14)	(6)	%
NGLs (Bbls)	13.95			19.91			(5.96)		(30)	%
Oil (Bbls)	52.97			49.74			3.23		6	%
Total (Boe)	$	14.40		$	15.76		$	(1.36)	(9)	%
Revenue (in thousands)
Natural gas	$	343,425		$	384,121		$	(40,696)	(11)	%
NGLs	23,173			33,685			(10,512)		(31)	%
Oil	15,064			20,474			(5,410)		(26)	%
Total commodity revenue	$	381,662		$	438,280		$	(56,618)	(13)	%
Midstream revenue	25,389			22,166			3,223		15	%
Other revenue	1,642			1,810			(168)		(9)	%
Total revenue	$	408,693		$	462,256		$	(53,563)	(12)	%
Gain (loss) on derivative settlements
(in thousands)
Natural gas	$	121,077		$	27,483		$	93,594	341	%
NGLs	16,498			22,214			(5,716)		(26)	%
Oil	7,025			(230)			7,255		(3154)	%
Net gain (loss) on derivative settlements	$	144,600		$	49,467		$	95,133	192	%

Adjusted Total Revenue	$	553,293		$	511,723		$	41,570	8.1	%

Per Boe metrics
Average realised sales price
(including impact of derivatives settled in cash)	$	14.40		$	15.76		$	(1.36)	(9)	%
Other revenue	0.74			0.77			(0.03)		(4)	%
Base lease operating expense	2.53			3.31			(0.78)		(24)	%
Midstream operating expense	1.45			1.42			0.03		2	%
Adjusted G&A	1.33			1.17			0.16		14	%
Production taxes	0.38			0.53			(0.15)		(28)	%
Transportation expense	1.24			1.28			(0.04)		(3)	%
Operating margin	$	8.21		$	8.82		$	(0.61)	(7)	%
% Operating margin	54		%	53		%

Other financial metrics (in thousands)
Adjusted Net Income	$	174,786		$	95,618		$	79,168	82.8	%
Operating profit (loss)	$	(77,568)		$	180,507		$	(258,075)	(143)	%
Income (loss) available to shareholders after taxation	$	(23,474)		$	99,400		$	(122,874)	(124)	%

Production, Revenue and Hedging

Total revenue in the year ended 31 December 2020 of $409 million decreased 12% from $462 million reported for the year ended 31 December 2019, primarily due to a 26% decrease in the average realised sales price, partially offset by 18% higher production. Including commodity hedge settlements of $145 million and $49 million in 2020 and 2019, respectively, Total Adjusted Revenue increased by 8% to $553 million in 2020 from $512 million in 2019.

We sold approximately 36,538 MBoe in 2020 versus approximately 30,944 MBoe in 2019 with the increase driven by the full integration of the previously acquired HG Energy and EdgeMarc assets in 2019 and the Carbon and EQT assets we acquired in May 2020. Lower commodity prices drove our average realised sales prices lower as reflected in the table below for the periods presented:

(In thousands)	Year Ended
	31 December 2020		31 December 2019		$ Change		% Change
Henry Hub	$	2.08	$	2.63	$	(0.55)	(21)	%
Belvieu	21.85		25.11		(3.26)		(13)	%
WTI	39.61		56.95		(17.34)		(30)	%

Refer to Note 5 in the Notes to the Group Financial Information for additional information regarding our acquisitions.

Commodity Revenue

The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) for the year ended 31 December 2020 by reflecting the effect of changes in volume and in the underlying prices:

(In thousands)	Natural Gas		NGLs		Oil		Total
Commodity revenue for the year ended 31 December 2019	$	384,121	$	33,685	$	20,474	$	438,280
Volume increase (decrease)	76,900		432		503		77,835
Price increase (decrease)	(117,596)		(10,944)		(5,913)		(134,453)
Net increase (decrease)	(40,696)		(10,512)		(5,410)		(56,618)
Commodity revenue for the year ended 31 December 2020	$	343,425	$	23,173	$	15,064	$	381,662

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)	Year Ended 31 December 2020
	Natural Gas				NGLs				Oil				Total Commodity
	Revenue		Realised $		Revenue		Realised $		Revenue		Realised $		Revenue		Realised $
Excluding hedge impact	$	343,425	$	1.72	$	23,173	$	8.15	$	15,064	$	36.12	$	381,662	$	10.45
Commodity hedge impact	121,077		0.61		16,498		5.80		7,025		16.85		144,600		3.95
Including hedge impact	$	464,502	$	2.33	$	39,671	$	13.95	$	22,089	$	52.97	$	526,262	$	14.40

	Year Ended 31 December 2019
	Natural Gas				NGLs				Oil				Total Commodity
	Revenue		Realised $		Revenue		Realised $		Revenue		Realised $		Revenue		Realised $
Excluding hedge impact	$	384,121	$	2.31	$	33,685	$	12.00	$	20,474	$	50.30	$	438,280	$	14.16
Commodity hedge impact	27,483		0.16		22,214		7.91		(230)		(0.56)		49,467		1.60
Including hedge impact	$	411,604	$	2.47	$	55,899	$	19.91	$	20,244	$	49.74	$	487,747	$	15.76

Refer to Note 14 in the Notes to the Group Financial Information for additional information regarding our hedging portfolio.

Expenses

(In thousands, except per unit data)	Year Ended
			Per				Per		Total Change				Per Boe Change
	31 December 2020		Boe		31 December 2019		Boe		$		%		$		%
Base lease operating expense ^(a)	$	92,288	$	2.53	$	102,302	$	3.31	$	(10,014)	(10)	%	$	(0.78)	(24)	%
Production taxes ^(b)	13,705		0.38		16,427		0.53		(2,722)		(17)	%	(0.15)		(28)	%
Midstream operating expense ^(c)	52,815		1.45		44,060		1.42		8,755		20	%	0.03		2	%
Transportation expense ^(d)	45,155		1.24		39,596		1.28		5,559		14	%	(0.04)		(3)	%
Total operating expense	$	203,963	$	5.58	$	202,385	$	6.54	$	1,578	1	%	$	(0.96)	(15)	%
Base G&A ^(e)	47,181		1.29		36,073		1.17		11,108		31	%	0.12		10	%
Non-recurring and/or non-cash G&A ^(f)	30,053		0.82		19,816		0.64		10,237		52	%	0.18		28	%
Total operating and G&A expense	$	281,197	$	7.70	$	258,274	$	8.35	$	22,923	9	%	$	(0.65)	(8)	%
Depreciation, depletion and amortisation	117,290		3.21		98,139		3.17		19,151		20	%	0.04		1	%
Allowance for credit losses ^(g)	8,490		0.23		730		0.02		7,760		100	%	0.21		100	%
Total expenses	$	406,977	$	11.14	$	357,143	$	11.54	$	49,834	14	%	$	(0.40)	(3)	%

(a) Base lease operating expense 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 the Group's 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, 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.

Our value-focused growth and disciplined operating approach reduced per unit expenses by 3%, or $0.40 per Boe, including:

• Lower per Boe base lease operating expenses, which declined 24%, or $0.78 per Boe, through a mixture of disciplined cost reductions and economies of scale, whereby fixed operating costs were spread across a larger base of producing assets;

• Lower per Boe production taxes, which declined 28%, or $0.15 per Boe, primarily due to a decrease in severance taxes as a result of a decrease in revenue. Declines also resulted from taxes on our midstream assets, that are generally fixed, being spread across a larger base of producing assets; and

• Lower per Boe transportation expense related to efficiencies of scale gained on the fixed cost components associated with transportation expense.

Partially offsetting the per Boe declines were increases due to:

•Higher per Boe midstream operating expense, which increased 2%, or $0.03 per Boe, primarily due to increases in the size of our midstream workforce to meet the needs of the expanded midstream capabilities gained in the Carbon and EQT acquisitions;

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

• Higher non-recurring and/or non-cash G&A due to costs associated with our transition from listing on AIM to the Premium Segment of the Main Market on the LSE, acquisition and integration expenses related to Carbon and EQT, and costs to modify certain derivative contracts.

Refer to Notes 5 and 14 in the Notes to the Group Financial Information for additional information regarding our acquisitions and derivative contracts, 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)	Year Ended
	31 December 2020		31 December 2019		$ Change		% Change
Net gain (loss) on commodity derivatives ^(a)	$	144,600	$	49,467	$	95,133	192	%
Net gain (loss) on interest rate swap	(202)		-		(202)		(100)	%
Gain on foreign currency hedge	-		4,117		(4,117)		(100)	%
Total gain (loss) on settled derivative instruments	$	144,398	$	53,584	90,814		169	%
Gain (loss) on fair value adjustments of unsettled financial instruments ^(b)	(238,795)		20,270		(259,065)		(1278)	%
Total gain (loss) on derivative financial instruments	$	(94,397)	$	73,854	$	(168,251)	(228)	%

(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 year ended 31 December 2020, the total loss on derivative financial instruments of $94 million decreased by $168 million compared to a gain of $74 million in 2019. Adjusting our unsettled derivative contracts to their fair values drove a loss of $239 million in 2020, a decrease of $259 million, as compared to a gain of $20 million in 2019.

While the change in fair value is significant and reflective of higher prices on the forward price curve, our derivative contracts position us to not only fully realise the healthy cash flows we hedged but also earn higher cash flow on our unhedged production.

Additionally, a large portion of the unsettled hedge loss relates to time option value of our long-dated portfolio. Specifically, approximately $70 million of the $166 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.

Offsetting the non-cash valuation loss was a cash gain of $144 million on settled derivative instruments for the year ended 31 December 2020, an increase of $91 million over 2019.

For the year ended 31 December 2020, the gain on settled derivative instruments, representing 26% of Adjusted Total Revenue, validates our hedge portfolio objective to provide downside commodity risk protection. While year-end 2020 prices experienced modest recovery, the rising forward price curve results in a shift of our overall, long-dated derivative contract portfolio from an asset to a liability. For 2021, we have significant downside protection, including approximately 90% of our natural gas production hedged at a weighted average floor price of $2.93 per Mcfe, securing our cash flows, future dividend distributions and debt repayments.

Refer to Note 14 in the Notes to the Group Financial Information for additional information regarding our derivative financial instruments.

Gain on Bargain Purchase

We recorded the following gains on bargain purchase in the Consolidated Statement of Comprehensive Income for the periods presented:

(In thousands)	Year Ended
	31 December 2020		31 December 2019		$ Change		% Change
Gain on bargain purchase	$	17,172	$	1,540	$	15,632	1,015	%

While gains on bargain purchases are uncommon, the E&P segment of the broader energy sector has been in a period of transition and rebalancing for the past few years, creating opportunities for healthy companies like Diversified to acquire high quality assets for less than their fair values. We have established a track record of being disciplined in our bidding to acquire assets that meet our strict asset profile and are accretive to our overall corporate value.

Refer to Note 5 in the Notes to the Group Financial Information for additional information regarding our acquisitions and bargain purchase gains.

Finance Costs

(In thousands)	Year Ended
	31 December 2020		31 December 2019		$ Change		% Change
Interest expense, net of capitalised and income amounts	$	34,391	$	32,662	$	1,729	5	%
Amortisation of discount and deferred finance costs	8,334		3,875		4,459		115	%
Other	602		130		472		363	%
Total finance costs	$	43,327	$	36,667	$	6,660	18	%

For the year ended 31 December 2020, interest expense on borrowings of $34 million increased $2 million compared to $33 million in 2019, primarily due to the increase in borrowings used to fund our previously mentioned acquisitions. As of 31 December 2020 and 2019, total borrowings were $746 million and $645 million, respectively. For the year ended 31 December 2020, the weighted average interest rate on borrowings was 4.70% as compared to 4.52% in 2019, as a result of entering into additional fixed rate financing structures as we sought to capitalise on depressed markets and secure advantageous financing.

The increase in other finance costs was primarily due to an increase in interest expense on leases. During the year ended 31 December 2020, we expanded our fleet and transitioned owned vehicles to a fleet management lease programme.

Refer to Notes 5, 21, and 22 in the Notes to the Group Financial Information for additional information regarding our acquisitions, capital leases and borrowings, respectively.

Taxation

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

(In thousands)	Year Ended
	31 December 2020			31 December 2019			$ Change		% Change
Income (loss) before taxation	$	(136,740)		$	131,491		$	(268,231)	(204)	%
Income tax benefit (expense)	113,266			(32,091)			145,357		(453)	%
Effective tax rate	82.8		%	24.4		%

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

	Year Ended
	31 December 2020		31 December 2019
Expected tax at statutory US federal income tax rate	21.0	%	21.0	%
State income taxes, net of federal tax benefit	5.4	%	6.0	%
Federal credits	58.8	%	(5.3)	%
Other, net	(2.4)	%	2.7	%
Effective tax rate	82.8	%	24.4	%

For the year ended 31 December 2020, we reported a tax benefit of $113 million, a change of $145 million, compared to an expense of $32 million in 2019. The resulting effective tax rates for the years ended 31 December 2020 and 2019 were 83% and 24%, respectively. The effective tax rate is primarily impacted by 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.

Refer to Note 8 in the Notes to the Group Financial Information for additional information regarding taxation.

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

(In thousands, except per unit amounts)	Year Ended
	31 December 2020		31 December 2019		$ Change		% Change
Operating profit (loss)	$	(77,568)	$	180,507	$	(258,075)	(143)	%
Income (loss) available to shareholders after taxation	(23,474)		99,400		(122,874)		(124)	%
Adjusted Net Income	174,786		95,618		79,168		83	%
Hedged Adjusted EBITDA	300,590		273,266		27,324		10	%

Earnings (loss) per share - diluted	$	(0.03)	$	0.15	$	(0.18)	(120)	%
Adjusted EPS - diluted	0.25		0.15		0.10		67	%
Hedged Adjusted EBITDA per Share - diluted	0.44		0.42		0.02		5	%

For the year ended 31 December 2020, we reported a net loss of $23 million and a loss per share of $0.03 compared to income of $99 million and EPS of $0.15 in 2019, a decrease of 124% and 120%, respectively. We also reported an operating loss of $78 million compared with an operating profit of $181 million for the year ended 31 December 2020 and 2019. This year-over-year decline in net income was attributable to a mark-to-market loss of $239 million.

Excluding the mark-to-market loss as well as other non-cash and non-recurring items, we reported Adjusted Net Income of $175 million and Adjusted EPS of $0.25 per share compared to Adjusted Net Income of $96 million and Adjusted EPS of $0.15 per share in 2019, increases of 83% and 67%, respectively.

Additional adjustments for depletion, depreciation, amortisation, interest, and taxes resulted in Hedged Adjusted EBITDA of $301 million and Hedged Adjusted EBITDA per Share of $0.44 compared to $273 million and $0.42 in 2019, representing increases of 10% and 5%, respectively. The increases in Adjusted Net Income and Hedged Adjusted EBITDA metrics year-over-year were driven by a strong execution of our stated strategy, resulting in consistent growth of earnings at the share level.

Refer to Note 9 in the Notes to the Group Financial Information for information regarding Adjusted Net Income, Adjusted EPS, and Hedged Adjusted EBITDA. Please refer to the APMs section 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 not only afford us lower interest rates than more traditional E&P financing like high-yield bonds, but 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 return on our capital investments to support the strategic initiatives in our business operations.

(In thousands)	Year Ended
	31 December 2020		31 December 2019		$ Change		% Change
Net cash provided by operating activities	$	241,710	$	279,156	$	(37,446)	(13)	%
Net cash used in investing activities	(256,863)		(466,887)		210,024		(45)	%
Net cash provided by financing activities	14,871		188,020		(173,149)		(92)	%
Net change in cash and cash equivalents	$	(282)	$	289	$	(571)	(198)	%

Net Cash Provided by Operating Activities

For the year ended 31 December 2020, net cash provided by operating activities of $242 million decreased $37 million, or 13%, as compared to $279 million in 2019. The reduction in net cash provided by operating activities was predominantly attributable to the following:

• A decrease in revenue, largely offset by an increase in settlements of hedges;

• An increase in Adjusted G&A for investments in staffing and systems to support our growth;

• An increase in non-recurring and/or non-cash G&A associated with a variety of items including (1) the costs to transition from our AIM listing to a Premium Listing on the Main Market of the LSE, (2) acquisition and integration expenses related to Carbon and EQT, and (3) derivative commodity contract modifications costs associated with our ABS II financing and with similar portfolio optimisation initiatives; and

• The timing of working capital payments and receipts.

Refer to Notes 5 and 14 in the Notes to the Group Financial Information for additional information regarding our acquisitions and derivative financial instruments, respectively.

Net Cash Used in Investing Activities

For the year ended 31 December 2020, net cash used in investing activities of $257 million decreased $210 million, or 45%, from $467 million in 2019. The change in net cash used in investing activities was primarily attributable to the following:

• For the year ended 31 December 2020, we paid cash purchase consideration of approximately $100 million and $123 million for business combinations (Carbon) and asset acquisitions (primarily EQT), respectively. For the year ended 31 December 2019, we paid purchase consideration of $439 million for business combinations (primarily HG Energy & Edgemark). Refer to Note 5 in the Notes to the Group Financial Information for additional information regarding our acquisitions.

• Capital expenditures were $22 million for the year ended 31 December 2020 compared to $32 million for the year ended 31 December 2019. Prior-year expenditures included "Project Delta," our system modernisation initiative whereby we planned, designed, tested, and implemented a network of accounting, production, land and measurement systems into a single data platform. Having completed most of that work during 2019, we had less similar expenditures in 2020.

• Restricted cash increased by $7 million year-over-year as a result of the interest expense reserve required by our long-term financing agreements including ABS I, ABS II and Term Loan financing. For more information refer to Note 3 in the Notes to the Group Financial Information.

• Investments were made in our marketing and operations groups in 2020 as we looked to expand these to better manage our growth. We invested in two service providers that had previously been providing contracting services for us. These acquisitions resulted in a cash outflow of $3 million. For more information refer to Note 13 in the Notes to the Group Financial Information.

Net Cash Provided by Financing Activities

For the year ended 31 December 2020, net cash provided by financing activities of $15 million decreased $173 million, or 92%, as compared to $188 million in FY19. The change in net cash provided by financing activities was primarily attributable to the following:

• Our Credit Facility activity resulted in net repayments of $223 million in 2020 versus net repayments of $59 million in 2019, with much of the increase attributed to a $200 million refinancing of Credit Facility borrowings through ABS II;

• Proceeds from borrowings, net of repayments, on our new debt facilities were $318 million in 2020, an increase of $112 million as compared to 2019;

• A decrease of $140 million in proceeds from equity issuances that raised $81 million in 2020 as compared to $222 million raised in 2019.

• An increase of $16 million in dividends paid in 2020 as compared to 2019; and

• A decrease of $37 million in the repurchase of shares in 2020 as compared to 2019.

Refer to Notes 17, 19 and 22 in the Notes to the Group Financial Information for additional information regarding share capital, dividends and borrowings, respectively.

GROUP FINANCIAL INFORMATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

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

		Audited as at
		Year Ended
	Note	31 December 2020		31 December 2019
Revenue	6	$	408,693	$	462,256
Operating expense	7	(203,963)		(202,385)
Depreciation, depletion and amortisation	7	(117,290)		(98,139)
Gross profit		87,440		161,732
General and administrative expense	7	(77,234)		(55,889)
Allowance for expected credit losses	15	(8,490)		(730)
Gain (loss) on natural gas and oil programme and equipment	12	(2,059)		-
Gain (loss) on derivative financial instruments	14	(94,397)		73,854
Gain on bargain purchase	5	17,172		1,540
Operating profit (loss)		(77,568)		180,507
Finance costs	22	(43,327)		(36,667)
Accretion of asset retirement obligation	20	(15,424)		(12,349)
Other income (expense)		(421)		-
Income (loss) before taxation		(136,740)		131,491
Income tax benefit (expense)	8	113,266		(32,091)
Income (loss) available to shareholders after taxation		(23,474)		99,400
Other comprehensive income (loss)		(28)		-
Total comprehensive income (loss) for the year		$	(23,502)	$	99,400

Earnings (loss) per share - basic	10	$	(0.03)	$	0.15
Earnings (loss) per share - diluted	10	$	(0.03)	$	0.15

Weighted average shares outstanding - basic	10	685,170		641,666
Weighted average shares outstanding - diluted	10	688,348		644,782

The notes are an integral part of this Group Financial Information.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

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

		Audited as at
	Note	31 December 2020		31 December 2019
ASSETS
Non-current assets:
Natural gas and oil properties, net	11	$	1,755,085	$	1,496,029
Property, plant and equipment, net	12	382,103		320,953
Intangible assets	13	19,213		15,981
Restricted cash	3	20,100		6,505
Derivative financial instruments	14	717		3,803
Deferred tax asset	8	14,777		-
Other non-current assets	16	4,213		2,309
Total non-current assets		$	2,196,208	$	1,845,580
Current assets:
Trade receivables, net	15	$	66,991	$	73,924
Cash and cash equivalents	3	1,379		1,661
Restricted cash	3	250		1,207
Derivative financial instruments	14	17,858		73,705
Other current assets	16	7,996		9,863
Total current assets		$	94,474	$	160,360
Total assets		$	2,290,682	$	2,005,940
EQUITY AND LIABILITIES
Shareholders' equity:
Share capital	17	$	9,520	$	8,800
Share premium	17	841,159		760,543
Merger reserve		(478)		(478)
Capital redemption reserve		592		518
Share-based payment reserve		8,683		3,907
Retained earnings		27,182		164,845
Total equity		$	886,658	$	938,135
Non-current liabilities:
Asset retirement obligations	20	$	344,242	$	196,871
Leases	21	13,865		1,015
Borrowings	22	652,281		598,778
Deferred tax liability	8	15,746		124,112
Derivative financial instruments	14	168,524		15,706
Other non-current liabilities	24	12,860		4,468
Total non-current liabilities		$	1,207,518	$	940,950
Current liabilities:
Trade and other payables	23	$	19,366	$	17,052
Leases	21	5,013		798
Borrowings	22	64,959		23,723
Derivative financial instruments	14	15,858		-
Other current liabilities	24	91,310		85,282
Total current liabilities		$	196,506	$	126,855
Total liabilities		$	1,404,024	$	1,067,805
Total equity and liabilities		$	2,290,682	$	2,005,940

The notes are an integral part of this Group Financial Information.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

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

	Note	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings		Total Equity
Balance at 31 December 2018		$	7,346	$	540,655	$	(478)	$	-	$	842	$	200,498	$	748,863
Income (loss) after taxation		-		-		-		-		-		99,400		99,400
Other comprehensive income (loss)		-		-		-		-		-		-		-
Total comprehensive income (loss)		-		-		-		-		-		99,400		99,400
Issuance of share capital	17	1,972		219,888		-		-		-		-		221,860
Equity compensation		-		-		-		-		3,065		-		3,065
Repurchase of shares	17	(518)		-		-		518		-		(52,902)		(52,902)
Dividends	19	-		-		-		-		-		(82,151)		(82,151)
Transactions with shareholders		1,454		219,888		-		518		3,065		(135,053)		89,872
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	17	791		80,616		-		-		-		-		81,407
Equity compensation		3		-		-		-		4,776		-		4,779
Repurchase of shares	17	(74)		-		-		74		-		(15,634)		(15,634)
Dividends	19	-		-		-		-		-		(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 this Group Financial Information.

CONSOLIDATED STATEMENT OF CASH FLOWS

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

		Audited as at
		Year Ended
	Note	31 December 2020		31 December 2019
Cash flows from operating activities:
Income (loss) after taxation		$	(23,474)	$	99,400
Cash flows from operations reconciliation:
Depreciation, depletion and amortisation	7	117,290		98,139
Accretion of asset retirement obligations	20	15,424		12,349
Income tax (benefit) expense		(113,266)		32,091
(Gain) loss on fair value adjustments of unsettled financial instruments	14	238,795		(20,270)
Plugging costs of asset retirement obligations	20	(2,442)		(2,541)
(Gain) loss on natural gas and oil programme and equipment		1,356		-
(Gain) on bargain purchase	5	(17,172)		(1,540)
Finance costs	22	43,327		36,667
Revaluation of contingent consideration	5	567		-
Hedge modifications	14	(7,723)		-
Non-cash equity compensation	7	5,007		3,065
Working capital adjustments:
Change in trade receivables		2,390		4,528
Change in other current assets		1,958		2,606
Change in other assets		(1,173)		409
Change in trade and other payables		(4,772)		7,669
Change in other current and non-current liabilities		(8,532)		8,573
Cash generated from operations		247,560		281,145
Cash paid for income taxes		(5,850)		(1,989)
Net cash provided by operating activities		241,710		279,156
Cash flows from investing activities:
Consideration for Business Acquisitions, net of cash acquired	5	(100,138)		(439,272)
Consideration for Acquisition of Assets	5	(122,953)		-
Expenditures on natural gas and oil properties and equipment	11,12	(21,947)		(32,313)
(Increase) decrease in restricted cash		(12,637)		(5,302)
Proceeds on disposals of natural gas and oil properties and equipment	12	3,712		10,000
Other acquired intangibles	13	(2,900)		-
Net cash used in investing activities		(256,863)		(466,887)
Cash flows from financing activities:
Repayment of borrowings	22	(705,314)		(618,010)
Proceeds from borrowings	22	799,650		765,236
Financing expense		(34,335)		(32,715)
Cost incurred to secure financing		(7,799)		(11,574)
Proceeds from equity issuance, net		81,407		221,860
Principal element of lease payments	20	(3,684)		(1,724)
Contingent consideration payments	5	(893)		-
Dividends to shareholders	19	(98,527)		(82,151)
Repurchase of shares		(15,634)		(52,902)
Net cash provided by financing activities		14,871		188,020
Net change in cash and cash equivalents		(282)		289
Cash and cash equivalents, beginning of period		1,661		1,372
Cash and cash equivalents, end of period		$	1,379	$	1,661

The notes are an integral part of this Group Financial Information.

NOTES TO THE GROUP FINANCIAL INFORMATION

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

INDEX TO THE NOTES TO THE GROUP FINANCIAL INFORMATION
Note 1 - General Information
Note 2 - Basis of Preparation
Note 3 - Significant Accounting Policies
Note 4 - Significant Accounting Judgements and Estimates
Note 5 - Acquisitions
Note 6 - Revenue
Note 7 - Expenses by Nature
Note 8 - Taxation
Note 9 - Adjusted Net Income and Hedged Adjusted EBITDA
Note 10 - Earnings (Loss) Per Share
Note 11 - Natural Gas and Oil Properties
Note 12 - Property, Plant and Equipment
Note 13 - Intangible Assets
Note 14 - Derivative Financial Instruments
Note 15 - Trade and Other Receivables
Note 16 - Other Assets
Note 17 - Share Capital
Note 18 - Non-Cash Share-Based Compensation
Note 19 - Dividends
Note 20 - Asset Retirement Obligations
Note 21 - Leases
Note 22 - Borrowings
Note 23 - Trade and Other Payables
Note 24 - Other Liabilities
Note 25 - Fair Value and Financial Instruments
Note 26 - Financial Risk Management
Note 27 - Contingencies
Note 28 - Related Party Transactions
Note 29 - Subsequent Events

NOTE 1 - GENERAL INFORMATION

Diversified Gas & Oil PLC (the "Parent") and its wholly owned subsidiaries (the "Group") is a natural gas, NGLs and oil producer and midstream operator that is focused on acquiring and operating mature producing wells with long-life low-decline profiles. The Group's assets are exclusively located within the Appalachian Basin of the US. 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 and Tennessee.

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.

NOTE 2 - BASIS OF PREPARATION

Basis of Preparation

The Group's consolidated financial statements (the "Group Financial Information") has been prepared in accordance with both international accounting standards in conformity with the requirements of the Companies Act 2006 and IFRS adopted pursuant to Registration (EC) No 1606/2002 as it applies in the EU. The principal accounting policies are set out below and have been applied consistently throughout the year

Unless otherwise stated, the Group Financial Information is 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 Group Financial Information has 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.

Going concern

The Group Financial Information has 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, taking into account the Directors' assessment of the financial and trading effects of the Covid-19 pandemic. 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.

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 Team, 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").

Key assumptions, which underpin the annual business planning process, include forecasted natural gas and oil prices, forecasted operating cost and capital expenditure levels, production profiles, and the availability of liquidity or additional financing. Cash flow projections are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from our producing assets. The Directors and Senior Leadership Team closely monitor these forecast assumptions and projections and seek to mitigate the Group's liquidity risk.

Based on our scenario planning process, the Directors and Senior Leadership Team believe that stress testing forecast results over the Base Plan, from January 2021 to December 2023, form a reasonable expectation to the Group's viability. The Base Plan forecast process is performed at least annually and covers our three year medium-term strategic planning period. The Directors and Senior Leadership Team are confident that operational risks are being monitored and managed effectively within the Base Plan period, and our scenario planning is focused primarily on plausible changes in external factors, providing a reasonable degree of confidence.

The principal risks and uncertainties that affect the Directors' assessment of our viability in this period are:

• The effect of volatile natural gas prices on the business;

• Operational production performance of the producing assets; and

• Operating cost levels and our ability to control costs.

The Base Plan incorporates assumptions that reflect these principal risks 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%, 65% and 45% 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 Team also consider further scenarios around the Base Plan that primarily reflect a more severe, but plausible, 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%.

Scenario 4: The three scenarios above were then considered in aggregate.

The Directors and Senior Leadership Team consider the impact that these principal risks could, in certain circumstances, have on the Group's prospects within the assessment period, and accordingly assess the opportunities to actively mitigate the risk these downside scenarios create while still being able to meet our debt obligations, and return cash flows to shareholders.

Under these downside sensitivity scenarios, the Group remains cash flow positive. The Group meets its working capital requirements through operating cash flow management and through the utilisation of the Group's Credit Facility, when necessary. For the purpose of the going concern assessment, the Directors have only taken into account the capacity under the existing Credit Facility. In November 2020 the Group reaffirmed its borrowing base on the $1,500,000 Credit Facility at $425,000. The Group's available borrowing under the Credit Facility totalled $211,600 as of 31 December 2020. The key covenants attached to the Group's Credit Facility relate to the Group's EBITDAX leverage ratio and current ratio. In the downside scenario modelled, the Group continues to maintain sufficient liquidity and meets its covenants under the Credit Facility as well as its other existing borrowing instruments.

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.

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.

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 Group Financial Information.

Prior period reclassifications

The Group has reclassified certain amounts in its prior year Consolidated Statement of Financial Position 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. During the year ended 31 December 2019, the Group reclassified $15,981 related to its Enterprise Resource Planning ("ERP") software from "Property, plant and equipment" to "Intangible assets" in the Consolidated Statement of Financial Position.

Basis of Consolidation

During 2019, the Group underwent a restructuring in order to simplify its organisation. Under this restructuring all production entities were merged into Diversified Production, LLC and all midstream entities were merged into Diversified Midstream, LLC. Further, Diversified Energy Marketing, LLC was created to sell the commodities produced by Diversified Production, LLC and certain third parties. There is no financial information impact as a result of the reorganisation.

The Group Financial Information for the year ended 31 December 2020 reflects the following corporate structure of the Group:

The Group, and its 100% wholly owned subsidiary:

• Diversified Gas & Oil PLC ("DGOC'') 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 Group Financial Information in compliance with IFRS requires the Directors to make estimates and exercise judgment in applying the Group's accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the Group Financial Information are disclosed in Note 4.

Business Combinations and Asset Acquisitions

The Group performs an assessment of each acquisition to determine whether the acquisition should be accounted for as an asset acquisition or business combination.

Accounting for business combinations under IFRS 3 is applied once it is determined that a business has been acquired. Under IFRS 3, a business is defined as an integrated set of activities and assets conducted and managed for the purpose of providing a return to investors. A business generally consists of inputs, processes applied to those inputs, and resulting outputs that are, or will be, used to generate revenues.

For each transaction, the Group may elect to apply the concentration test under the IFRS 3 amendment to determine if the fair value of assets acquired is substantially concentrated in a single asset (or a group of similar assets). If this concentration test is met, the acquisition qualifies as an acquisition of a group of assets and liabilities, not of a business. When the Group determines a transaction is an acquisition of a group of assets rather than a business combination, the Group capitalises the transaction costs incurred as part of the acquisition. Additionally in instances when the acquisition of a group of assets contains contingent consideration, the Group records changes in the fair value of the contingent consideration through the basis of the asset acquired rather than through the statement of comprehensive income.

More information regarding the judgements and conclusions reached with respect to business combinations and asset acquisitions is included in Note 4 and Note5.

Cash and Cash Equivalents

Cash on the balance sheet comprises cash at banks. Balances held at banks, at times, exceed US federally insured amounts. The Group has not experienced any losses in such accounts and the Directors believe the Group is not exposed to any significant credit risk on its cash. At 31 December 2020 and 2019, the Group's cash balance was $1,379 and $1,661, respectively.

Trade Receivables

Trade receivables are stated at the historical carrying amount, net of any provisions required. Trade receivables are due from customers throughout the natural gas and oil industry. Although diversified among several customers, collectability is dependent on the financial condition of each individual customer as well as the general economic conditions of the industry. The Directors review the financial condition of customers prior to extending credit and generally do not require collateral to support of the Group's trade receivables. Any changes in the Directors' allowance for current expected credit losses during the year are recognised in the Consolidated Statement of Comprehensive Income. Trade receivables also include certain receivables from third-party working interest owners. The Group consistently assesses the collectability of these receivables. At 31 December 2020 and 2019, the Group considered a portion of these working interests receivables uncollectable and recorded a allowance for credit losses in the amount of $11,082 and $3,210, respectively. See Note 15 for additional information.

Impairment of Financial Assets

IFRS 9, Financial Instruments ("IFRS 9"), requires the application of an expected credit loss model in considering the impairment of financial assets. The expected credit loss model requires the Group to account for expected credit losses and changes in those expected credit losses at each reporting date to reflect changes in credit risk since initial recognition of the financial assets. The credit event does not have to occur before credit losses are recognised. IFRS 9 allows for a simplified approach for measuring the loss allowance at an amount equal to lifetime expected credit losses for trade receivables and contract assets.

The Group applies the simplified approach to the expected credit loss model to trade receivables arising from:

• Sales of natural gas, NGLs and oil ;

• Sales of gathering and transportation of third-party natural gas; and

• The provision of other services.

Borrowings

Borrowings are recognised initially at fair value, net of any applicable transaction costs incurred. Borrowings are subsequently carried at amortised cost. Any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the Consolidated Statement of Comprehensive Income over the period of the borrowings using the effective interest method (if applicable).

Interest on borrowings is accrued as applicable to each class of borrowing.

Derivative Financial Instruments

Derivatives are used as part of the Group's overall strategy to mitigate risk associated with the unpredictability of cash flows due to volatility in commodity prices. Further details of the Group's exposure to these risks are detailed in Note 26. The Group has entered into financial instruments which are considered derivative contracts, such as swaps and collars which result in net cash settlement each month and do not result in physical deliveries. The derivative contracts are initially recognised at fair value at the date the contract is entered into and remeasured to fair value every balance sheet date. The resulting gain or loss is recognised in the Consolidated Statement of Comprehensive Income in the year incurred.

Restricted Cash

Cash held on deposit for bonding purposes is classified as restricted cash and recorded within current and non-current assets. The cash (1) is restricted in use by state governmental agencies to be utilised and drawn upon if the operator should abandon any wells, or (2) is being held as collateral by the Group's surety bond providers. Additionally, the Group is required to maintain certain reserves for interest payments related to its asset backed securitisation discussed in Note 22. These reserves approximate seven and a half months of interest and any associated fees. At 31 December 2020 and 2019, the Group's restricted cash balance was $20,350 and $7,712, respectively. The Group classifies restricted cash as current or non-current based on the classification of the associated asset or liability to which the restriction relates.

Natural Gas and Oil properties

Development and acquisition costs

Expenditures related to the construction, installation or completion of infrastructure facilities, such as platforms, and the drilling of development wells, including delineation wells, are capitalised within natural gas and oil properties. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, and the initial estimate of the well asset retirement obligation. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Depletion

Natural gas and oil properties are depleted on a unit-of-production basis over the proved reserves of the field concerned, except in the case of assets whose useful life is shorter than the lifetime of the field, in which case the straight- line method is applied. Rights and concessions are depleted on the unit-of-production basis over the total proven reserves of the relevant area. The unit-of-production rate for the depreciation of field development costs considers expenditures incurred to date, together with sanctioned future development expenditure.

Intangible Assets

Software development and acquisition costs

Development costs that are directly attributable to the design and testing of identifiable and unique software products controlled by the Group are recognised as intangible assets where the following criteria are met:

• It is technically feasible to complete the software so that it will be available for use;

• The Directors intend to complete the software and use or sell it;

• There is an ability to use the software;

• It can be demonstrated how the software will generate probable future economic benefits;

• Adequate technical, financial and other resources to complete the development and to use the software are available; and

• The expenditure attributable to the software during its development can be reliably measured.

Directly attributable costs that are capitalised as part of the software include employee costs and an appropriate portion of relevant overheads.

Capitalised development costs are recorded as intangible assets and amortised from the point at which the asset is ready for use.

Costs associated with maintaining software programmes are recognised as an expense as incurred.

Impairment of intangible assets

Intangible assets are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs of disposal and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from other assets or groups of assets (cash-generating units). Intangible assets that suffered an impairment are reviewed for possible reversal of the impairment at the end of each reporting period.

Amortisation

The Group amortises intangible assets with a limited useful life, using the straight-line method over the following periods:

	Range in Years
Software	3
Other acquired intangibles	3

Property, Plant and Equipment

Property, plant and equipment are stated at cost less accumulated depreciation and impairment losses, if any. The cost of an item of property, plant and equipment initially recognised includes its purchase price and any cost that is directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by the Directors.

Property, plant and equipment are generally depreciated on a straight-line basis over their estimated useful lives:

	Range in Years
Buildings and leasehold improvements	40
Equipment	5 - 10
Motor vehicles	5
Midstream assets	7 - 15
Other property and equipment	5 - 10

Property, plant and equipment held under leases are depreciated over the shorter of lease term and estimated useful life.

Impairment of Non-Financial Assets

At each reporting date, the Directors assess whether indications exist that an asset may be impaired. If indications exist, or when annual impairment testing for an asset is required, the Directors estimate the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's or cash generating unit's fair value less costs to sell and its value-in-use, and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. Where the carrying amount of an asset or cash-generating unit exceeds its recoverable amount, the Directors consider the asset impaired and write the subject asset down to its recoverable amount. In assessing value-in-use, the Directors discount the estimated future cash flows to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In determining fair value less costs to sell, the Directors consider recent market transactions, if available. If no such transactions can be identified, the Directors will utilise an appropriate valuation model.

Leases

The Group recognises a right-of-use asset and a lease liability at the commencement date of contracts (or separate components of a contract) which convey to the Group the right to control the use of an identified asset for a period of time in exchange for consideration, when such contracts meet the definition of a lease as determined by IFRS 16. The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at inception date.

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 can not be readily determined the Group uses its incremental borrowing rate. After the commencement date, the lease liability is reduced for payments made by the lessee and increased for interest on the lease liability.

Right-of-use assets are initially measured at cost, which comprises:

• The amount of the initial measurement of the lease liability;

• Any lease payments made at or before the commencement date, less any lease incentives received, any initial direct costs incurred by the lessee; and

• An estimate of costs to be incurred by the lessee in dismantling and removing the underlying asset, restoring the site on which it is located or restoring the underlying asset to the condition required by the terms and conditions of the lease unless those costs are incurred to produce inventories.

Subsequent to the measurement date, the right-of-use asset is depreciated on a straight line basis for a period of time that reflects the life of the underlying asset, and also adjusted for the remeasurement of any lease liability.

Asset Retirement Obligations

Where a material liability for the retirement of a well, removal of production equipment and site restoration at the end of the production life of a well exists, the Group recognises a liability for well asset retirement. The amount recognised is the present value of estimated future net expenditures determined in accordance with local conditions and requirements. The unwinding of the discount on the decommissioning liability is included as accretion of the decommissioning provision. The cost of the relevant property, plant and equipment asset is increased with an amount equivalent to the liability and depreciated on a unit of production basis. The Group recognises changes in estimates prospectively, with corresponding adjustments to the liability and the associated non-current asset.

At 31 December 2020 and 2019, the Group had no midstream asset retirement obligations.

Taxation

Deferred taxation

Deferred tax is provided in full on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Group Financial Information. Deferred tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and are expected to apply when the related deferred tax is realised or the deferred liability is settled.

Deferred tax assets are recognised to the extent that it is probable that the future taxable profit will be available against which the temporary differences can be utilised.

Income taxation

Current income tax assets and liabilities for the years ended 31 December 2020 and 2019 were measured at the amount to be recovered from, or paid to, the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted at the reporting date in the jurisdictions where the Group operates and generates taxable income.

Uncertain tax positions

Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation and considers whether it is probable that a taxation authority will accept an uncertain tax treatment. The group measures its tax balances based on either the most likely amount, or the expected value, depending on which method provides a better prediction of the resolution of the uncertainty.

Revenue Recognition

Natural gas, NGLs and oil

Commodity revenue is derived from sales of natural gas, NGLs and oil products and is recognised when the customer obtains control of the commodity. This transfer generally occurs when product is physically transferred into a vessel, pipe, sales meter or other delivery mechanism. This also represents the point at which the Group carries out its single performance obligation to its customer under contracts for the sale of natural gas, NGLs and oil.

Commodity revenue in which the Group has an interest with other producers is recognised proportionately based on the Group's working interest and the terms of the relevant production sharing contracts. The portion of revenue that is due to minority working interest is included as a liability in Note 24.

Commodity revenue is recorded based on the volumes accepted each day by customers at the delivery point and is measured using the respective market price index for the applicable commodity plus or minus the applicable basis differential based on the quality of the product.

Third-party gathering revenue

Revenue from gathering and transportation of third-party natural gas is recognised when the customer transfers its natural gas to the entry point in the Group's midstream network and becomes entitled to withdraw an equivalent volume of natural gas from the exit point in the Group's midstream network under contracts for the gathering and transportation of natural gas. This transfer generally occurs when product is physically transferred into the Group's vessel, pipe, or sales meter. The customer's entitlement to withdraw an equivalent volume of natural gas is broadly coterminous with the transfer of natural gas into the Group's midstream network. Customers are invoiced and revenue is recognised each month based on the volume of natural gas transported at a contractually agreed upon price per unit.

Other revenue

Revenue from the operation of third-party wells is recognised as earned in the month work is performed and consistent with the Group's contractual obligations. The Group's contractual obligations in this respect are considered to be its performance obligations for the purposes of IFRS 15, Revenue from Contracts with Customers ("IFRS 15").

Revenue from the sale of water disposal services to third-parties into the Group's disposal wells is recognised as earned in the month the water was physically disposed at a contractually agreed upon price per unit. Disposal of the water is considered to be the Group's performance obligation under these contracts.

Revenue is stated after deducting sales taxes, excise duties and similar levies.

Share-Based Payments

The Group accounts for share-based payments under IFRS 2, Share-based Payment ("IFRS 2"). All of the Group's share-based awards are equity settled. The fair value of the awards are determined at the date of grant. At 31 December 2020 and 2019, the Group had three types of share-based payment awards, restricted stock units ("RSUs"), performance stock units ("PSUs") and Options. The fair value of the grant of the Group's RSUs and PSUs is determined using the stock price at the grant date and uniformly expensed over the vesting period. The fair value of the Group's Options are calculated using the Black-Scholes model as of the grant date. The inputs to the Black-Scholes model included:

• The share price at the date of grant;

• Exercise price;

• Expected volatility;

• Expected dividends;

• Risk-free rate of interest; and

• Patterns of exercise of the plan participants.

The grant date fair value of share-based awards, adjusted for market-based performance conditions, are expensed uniformly over the vesting period.

Segment Reporting

The Group is an independent owner and operator of producing natural gas and oil wells concentrated in the Appalachian Basin. The Group's operations are located throughout the region and has operations in the states of Tennessee, Kentucky, Virginia, West Virginia, Ohio, and Pennsylvania. 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 67,000 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 Company'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.

New Standards and Interpretations - Adopted

IFRS 3, Business Combinations ("IFRS 3")

In October 2018, the International Accounting Standards Board issued amendments to IFRS 3. The amendments clarify the definition of a business, with the objective of assisting entities to determine whether a transaction should be accounted for as a business combination or as an asset acquisition. The amended standard states that to be considered a business, an acquired set of activities and assets must include, at a minimum, an input and a substantive process that together significantly contributes to the ability to create outputs while removing the consideration of a market participant's ability to replace any missing inputs or processes and continuing to produce outputs. The standard also establishes an optional asset concentration test allowing entities to determine whether an acquired set of activities and assets is not a business. The Group adopted the amendments to IFRS 3 on 1 January 2020 and applied the amendments to asset acquisitions and business combinations that occurred subsequent to adoption.

New Standards and Interpretations - Not Yet Adopted

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2020 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 - SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES

In application of the Group's accounting policies, which are described in note 3, the Directors have made the following judgments and estimates which may have a significant effect on the amounts recognised in the Group Financial Information:

SIGNIFICANT JUDGEMENTS

Business Combinations and Asset Acquisitions

The Group follows the guidance in IFRS 3 for determining the appropriate accounting treatment for acquisitions. IFRS 3 permits an initial fair value screen to determine if substantially all of the fair value of the assets acquired is concentrated in a single asset or group of similar assets. If the initial screening test is not met, the set is considered a business based on whether there are inputs and substantive processes in place. Based on the results of this analysis and conclusion on an acquisition's classification of a business combination or an asset acquisition, the accounting treatment is derived.

If the acquisition is deemed to be a business, the acquisition method of accounting is applied. Identifiable assets acquired and liabilities assumed at the acquisition date are recorded at fair value. When the fair value exceeds the consideration transferred a bargain purchase gain is recognised, conversely when the consideration transferred exceeds the fair value goodwill is recorded.

If the transaction is deemed to be an asset purchase, the cost accumulation and allocation model is used whereby the assets and liabilities are recorded based on the purchase price and allocated to the individual assets and liabilities based on relative fair values. As a result bargain purchase gains are not recognised on asset acquisitions. Additionally in instances when the acquisition of a group of assets contains contingent consideration, 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. More information regarding conclusions reached with respect to this judgement is included in Note 5.

The determination and allocation of fair values to the identifiable assets acquired and liabilities assumed are based on various assumptions and valuation methodologies requiring considerable management judgment. The most significant variables in these valuations are discount rates and other assumptions and estimates used to determine the cash inflows and outflows. Management determines discount rates based on the risk inherent in the acquired assets, specific risks, industry beta and capital structure of guideline companies. The valuation of an acquired business is based on available information at the acquisition date and assumptions that are believed to be reasonable. However, a change in facts and circumstances as of the acquisition date can result in subsequent adjustments during the measurement period, but no later than one year from the acquisition date.

SIGNIFICANT ESTIMATES

Estimating the Fair Value of Natural Gas and Oil Properties

The Group determines the fair value of its natural gas and oil properties upon acquisition using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and natural gas and oil forward prices. The future net cash flows are discounted using a weighted average cost of capital as well as any additional risk factors. Proved reserves are estimated by reference to available geological and engineering data and only include volumes for which access to market is assured with reasonable certainty. Estimates of proved reserves are inherently imprecise, require the application of judgment and are subject to regular revision, either upward or downward, based on new information such as from the drilling of additional wells, observation of long-term reservoir performance under producing conditions and changes in economic factors, including product prices, contract terms or development plans. Sensitivity analysis on the significant inputs to the fair value is included in Note 5.

Impairment of Natural Gas and Oil Properties

In preparing the Group Financial Information the Directors considered that a key judgment was whether there was any evidence that the natural gas and oil properties were impaired. When making this assessment producing assets are reviewed for indicators of impairment at the balance sheet date. Indicators of impairment for the Group's producing assets include:

• A decrease in commodity pricing or other negative changes in market conditions;

• Downward revisions of reserve estimates; or

• Increases in operating costs.

The Group reviews the carrying value of its natural gas and oil properties annually or when an indicator of impairment is identified. The impairment test compares the carrying value of natural gas and oil properties to their recoverable amount based on the present value of estimated future net cash flows from the proved natural gas and oil reserves. The future cash flows are calculated using estimated reserve quantities, costs to produce and develop reserves, and natural gas and oil forward prices. The fair value of proved reserves is estimated by reference to available geological and engineering data and only include volumes for which access to market is assured with reasonable certainty. When the carrying value is in excess of the fair value, the Group recognises an impairment by writing down the value of its natural gas and oil properties to their fair value. No such impairments were recorded during 2020 and 2019.

Where there has been a charge for impairment in an earlier period, that charge will be reversed in a later period where there has been a change in circumstances to the extent that the recoverable amount is higher than the net book value at the time. In reversing impairment losses, the carrying amount of the asset will be increased to the lower of its original carrying value or the carrying value that would have been determined (net of depletion) had no impairment loss been recognised in prior years. No such recoveries were recorded during 2020 and 2019. Please refer to Note 20 for additional information.

When applicable, the Group recognises impairment losses in the Consolidated Statement of Comprehensive Income in those expense categories consistent with the function of the impaired asset.

Reserve Estimates

Reserves are estimates of the amount of natural gas, NGLs and oil product that can be economically and legally extracted from the Group's properties. To calculate the reserves, significant estimates and assumptions are required about a range of geological, technical and economic factors, including quantities, production techniques, recovery rates, production costs, transport costs, commodity demand, commodity prices and exchange rates.

Estimating the quantity and/or grade of reserves requires the size, shape and depth of fields to be determined by analysing geological data, such as drilling samples. This process may require complex and difficult geological judgments and calculations to interpret the data.

Given the economics used to estimate reserve changes from year to year and, because additional geological data is generated during the course of operations, estimates of reserves may change from time to time.

Asset Retirement Obligation Costs

The ultimate asset retirement obligation costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing and amount of expenditures can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, significant estimates and assumptions are made in determining the provision for asset retirement. These assumptions include cost to plug the wells, the economic life of the wells and the discount rate. Changes in assumptions related to the Group's asset retirement obligations could result in a material change in the carrying value within the next financial year. See Note 20 for more information and sensitivity analysis.

NOTE 5 - 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 accounts for acquisitions under 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.

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 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 another $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 22.

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 31 December 2020 no contingent consideration payment had been made.

In the period from its acquisition to 31 December 2020 the acquisition of Carbon increased the Group's natural gas and oil production by 10,279 MMcf and 45 MBbls, respectively. The properties associated with the acquisition have been co-mingled with the Group's existing properties and it is impractical to provide stand-alone operational results related to these acquired properties for the twelve month period ended 31 December 2020.

As stated in Note 4, changes in the Group's assumptions used as inputs for acquisitions could result in a material change of the fair value of the acquired reserves. The Group considers the discount rate, commodity pricing, production and operating expense assumptions to be the inputs most sensitive to the fair value of the acquired reserves. The table below represents the impact a 100 basis point adjustment in the discount rate, commodity price, production and operating expense would have on the fair value of the acquired reserves provided this represents a reasonably possible change in these assumptions.

Adjusted fair value of natural gas and oil properties	+100 Basis Points	-100 Basis Points
Discount rate	76,625	83,751
Pricing ^(a)	81,938	78,238
Production	81,938	78,238
Operating expense	79,238	80,938

(a) The Group used a projected base realised price of $1.86 for natural gas and $30.84 for oil.

As a result of the valuation, the fair value of the reserves held in assets acquired was $80,138, which was derived using a cumulative discount rate of 11%. The provisional fair value of the assets acquired and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	101,490
Contingent consideration	5,463
Total consideration	$	106,953

Net assets acquired
Natural gas and oil properties	$	80,138
Natural gas and oil properties (asset retirement obligation, asset portion)	23,853
Property, plant and equipment	46,713
Other non-current assets	3,846
Derivative financial instruments, net	3,464
Trade receivables	110
Inventory	2,478
Other current assets	6
Cash and cash equivalents	1,352
Deferred tax asset	4,105
Leases, non-current	(2,537)
Other non-current liabilities	(441)
Asset retirement obligation, liability portion	(23,853)
Trade and other payables	(1,672)
Leases, current	(963)
Other current liabilities	(12,474)
Net assets acquired	124,125
Gain on bargain purchase	(17,172)
Purchase price	$	106,953

Taking into account the requirements of IFRS 3 with respect to the possibility of recognising a possible gain on a bargain purchase, the Group reviewed the procedures used to identify and measure all amounts affecting the calculation of the assets and liabilities acquired in the transaction and considered the recognition of the gain on the bargain purchase appropriate. The review of these factors included the review of Carbon's public filings when submitting the transaction to stockholders for approval as required by Section 271 of the General Corporation Law of the State of Delaware.

The bargain purchase was a result of a combination of factors that coincided with the sustained period of low natural gas and oil prices the market has experienced, significant market volatility linked to the Covid-19 pandemic and strategic decisions by other industry participants as they effect their own initiatives often choosing to divest assets they consider non-core to their business.

These external pressures created concerns about Carbon's ability to comply with certain financial covenants if this lingering period of low pricing were to persist, providing incentive for Carbon to market the assets. These pressures coupled with Carbon's desire for additional strategic pursuits in California-based assets contributed to the Group's recognition of a $17,172 gain on bargain purchase.

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 a 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 another $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 22.

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 at 31 December 2020, the Group has made contingent consideration payments of $893.

In the period from its acquisition to 31 December 2020 the acquisition of EQT increased the Group's natural gas production by 12,971 MMcf. The properties associated with the acquisition have been co-mingled with the Group's existing properties and it is impractical to provide stand-alone operational results related to these acquired properties for the twelve month period ended 31 December 2020.

Adjusted fair value of natural gas and oil properties	+100 Basis Points	-100 Basis Points
Discount rate	114,909	115,808
Pricing ^(a)	115,447	115,258
Production	115,447	115,258
Operating expense	115,333	115,375

(a) The Group used a projected base realised price of $1.73 using Henry Hub strip prices adjusted for differentials.

As a result of the valuation, the fair value of the reserves held in assets acquired was $114,007, which was derived using a cumulative discount rate of 11%. The provisional fair value of the assets and liabilities assumed were as follows:

Consideration paid:
Cash consideration	$	114,802
Contingent consideration	7,082
Acquisition costs	1,069
Total consideration	$	122,953

Natural gas and oil properties	$	114,007
Natural gas and oil properties (asset retirement obligation, asset portion)	3,142
Property, plant and equipment	10,956
Asset retirement obligation, liability portion	(3,142)
Other current liabilities	(2,010)
Net assets acquired	$	122,953

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.

2019 Acquisitions

HG Energy ("HG Energy") business combination

In April 2019, the Group acquired 107 unconventional wells in the states of Pennsylvania and West Virginia from HG Energy. The Group paid purchase consideration of $384,020, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were $4,788. The Group funded the cash consideration for the purchase with the proceeds from an equity placing of shares in April 2019 and a draw from the Credit Facility, discussed in Notes 17 and 22, respectively.

In the period from its acquisition to 31 December 2019, the acquisition of HG Energy contributed revenue of approximately $34,000 and increased the Group's natural total production by 90,940 Boepd. The properties associated with the acquisition have been commingled with the Group's existing properties and it is impractical to provide stand-alone operational results related to these acquired properties.

As a result of the valuation, the fair value of the reserves held in the assets acquired was $385,671, which was derived using a cumulative discount rate of 8%. The fair values of the assets and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	384,020
Total consideration	$	384,020

Net assets acquired
Natural gas and oil properties	$	385,671
Natural gas and oil properties (asset retirement obligation, asset portion)	236
Suspense ^(a)	(1,651)
Asset retirement obligation, liability portion	(236)
Net assets acquired	$	384,020

(a) Suspense represents the amounts payable to minority working interest owners.

EdgeMarc Energy ("EdgeMarc") business combination

In September 2019, the Group acquired 12 unconventional wells and three drilled but uncompleted unconventional wells in Ohio from EdgeMarc Energy. The Group paid purchase consideration of $48,107, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were $747. The Group funded the cash consideration for the purchase from a draw on the Credit Facility, discussed in Note 22.

In the period from its acquisition to 31 December 2019, the acquisition of EdgeMarc contributed revenue of approximately $6,600 and increased the Group's total production to 95,940 Boepd. The properties associated with the acquisition have been commingled with the Group's existing properties and it is impractical to provide stand-alone operational results related to these acquired properties.

As a result of the valuation, the fair value of the reserves held in the assets acquired was $40,507, which was derived using a cumulative discount rate of 8.5%. The fair values of the assets and liabilities assumed were as follows:

Consideration paid
Cash consideration	$	48,107
Total consideration	$	48,107

Net assets acquired
Natural gas and oil properties	$	40,507
Natural gas and oil properties (asset retirement obligation, asset portion)	15
Drilled but uncompleted	10,000
Derivative financial instruments, net	2,213
Suspense ^(a)	(2,744)
Asset retirement obligation, liability portion	(15)
Taxes payable	(329)
Net assets acquired	49,647
Gain on bargain purchase	(1,540)
Purchase price	$	48,107

(a) Suspense represents the amounts payable to minority working interest owners.

The Group recorded a $1,540 gain on the acquisition of the EdgeMarc assets which the Directors believe is reasonable given the facts and circumstances of the acquisition. The Group entered into a "stalking-horse" Asset Purchase Agreement with EdgeMarc, debtors-in-possession under title 11 of the US Code, pursuant to voluntary petitions for relief filed under Chapter 11 of the US Bankruptcy Code. Given the circumstances of EdgeMarc, the Directors believe that EdgeMarc was in a distressed position to sell the assets under fair market value.

Acquisition of natural gas gathering systems

In September 2019, the Group acquired certain natural gas gathering systems from Dominion and Equitrans, for total cash consideration of $7,700, excluding customary purchase price adjustments. The natural gas gathering systems associated with the acquisitions have been commingled with the Group's existing natural gas gathering systems and it is impractical to provide stand-alone operational results related to these acquired assets. The Group funded the cash consideration of the purchase from a draw on the Credit Facility discussed in Note 22. The Group accounted for this acquisition as an asset acquisition under IFRS 3. Transaction costs associated with the Dominion and Equitrans acquisitions were $726 and $507, respectively.

NOTE 6 - 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:

	Year Ended
	31 December 2020		31 December 2019
Natural gas	$	343,425	$	384,121
NGLs	23,173		33,685
Oil	15,064		20,474
Total commodity revenue	381,662		438,280
Midstream	25,389		22,166
Other	1,642		1,810
Total revenue	$	408,693	$	462,256

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 generally uncollateralised, and are collected within 30 - 60 days depending on the commodity, location and well type.

During the year ended 31 December 2020, two customers individually totalled more than 10% of total revenues, totalling 11% each for a total of 22%. During the year ended 31 December 2019, one customer individually totalled more than 10% of total revenues, totalling 13%.

NOTE 7 - EXPENSES BY NATURE

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

	Year Ended
	31 December 2020		31 December 2019
Base lease operating expense ^(a)	$	92,288	$	102,302
Production taxes ^(b)	13,705		16,427
Midstream operating expense ^(c)	52,815		44,060
Transportation expense ^(d)	45,155		39,596
Total operating expense ^(e)	203,963		202,385
Depreciation and amortisation	33,673		23,568
Depletion	83,617		74,571
Total depreciation, depletion and amortisation	117,290		98,139
Employees and benefits (administrative)	28,843		20,914
Other administrative ^(f)	8,820		7,384
Professional fees ^(g)	6,259		5,212
Auditors' remuneration ^(h)	2,429		1,667
Rent	830		896
Base G&A ⁽ⁱ⁾	47,181		36,073
Non-recurring costs associated with acquisitions ^(j)	10,465		9,210
Other non-recurring costs ^(k)	14,581		7,542
Non-cash equity compensation ^(l)	5,007		3,064
Non-recurring and/or non-cash G&A ^(m)	30,053		19,816
Total G&A	77,234		55,889
Allowance for joint interest owner receivables	6,931		730
Recurring allowance for credit losses	1,559		-
Total allowance for credit losses ⁽ⁿ⁾	8,490		730
Total expense	$	406,977	$	357,143
Aggregate remuneration (including Directors):
Wages and salaries	75,719		68,226
Payroll taxes	5,383		2,869
Benefits	14,926		5,766
Total employees and benefits expense	$	96,028	$	76,861

(a) Base lease operating expense 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 seven months of operating expense related to the EQT and Carbon acquisitions, both acquired in May 2020, as well as a full year of operating expenses related to the HG Energy and EdgeMarc assets acquired in April 2019 and September 2019, respectively. See Note 5 for additional information on acquisitions.

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

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

(h) Auditors' remuneration includes fees payable to the Group's auditor for the audit of the Group and Company annual accounts, accounts of subsidiaries and other assurance services. Please refer to the table below for more information.

(i) Adjusted G&A includes payroll and benefits for our management, directors and administrative staff, costs of maintaining 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.

(j) Non-recurring costs associated with acquisitions primarily relate to transition services, IT integration, legal and consulting costs directly related to acquisitions.

(k) Other non-recurring costs for 2020 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. For 2019, other non-recurring costs are associated with early buyouts of long-term firm transportation agreements, severance packages, temporary service agreements for onboarding of acquired assets and consolidation of the Group's corporate structure.

(l) Non-cash equity issuances in 2020 and 2019, reflect the expense recognition related to share-based compensation provided to certain key managers.

(m) Non-recurring and/or non-cash G&A includes costs related to acquisitions, the Group's up-list to the Main Market of the LSE, and other one-time events.

(n) 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 15 for additional information.

The average monthly number of employees was as follows:

	Year Ended
	31 December 2020	31 December 2019
Number of production support employees, including Directors	183	156
Number of production employees	924	768
Workforce	1,107	924

The Directors consider that the Group's key management personnel comprise the Directors. The Directors' remuneration was as follows for the periods presented:

	Year Ended
	31 December 2020		31 December 2019
Executive Directors
Salary	$	1,090	$	775
Taxable benefits ^(a)	16		11
Benefit plan ^(b)	32		22
Bonus	1,537		1,124
Total Executive Directors' remuneration	2,675		1,932
Non-Executive Directors
Salary	763		374
Total Non-Executive Directors' remuneration	763		374
Total remuneration	$	3,438	$	2,306

(a) Taxable benefits were comprised of Group paid life insurance premiums and automobile reimbursements.

(b) Benefit plan amounts reflect matching contributions under the Group's 401(k) plan.

Auditors' remuneration for the Group was as follows for the periods presented:

	Year Ended
	31 December 2020		31 December 2019
Auditors remuneration (PwC)
Fees payable to the Company's external auditors and their associates for the audit of the consolidated financial statements	$	1,196	$	-
Audit-related assurance services ^(a)	1,146		-
Other assurance services	87		-
Total auditors' remuneration (PwC)	2,429		-
Auditors' remuneration (Crowe)
Fees payable to the Company's external auditors and their associates for the audit of the consolidated financial statements	-		350
Audit-related assurance services	-		1,092
Other assurance services	-		225
Total auditors' remuneration (Crowe)	-		1,667
Total auditors' remuneration	$	2,429	$	1,667

(a) Fees incurred associated with the up-list to the Main Market of the LSE.

NOTE 8 - 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 Group Financial Information 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 taxable years ending 31 December 2020 and 2019, the Group had a tax benefit of $113,266 and an expense of $32,091, respectively. The Group's effective tax rate was 82.8% and 24.4% for the same periods, respectively. 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 programs, 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 May 2020, the US Internal Revenue Service released Notice 2020-34 which quantified the amount of credit per Mcf of qualified natural gas production for tax years beginning in 2019 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. 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 provision for income taxes in the Consolidated Statement of Comprehensive Income is summarised below:

	Year Ended
	31 December 2020		31 December 2019
Current income tax expense
Federal	$	233	$	654
State	4,923		2,217
Foreign - UK	616		142
Total current income tax expense	5,772		3,013
Deferred income tax (benefit) expense
Federal	(108,627)		22,253
State	(10,411)		6,825
Total deferred income tax (benefit) expense	(119,038)		29,078
Total income tax (benefit) expense	$	(113,266)	$	32,091

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

	Year Ended
	31 December 2020			31 December 2019
Income (loss) before taxation	$	(136,740)		$	131,491
Income tax benefit (expense)	113,266			(32,091)
Effective tax rate	82.8		%	24.4		%

	Year Ended
	31 December 2020				31 December 2019
Expected tax at statutory US federal income tax rate	$	(28,715)	21.0	%	$	27,613	21.0	%
State income taxes, net of federal tax benefit	(7,451)		5.4	%	7,946		6.0	%
Federal credits	(80,380)		58.8	%	(7,000)		(5.3)	%
Other, net	3,280		(2.4)	%	3,532		2.7	%
Effective tax rate	$	(113,266)	82.8	%	$	32,091	24.4	%

The Group had a net deferred tax liability of $969 at 31 December 2020 compared to a net deferred tax liability of $124,112 at 31 December 2019. The deferred tax liability decreased by $123,143, primarily due to unrealised losses for unsettled derivatives not recognised for tax purposes, the recognition of federal tax credits, and the utilisation of federal and state net operating losses. The presentation 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 following table presents the components of the net deferred income tax asset included in non-current assets and net deferred income tax liability included in non-current liabilities as at the periods presented:

	31 December 2020		31 December 2019
Deferred tax asset
Asset retirement obligations	$	90,949	$	52,254
Derivative financial instruments	46,237		-
Allowance for doubtful accounts	2,968		841
Net operating loss carryover	474		43,262
Federal tax credits carryover	99,117		19,502
Other	4,160		2,344
Total deferred tax asset	243,905		118,203
Deferred tax liability
Amortisation and depreciation	(244,874)		(228,004)
Derivative financial instruments	-		(14,311)
Total deferred tax liability	(244,874)		(242,315)
Net deferred tax liability	$	(969)	$	(124,112)

Balance sheet presentation
Deferred tax asset	$	14,777	$	-
Deferred tax liability	(15,746)		(124,112)
Net deferred tax liability	$	(969)	$	(124,112)

In assessing the realisability of deferred tax assets, the Group considers whether it is probable that some or all the deferred tax assets will not be realised. The ultimate realisation of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible or before credits expire. The Group considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Group has determined, at this time, to recognise its deferred tax assets.

The Group reported the effects of deferred tax expense as at and for the year ended 31 December 2020:

	Opening Balance		Consolidated Statement of Comprehensive Income		Other ^(a)		Closing Balance
Asset retirement obligations	$	52,254	$	38,695	$	-	$	90,949
Allowance for doubtful accounts	841		2,127		-		2,968
Net operating loss carryover	43,263		(43,181)		392		474
Federal tax credits carryover	19,503		79,614		-		99,117
Property, plant, and equipment and natural gas and oil properties	(228,005)		(20,079)		3,210		(244,874)
Derivative financial instruments	(14,311)		60,548		-		46,237
Other	2,343		1,314		503		4,160
Total deferred tax liability	$	(124,112)	$	119,038	$	4,105	$	(969)

(a) Amounts primarily relate to deferred taxes acquired as part of acquisition purchase accounting.

The Group reported the effects of deferred tax expense as at and for the year ended 31 December 2019:

	Opening Balance		Consolidated Statement of Comprehensive Income		Other ^(a)		Closing Balance
Asset retirement obligations	$	46,893	$	5,361	$	-	$	52,254
Allowance for doubtful accounts	577		264		-		841
Net operating loss carryover	57,081		(13,818)		-		43,263
Federal tax credits carryover	14,365		5,138		-		19,503
Property, plant, and equipment and natural gas and oil properties	(206,795)		(21,210)		-		(228,005)
Derivative financial instruments	(8,488)		(5,823)		-		(14,311)
Other	1,334		1,009		-		2,343
Total deferred tax liability	$	(95,033)	$	(29,079)	$	-	$	(124,112)

(a) No acquisition purchase accounting deferred taxes were recorded in 2019.

The Group's deferred tax assets and liabilities all arise in the US.

For US federal tax purposes, the Group is taxed as one consolidated entity. The Group is subject to additional taxes in its domiciled jurisdiction of the UK. For the years ended 31 December 2020 and 2019, the Group incurred $616 and $142 of income tax liability in the UK, respectively.

The Group had an uncertain tax position liability of $1,837 at 31 December 2020 compared to a liability of $2,133 at 31 December 2019. At the date of acquisition, the Directors determined that Alliance Petroleum had taken uncertain tax positions. The Group had no other uncertain tax positions as at 31 December 2020.

For the year ended 31 December 2020, the Group utilised all of its $196,200 federal net operating loss carryforwards ("NOLs") reported as of 31 December 2019. With the acquisition of Carbon, discussed in Note 5, the Group acquired $1,867 of NOLs, which are subject to limitation. Additionally, the Group has US state NOLs of approximately $2,025, which expire in 2038.

The Group had US federal well tax credit carryforwards of approximately $99,117 at 31 December 2020 compared to $19,502 at 31 December 2019. As discussed earlier, 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. Due to the low commodity price environment, the Group generated $80,380 of federal tax credits and utilised $765 for the year ended 31 December 2020. The tax credits expire in the years 2037 through 2040.

The Group had US federal capital loss carryforwards of $9,904 at 31 December 2020 compared to $17,600 at 31 December 2019. For the year ended 31 December 2020, $7,700 of the capital loss carryforwards expired, and the remaining amounts expire in 2023. The Group does not expect to utilise these carryforwards, and therefore, a deferred tax asset for these carryforwards has not been recorded.

The Group completed a Section 382 study through 31 December 2020 in accordance with the Internal Revenue Code of 1986, as amended. If the Group experiences an ownership change, tax credit carryforwards can be utilised but are limited each year and could expire before they are fully utilised. The study concluded that the Group has not experienced an ownership change as defined by Section 382 since the last ownership change that occurred on 31 January 2018. The Directors expect its tax credit carryforwards, limited by the 31 January 2018 ownership change, to be fully available for utilisation by 2024. Based on the results of the study, it is reasonably possible that a change in shareholder ownership could occur in 2021.

NOTE 9 - 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:

	Year Ended
	31 December 2020		31 December 2019
Income (loss) available to shareholders after taxation	$	(23,474)	$	99,400
Loss on joint and working interest owners receivable	6,931		730
Gain on bargain purchase	(17,172)		(1,540)
(Gain) loss on fair value adjustments of unsettled financial instruments	238,795		(20,270)
(Gain) loss on natural gas and oil programme and equipment	2,059		-
Non-recurring costs	25,046		16,752
Non-cash equity compensation	5,007		3,065
(Gain) loss on foreign currency hedge	-		(4,117)
(Gain) loss on interest rate swap	202		-
Tax effect on adjusting items ^(a)	(62,608)		1,598
Adjusted Net Income	174,786		95,618
Less: Tax effect on adjusting items to Adjusted Net Income	62,608		(1,598)
Depreciation, depletion and amortisation	117,290		98,139
Finance costs	43,327		36,667
Accretion of asset retirement obligations	15,424		12,349
Other (income) expense	421		-
Loss on debt cancellation	-		-
Income tax (benefit) expense	(113,266)		32,091
Hedged Adjusted EBITDA	300,590		273,266

Adjusted EPS - basic	$	0.26	$	0.15
Adjusted EPS - diluted	$	0.25	$	0.15

Hedged Adjusted EBITDA per Share - basic	$	0.44	$	0.43
Hedged Adjusted EBITDA per Share - diluted	$	0.44	$	0.42

(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 ended 31 December 2020 and 2019. These expected statutory rates are presented in Note 8.

NOTE 10 - 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:

		Year Ended
	Calculation	31 December 2020		31 December 2019
Income (loss) available to shareholders after taxation	A	$	(23,474)	$	99,400

Weighted average shares outstanding - basic	B	685,170		641,666
Weighted average shares outstanding - diluted	C	688,348		644,782

Earnings (loss) per share - basic	= A/B	$	(0.03)	$	0.15
Earnings (loss) per share - diluted	= A/C	$	(0.03)	$	0.15

Hedged Adjusted EBITDA per Share - basic	Note 9	$	0.44	$	0.43
Hedged Adjusted EBITDA per Share - diluted		$	0.44	$	0.42

NOTE 11 - NATURAL GAS AND OIL PROPERTIES

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

	Year Ended
	31 December 2020		31 December 2019
Costs:
Beginning balance	$	1,625,884	$	1,148,235
Additions ^(a)	346,385		487,649
Disposals ^(b)	(3,712)		(10,000)
Ending balance	$	1,968,557	$	1,625,884
Depletion and impairment:
Beginning balance	$	(129,855)	$	(55,284)
Period changes	(83,617)		(74,571)
Disposals	-		-
Ending balance	$	(213,472)	$	(129,855)

Net book value	$	1,755,085	$	1,496,029

(a) For the year ended 31 December 2020, $103,991, $117,149 and $7,083 in additions were 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, please refer to Note 19 for additional information. For the year ended 31 December 2019, $385,907 and $40,522 were related to the acquisitions of HG Energy and EdgeMarc, respectively. See Note 5 for additional information regarding these acquisitions.

(b) In September 2020 the Group sold 662 wells in McKean, Forest, and Warren Counties, Pennsylvania. In November 2019, the Group sold the three drilled but uncompleted unconventional wells that were acquired in the EdgeMarc acquisition.

Impairment of Natural Gas and Oil Properties

Having identified an impairment indicator relating to a decline of natural gas and oil prices and the macroeconomic impacts of the Covid-19 pandemic in the half-year accounts, the Directors undertook an impairment test in line with the Group's accounting policy. Having performed this assessment, no impairment was recognised. For the period ended 31 December 2020, the Directors reassessed the indicators of impairment, noting a recovery in pricing and the economic outlook to the Group. As part of this assessment the Directors also evaluated the current and projected impact of climate change on the Group. As a result of their assessment no additional impairment indicators were identified.

For the period ended 31 December 2019, the Directors compared the carrying value of the Group's natural gas and oil properties to their fair values. Based on this review, the carrying value of natural gas and oil properties was not impaired.

NOTE 12 - PROPERTY, PLANT AND EQUIPMENT

The following table summarises the Group's property, plant and equipment for the periods presented:

	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
Depletion and impairment:
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

	Year Ended 31 December 2019
	Buildings and Leasehold Improvements		Equipment		Motor Vehicles		Midstream Assets		Other Property and Equipment		Total
Costs:
Beginning balance	$	8,963	$	2,750	$	18,879	$	292,619	$	2,108	$	325,319
Additions ^(a)(b)	13,691		1,688		220		13,918		97		29,614
Disposals ^(c)	-		-		-		-		-		-
Ending balance ^(d)	$	22,654	$	4,438	$	19,099	$	306,537	$	2,205	$	354,933
Depletion and impairment:
Beginning balance	$	(84)	$	(87)	$	(1,065)	$	(11,166)	$	(28)	$	(12,430)
Period changes	(475)		(1,900)		(6,186)		(12,289)		(700)		(21,550)
Disposals	-		-		-		-		-		-
Ending balance	$	(559)	$	(1,987)	$	(7,251)	$	(23,455)	$	(728)	$	(33,980)

Net book value	$	22,095	$	2,451	$	11,848	$	283,082	$	1,477	$	320,953

(a) Of the $91,356 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. Of the $17,315 in 2019 additions, $7,700 relates to equipment purchased through the Dominion and Equitrans acquisition. See Note 5 for additional information regarding these acquisitions.

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

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

(d) Buildings and Leasehold improvements and motor vehicles is inclusive of right-of-use assets associated with the Group's leases. Refer to Note 21 for additional information.

The Group continued to utilise certain fully depreciated assets during the years ended 31 December 2020 and 2019 with an original cost basis of $3,313 and $1,820, respectively.

NOTE 13 - INTANGIBLE ASSETS

Intangible assets consisted of the following for the periods presented:

	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

	Year Ended 31 December 2019
	Software		Other Acquired Intangibles		Total
Costs:
Beginning balance	$	2,775	$	-	$	2,775
Additions ^(a)	15,047		-		15,047
Disposals	-		-		-
Ending balance	$	17,822	$	-	$	17,822
Accumulated amortisation:
Beginning balance	$	(212)	$	-	$	(212)
Period changes	(1,629)		-		(1,629)
Disposals	-		-		-
Ending balance	$	(1,841)	$	-	$	(1,841)

Net book value	$	15,981	$	-	$	15,981

(a) For the year ended 31 December 2020 additions were related to software enhancements and $2,900 in other acquired intangibles. For the year ended 31 December 2019 additions were related to costs associated with the Group's ERP project.

NOTE 14 - 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 31 December 2020, 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.

• 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.

• 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		31 December 2020
2021
Swaps	186,347	$	2.93	$	-	$	-	$	-	$	-	$	-	$	2,447
Stand-Alone Calls	7,300	-		-		-		2.86		-		-		(2,116)
Basis Swap	106,632	-		-		-		-		-		(0.47)		12,126
Total 2021 contracts	300,279													$	12,457
2022
Swaps	118,884	$	2.81	$	-	$	-	$	-	$	-	$	-	$	(6,817)
Stand-Alone Calls	71,175	3.06		-		-		-		-		-		(20,036)
Basis Swap	33,539	-		-		-		-		-		(0.48)		2,855
Total 2022 contracts	223,598													$	(23,998)
2023
Swaps	88,957	$	2.68	$	-	$	-	$	-	$	-	$	-	$	(1,625)
Stand-Alone Calls	85,392	3.04		-		-		-		-		-		(19,028)
Basis Swap	900	-		-		-		-		-		(0.51)		53
Total 2023 contracts	175,249													$	(20,600)
2024
Swaps	81,739	$	2.66	$	-	$	-	$	-	$	-	$	-	$	(4,845)
Stand-Alone Calls	9,150	2.86		-		-		-		-		-		(3,023)
Total 2024 contracts	90,889													$	(7,868)
2025
Swaps	65,864	$	2.63	$	-	$	-	$	-	$	-	$	-	$	(8,928)
2026
Swaps	42,454	$	2.61	$	-	$	-	$	-	$	-	$	-	$	(8,888)
2027
Swaps	33,820	$	2.60	$	-	$	-	$	-	$	-	$	-	$	(7,343)
2028
Swaps	32,190	$	2.57	$	-	$	-	$	-	$	-	$	-	$	(8,218)
2029
Swaps	29,190	$	2.57	$	-	$	-	$	-	$	-	$	-	$	(8,410)
2030
Swaps	5,450	$	2.50	$	-	$	-	$	-	$	-	$	-	$	(2,557)
Swaptions
1/1/2022-1/12/2022 ^(b)	14,600	$	-	$	-	$	-	$	2.92	$	-	$	-	$	(1,693)
1/10/2024-1/9/2028 ^(c)	14,610	-		-		-		2.99		-		-		(3,837)
1/1/2025-1/12/2029 ^(d)	36,520	-		-		-		2.85		-		-		(7,827)
1/4/2026-1/3/2030 ^(e)	97,277	-		-		-		2.64		-		-		(34,024)
1/4/2030-1/3/2032 ^(f)	42,627	-		-		-		2.64		-		-		(21,453)
Total 2025-2032 contracts	205,634													$	(68,834)
Total natural gas contracts	1,204,617													$	(153,187)

(a) Rates have been converted from Btu to Mcfe using a Btu conversion factor of 1.10.

(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		31 December 2020
2021
Swaps ^(a)	2,130	$	20.73	$	-	$	-	$	-	$	-	$	-	$	(14,983)
Total NGLs contracts	2,130													$	(14,983)

(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		31 December 2020
2021
Sold Swaps	139	$	44.21	$	-	$	-	$	-	$	-	$	-	$	(565)
Long Swaps	306	32.63		-		-		-		-		-		4,770
Collars	121	-		-		52.01		67.72		-		-		809
Total 2021 contracts	566													$	5,014
2022
Swaps	110	$	43.06	$	-	$	-	$	-	$	-	$	-	$	(409)
2023
Swaps	70	37.00		-		-		-		$	-	-		(601)
2024
Swaps	64	37.00		-		-		-		$	-	-		(511)
2025
Swaps	56	37.00		-		-		-		$	-	-		(430)
2026
Swaps	13	37.00		-		-		-		$	-	-		(102)
Total oil contracts	879													$	2,961

INTEREST					Fair Value at
	Principal Hedged		Fixed Rate		31 December 2020
2022
LIBOR Interest Rate Swap	$	150,000	0.45	%	$	(598)

Net fair value of derivative financial instruments					$	(165,807)

Derivative Financial Instruments	Consolidated Statement of Financial Position	31 December 2020		31 December 2019
Assets:
Non-current assets	Derivative financial instruments	$	717	$	3,803
Current assets	Derivative financial instruments	17,858		73,705
Total assets		$	18,575	$	77,508
Liabilities
Non-current liabilities	Derivative financial instruments	$	(168,524)	$	(15,706)
Current liabilities	Derivative financial instruments	(15,858)		-
Total liabilities		$	(184,382)	$	(15,706)
Net assets (liabilities):
Net assets (liabilities) - non-current	Other non-current assets (liabilities)	$	(167,807)	$	(11,903)
Net assets (liabilities) - current	Other current assets (liabilities)	2,000		73,705
Total net assets (liabilities)		$	(165,807)	$	61,802

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 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)
	As at 31 December 2019
	Presented without Effects of Netting		Effects of Netting		As Presented with Effects of Netting
Non-current assets	$	35,657	$	(31,854)	$	3,803
Current assets	93,548		(19,843)		73,705
Total assets	129,205		(51,697)		77,508

Non-current liabilities	(47,560)		31,854		(15,706)
Current liabilities	(19,843)		19,843		-
Total liabilities	(67,403)		51,697		(15,706)

Total net assets (liabilities)	$	61,802	$	-	$	61,802

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

	Year Ended
	31 December 2020		31 December 2019
Net gain (loss) on commodity derivatives ^(a)	$	144,600	$	49,467
Net gain (loss) on interest rate swap	(202)		-
Gain on foreign currency hedge	-		4,117
Total gain (loss) on settled derivative instruments	144,398		53,584
Gain (loss) on fair value adjustments of unsettled financial instruments ^(b)	(238,795)		20,270
Total gain (loss) on derivative financial instruments	$	(94,397)	$	73,854

(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.

The Group enters into derivative contracts to reduce the effect of commodity price volatility on its cash flows, and enters into these contracts at the legal entity level that holds the Group's borrowings. Accordingly, the Group maintains distinct, long-dated derivative contract portfolios for its ABS financings and Term Loan I. The Group also maintains a separate derivative contract portfolio related to its Credit Facility. Infrequently, the Group adjusts portions of its derivative contract portfolio across these legal entities to ensure that it maintains the appropriate level and composition at both the legal entity and full-Group level. During the year ended 31 December 2020, the Group paid $10,963 to modify certain derivative contracts, which it excluded from Hedged Adjusted EBITDA due to their non-recurring nature. Modifications include the quantum of production subject to contracts, the swap or floor price of certain contracts and similar elements of it. Of the $10,963, $3,240 related to the Group's ABS II financing transaction, which refinanced a portion of its Credit Facility borrowings. To facilitate the price protection for ABS II, the Group initiated the necessary derivative contracts required by the lender with a member of its existing Credit Facility. After closing ABS II, the Group novated certain contracts to the legal entity holding ABS II. The remaining payments of $7,723 related to offsetting positions for derivative contracts on its Credit Facility, which the Group recorded as new derivative financial instruments on its Consolidated Statement of Financial Position. For more information on the Group's financing arrangements see Note 22.

NOTE 15 - 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 31 December 2020 and 2019, the Group recorded an allowance for current expected credit losses of $11,082 and $3,210, respectively. The following table summarises the Group's trade receivables. The fair value approximates the carrying value as at the periods presented:

	31 December 2020		31 December 2019
Commodity receivables	$	70,199	$	64,522
Other receivables	7,874		12,612
Total trade receivables	78,073		77,134
Allowance for credit losses ^(a)	11,082		3,210
Total trade receivables, net	$	66,991	$	73,924

(a) For the period ended 31 December 2020 the Group recorded a non-recurring increase in the reserve of joint interest owner receivables of $6,931. Due to the historical low pricing environment, the Group increased the allowance for credit losses related to amounts due from joint interest owners.

NOTE 16 - OTHER ASSETS

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

	31 December 2020		31 December 2019
Other non-current assets
Other non-current assets	$	2,376	$	176
Indemnification receivable ^(a)	1,837		2,133
Total other non-current assets	$	4,213	$	2,309
Other current assets
Prepaid expenses	$	1,681	$	4,317
Other receivables	-		383
Inventory	6,315		5,163
Total other current assets	$	7,996	$	9,863

(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 an indemnification receivable for the amount of $1,837 and $2,133 as at 31 December 2020 and 2019, respectively. In accordance with IFRS 3, the Group assigned acquisition date fair value to the indemnification asset using the same valuation techniques used to determine the acquisition date fair value of the related liability.

NOTE 17 - 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 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 5.

In April 2019, the Group placed 151,515 new shares at $1.52 per share (£1.17) to raise gross proceeds of $230,676 (approximately £177,278). Associated costs of the placing were $8,817.The Group used the proceeds to fund the HG Energy acquisition, discussed in Note 5.

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.

During the year ended 31 December 2019, the Group repurchased 38,662 treasury shares at an average price of $1.36 totalling $52,902. The Group has accounted for the repurchase of these shares as a direct reduction to retained earnings.

All repurchased treasury shares have been cancelled.

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 2018	542,654	$	7,346	$	540,655
Issuance of share capital	151,515	1,972		219,888
Repurchase of shares	(38,662)	(518)		-
Other issues ^(a)	223	-		-
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 years ended 31 December 2020 and 2019, the Group issued 324 and 223 RSUs, respectively, to certain key managers. The RSUs had no impact on share premium.

NOTE 18 - NON-CASH SHARE-BASED COMPENSATION

Equity Incentive Plan

The 2017 Equity Incentive Plan (the "Plan"), as amended through 11 May 2020, authorised and reserved for issuance 50,681 shares of common stock, which may be issued upon exercise of vested Options, RSUs and PSUs, that are granted under the Plan. As at 31 December 2020, 1,023 shares have vested and been made available to Plan participants while 31,110 shares have been granted but remain unvested.

Options Awards

The following table summarises Options award activity for the years ended 31 December 2020 and 2019:

	Number of Shares	Weighted Average Grant Date Fair Value per Share
Balance at 31 December 2018	15,450	$	0.33
Granted	8,520	0.59
Vested	-	-
Forfeited	(300)	0.33
Balance at 31 December 2019	23,670	$	0.42
Granted	-	-
Vested	-	-
Forfeited	(650)	0.37
Balance at 31 December 2020	23,020	$	0.43

The Group's Options ratably vest over a three-year period and contain both performance and service metrics. The performance metrics include Adjusted EPS as compared to pre-established benchmarks and a calculation that compares the Group's TSR to pre-established benchmarks. The number of units that will vest can range between 0% and 100% of the award.

The fair value of the Group's Options are calculated using the Black-Scholes model as of the grant date. The inputs to the Black-Scholes model included the following for Options granted during the years ended 31 December 2020 and 2019:

	31 December 2020			^(a)	31 December 2019
The share price at the date of grant	£	-			£	1.25
Exercise price	£	-			£	1.20
Expected volatility	-		%		31		%
Expected dividends	-		%		-		%
Risk-free rate of interest	-		%		2.25		%
Options life	-				10 years

(a) No Options were awarded during the year ended 31 December 2020.

(b) Volatility was calculated utilising the historical volatility for the Group's share price.

The fair value of the grant of the Group's Options is uniformly expensed over the vesting period.

RSU and PSU Awards

The following table summarises RSU equity award activity for the years ended 31 December 2020 and 2019:

	Number of Shares	Weighted Average Grant Date Fair Value per Share
Balance at 31 December 2018	672	$	0.92
Granted	900	1.30
Vested	(320)	0.91
Forfeited	-	-
Balance at 31 December 2019	1,251	$	1.20
Granted	7,309	1.18
Vested	(470)	1.08
Forfeited	-	-
Balance at 31 December 2020	8,090	$	1.19

RSUs cliff-vest based on service conditions, while PSUs cliff-vest based on three performance criteria which include a three-year average adjusted return on equity as compared to pre-established benchmarks, a calculation that compares the Group's TSR to pre-established benchmarks as well as the same calculated return for a group of peer companies as selected by the Group. The number of units that will vest can range between 0 % and 100% of the award.

The fair value of the Group's RSUs and PSUs is determined using the stock price at the grant date and uniformly expensed over the vesting period.

Share-Based Compensation Expense

The following table presents share-based compensation expense for the respective periods:

	31 December 2020		31 December 2019
Options	$	2,553	$	2,095
RSUs and PSUs	2,483		367
Total share-based compensation expense	$	5,036	$	2,462

NOTE 19 - 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 14 December 2018	$	0.0330	£	0.0253	8 March 2019	29 March 2019	542,654	17,908
Declared on 28 February 2019	$	0.0340	£	0.0239	12 April 2019	28 June 2019	542,654	18,450
Declared on 13 June 2019	$	0.0342	£	0.0278	6 September 2019	27 September 2019	663,636	22,696
Declared on 8 August 2019	$	0.0350	£	0.0269	29 November 2019	20 December 2019	659,903	23,097
Paid during the year ended 31 December 2019								$	82,151
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
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 29 October 2020 the Group proposed a dividend of $0.0400 per share. The dividend will be paid on 26 March 2021 to shareholders on the register on 5 March 2021. This dividend was not approved by shareholders, thereby qualifying it as an "interim" dividend. No liability was recorded in the Group Financial Information in respect of this interim dividend as at 31 December 2020.

Subsequent Events

On 8 March 2021 the Directors recommended a final quarter dividend of $0.0400 per share. The dividend would be paid on 24 June 2021 to shareholders on the register on 28 May 2021, subject to shareholder approval at the AGM. No liability has been recorded in the Group Financial Information in respect of this dividend as at 31 December 2020.

NOTE 20 - 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 over the long producing life of its wells (the Group presently 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 periods ended 31 December 2020 and 2019.

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 2020 and 2019 was 3.7% and 5.0%, respectively.

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

	Year Ended
	31 December 2020		31 December 2019
Balance at beginning of period	$	199,521	$	142,725
Additions ^(a)	26,995		252
Accretion	15,424		12,349
Plugging costs	(2,442)		(2,541)
Disposals	(3,838)		-
Revisions to estimate ^{(b) (c)}	110,464		46,736
Balance at end of period	346,124		199,521
Less: Current asset retirement obligations	1,882		2,650
Non-current asset retirement obligations	$	344,242	$	196,871

(a) See Note 5 for more information about the Group's acquisitions.

(b) 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 plug and abandon wells.

(c) At 31 December 2019, the Group performed normal revisions to its asset retirement obligations which resulted in a $46,736 adjustment, of which $42,650 relates to macroeconomic factors that reduced bond yields and resulted in a lower discount rate applied to our asset retirement obligations liability. The remaining $4,086 relates to pricing-related adjustments based on historical costs incurred to plug and abandon

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 $69,675 impact on the Group's asset retirement obligations as at 31 December 2020.

NOTE 21 - 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
	31 December 2020		31 December 2019
Balance at beginning of period	$	1,813	$	3,536
Additions ^(a)	19,820		1
Interest expense ^(b)	929		-
Cash outflows	(3,684)		(1,724)
Balance at end of period	$	18,878	$	1,813
Classified as:
Current liability	$	5,013	$	798
Non-current liability	13,865		1,015
Total	$	18,878	$	1,813

(a) Of the $19,820 in lease additions, $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
	31 December 2020		31 December 2019
Balance at beginning of period	$	1,868	$	3,454
Additions ^(a)	19,558		-
Depreciation	(3,400)		(1,586)
Balance at end of period	$	18,026	$	1,868
Classified as:
Motor vehicles	$	14,614	$	1,655
Buildings and leasehold improvements	3,412		213
Total	$	18,026	$	1,868

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

	31 December 2020		31 December 2019
Discount rates range	1.8% - 3.3%		3.1% - 4.3%

The undiscounted future cash outflows relating to leases are disclosed in Note 26. Expenses related to short-term and low-value lease exemptions applied under IFRS 16 are disclosed in Note 7.

NOTE 22 - BORROWINGS

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

	31 December 2020		31 December 2019
Credit Facility Weighted average Interest rate of 2.96% (2020) and 4.80% (2019)	$	213,400	$	436,700
ABS I Note Interest rate of 5.00%	180,426		200,000
ABS II Note Interest rate of 5.25%	191,125		-
Term Loan I Interest rate of 6.50%	156,805		-
Miscellaneous, primarily for real estate, vehicles and equipment	4,730		8,219
Total borrowings	$	746,486	$	644,919
Less: Current portion of long-term debt	(64,959)		(23,510)
Less: Deferred financing costs	(23,068)		(22,631)
Less: Original issue discounts	(6,178)		-
Total non-current borrowings, net	$	652,281	$	598,778

Credit Facility

In November 2020, 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 May 2021. Available borrowings under the Group's Credit Facility were $211,600 as at 31 December 2020.

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 31 December 2020 the Group was in compliance with all financial covenants. The fair value of the Credit Facility approximates the carrying value as at 31 December 2020.

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, as discussed in Note 5.

The Term Loan I is secured by the Group's producing assets acquired from Carbon and EQT discussed in Note 5.

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 period ended 31 December 2020, the Group incurred $6,371 in interest related to the Term Loan I which is recognised under the effective interest rate method. The fair value of the Term Loan I approximates the carrying value as at 31 December 2020.

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 31 December 2020 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 2.775% 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 the Group's producing assets, excluding the Group's EdgeMarc assets acquired in September 2019. 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. During the period ended 31 December 2020, the Group incurred $7,563 in interest related to the ABS II Note 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, 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 31 December 2020.

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 31 December 2020 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 the Group's producing assets, excluding the acquired EdgeMarc assets discussed in Note 5. 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 years ended 31 December 2020 and 2019, the Group incurred $9,661 and $1,305 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, 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 31 December 2020.

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 31 December 2020 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:

	31 December 2020		31 December 2019
Not later than one year	$	64,959	$	23,510
Later than one year and not later than five years	450,503		515,620
Later than five years	231,024		105,789
Total borrowings	$	746,486	$	644,919

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

	Year Ended
	31 December 2020		31 December 2019
Interest expense, net of capitalised and income amounts	$	34,391	$	32,662
Amortisation of discount and deferred finance costs	8,334		3,875
Other	602		130
Total finance costs	$	43,327	$	36,667
Loss on early retirement of debt	$	-	$	-

Reconciliation of borrowings arising from financing activities:

	Year Ended
	31 December 2020		31 December 2019
Balance at beginning of period	$	622,288	$	482,814
Proceeds from borrowings	799,650		765,236
Repayments of borrowings	(705,314)		(618,010)
Costs incurred to secure financing	(7,799)		(11,574)
Amortisation of discount and deferred financing costs	8,334		3,875
Interest paid in cash	(34,335)		(32,715)
Finance costs and other	34,416		32,662
Balance at end of period	$	717,240	$	622,288

NOTE 23 - 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:

	31 December 2020		31 December 2019
Trade payables	$	19,218	$	16,700
Other payables	148		352
Total trade and other payables	$	19,366	$	17,052

NOTE 24 - OTHER LIABILITIES

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

	31 December 2020		31 December 2019
Other non-current liabilities
Uncertain tax position ^(a)	$	1,837	$	2,133
Other non-current liabilities ^(b)	11,023		2,335
Total other non-current liabilities	$	12,860	$	4,468
Other current liabilities
Accrued expenses	$	28,582	$	23,645
Taxes payable	18,025		19,379
Net revenue clearing ^(c)	12,561		9,287
Asset retirement obligations - current	1,882		2,650
Revenue to be distributed ^(d)	30,260		30,321
Total other current liabilities	$	91,310	$	85,282

(b) Other non-current liabilities includes the long-term portion of the contingent consideration for the Carbon and EQT acquisitions. For more information please refer to Note 5.

(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.

NOTE 25 - 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):

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

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

(d) 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 Group does not hold derivatives for speculative or trading purposes and the derivative contracts held by the Group do not contain any credit-risk related contingent features. The Directors have elected not to apply hedge accounting to derivative contracts.

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. When derivative assets and liabilities are presented net, the fair value of the right to reclaim collateral assets (receivable) or the obligation to return cash collateral (payable) is also offset against the net fair value of the corresponding derivative. At 31 December 2020 and 2019, there were no collateral assets or liabilities associated with derivative assets and liabilities.

Derivatives expose the Group to counterparty credit risk. The derivative contracts have been executed under master netting arrangements which, in the event of default by its counterparties, allows the Group to elect early termination. The Group monitors the creditworthiness of its counterparties but is not able to predict sudden changes and hence may be limited in its ability to mitigate an increase in credit risk.

Possible actions would be to transfer the Group's positions to another counterparty or request a voluntary termination of the derivative contracts, resulting in a cash settlement in the event of non-performance by the counterparty. For the periods ended 31 December 2020 and 2019, the counterparties for all the Group's derivative financial instruments were lenders under formal credit and debt agreements.

The derivative instruments consist of non-financial instruments considered normal purchases and normal sales.

For recurring and non-recurring fair value measurements categorised within Level 2 and Level 3 of the fair value hierarchy, a description of the valuation technique(s) and the inputs used in the fair value measurement. If there has been a change in valuation technique (ex: changing from a market approach to an income approach or the use of an additional valuation technique), the entity shall disclose that change and the reason(s) for making it.

All financial instruments measured at fair value use Level 2 valuation techniques for the periods ended 31 December 2020 and 2019.

Level 2 fair value measurements are those including inputs other than quoted prices included within Level 1 that are observable for the asset or liability directly or indirectly. The fair value of the swap commodity derivatives is calculated using a discounted cash flow model and the fair value of the option commodity derivatives are calculated using a relevant option pricing model, which are calculated from relevant market prices and yield curves at the balance sheet date and are therefore based solely on observable price information. These instruments are not directly quoted in active markets and are accordingly classified as Level 2 in the fair value hierarchy.

There were no transfers between fair value levels for the periods ended 31 December 2020 and 2019.

Financial Instruments

For trade receivables, the Group applies the simplified approach permitted by 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.

The Group is not a financial institution. The Group does not apply hedge accounting and its customers are considered creditworthy and pay consistently within agreed payments terms.

A classification of the Group's financial instruments for the periods presented is included in the table below:

	Year Ended
	31 December 2020		31 December 2019
Cash and cash equivalents at amortised cost	$	1,379	$	1,661
Trade receivables and accrued income at amortised cost	66,991		73,924
Other non-current assets ^(a)	2,376		176
Other current assets ^(b)	-		383
Other non-current liabilities ^(b)	(11,023)		(2,335)
Other current liabilities ^(c)	(41,143)		(32,932)
Derivative financial instruments at fair value	(165,807)		61,802
Leases	(18,878)		(1,813)
Borrowings	(746,486)		(644,919)
Total	$	(912,591)	$	(544,053)

(a) Excludes indemnification receivables.

(b) Excludes prepaid expenses and inventory.

(d) Excludes taxes payable, asset retirement obligations and revenue to be distributed.

NOTE 26 - FINANCIAL RISK MANAGEMENT

The Group is exposed to a variety of financial risks such as market risk, credit risk, liquidity risk, capital risk and collateral risk. The Group manages these risks by monitoring the unpredictability of financial markets and seeking to minimise potential adverse effects on the Group's financial performance on a continuous basis.

The Group's principal financial liabilities are comprised of borrowings, leases and trade and other payables, used primarily to finance and financially guarantee its operations. The Group's principal financial assets include cash and cash equivalents and trade and other receivables derived from its operations.

The Group also enters into derivative financial instruments which, depending on market dynamics, are recorded as assets or liabilities. To assist with its hedging programme design and composition, the Group engages a specialist firm with the appropriate skills and experience to manage its risk management derivative-related activities.

Market Risk

Market risk is the possibility that the fair value of future cash flows of a financial instrument will fluctuate due to changes in market prices. Market risk is comprised of two types of risk: interest rate risk and commodity price risk. Financial instruments affected by market risk include borrowings and derivative financial instruments. Derivative and non-derivative financial instruments are used to manage market price risks resulting from changes in commodity prices and foreign exchange rates, which could have a negative effect on assets, liabilities or future expected cash flows.

Interest rate risk

The Group is subject to market risk exposure related to changes in interest rates on its variable-rate Credit Facility. The remainder of the Group's financing is fixed-rate. At 31 December 2020 and 2019, the Group had $213,400 and $436,700, respectively, outstanding under its Credit Facility with a weighted average interest rate of 2.96% and 4.80%, respectively. Refer to Note 22 for additional information about the Credit Facility.

The table below represents the impact a 100 basis point adjustment in the interest rate for the Credit Facility and the corresponding impact on finance costs. This represents a reasonably possible change in interest rate risk.

Credit Facility Interest Rate Sensitivity	+100 Basis Points		-100 Basis Points
Finance costs	$	2,134	$	(2,134)

The Group principally manages this risk by entering into fixed rate borrowing obligations with amortising structures facilitating an expedited repayment of principal. To mitigate residual interest rate risk the Group enters into derivative financial instruments. The total principal hedged through the use of derivative financial instruments varies from period to period. See Note 14 for more information on the Group's derivative financial instruments.

As of 31 December 2020, the Group had an interest rate swap ("IR swap") that fixed $150,000 of variable LIBOR interest rate risk. As of 31 December 2019 the Group had no IR swaps. Refer to Note 14 for additional information about the Group's derivative financial instruments.

Commodity price risk

The Group's revenues are primarily derived from the sale of its natural gas, NGLs and oil production, and as such, the Group is subject to commodity price risk. Commodity prices for natural gas, NGLs and oil can be volatile and can experience fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. For the years ended 31 December 2020 and 2019, the Group's commodity revenue was $381,662 and $438,280, respectively.

The Group enters into derivative financial instruments to mitigate the risk of fluctuations in commodity prices. The total volumes hedged through the use of derivative financial instruments varies from period to period, but generally the Group's objective is to hedge approximately 40% to 90% of its anticipated production volumes for the next 36 months. Refer to Note 14 for additional information about the Group's derivative financial instruments.

Credit Risk

The Group is exposed to credit risk from the sale of its natural gas, NGLs and oil. Trade receivables from customers are amounts due for the purchase of natural gas, NGLs and oil. Collectability is dependent on the financial condition of each customer. The Group reviews the financial condition of customers prior to extending credit and generally does not require collateral in support of their trade receivables. At 31 December 2020 and 2019, the Group had one and three customers, respectively, over 10% that made up 11% and 41%, respectively of the Group's total trade receivables from customers. At 31 December 2020 and 2019, the Group's trade receivables from customers were $66,908 and $68,393, respectively.

The Group is exposed to credit risk from joint interest owners, entities that own a working interest in the properties operated by the Group. Joint interest receivables are classified in trade receivables, net in the Consolidated Statement of Financial Position. The Group has the ability to withhold future revenue payments to recover any non-payment of joint interest receivables. Given the historical low pricing environment in 2020, however, the Group increased the allowance for credit losses related to amounts due from joint interest owners by $6,931. At 31 December 2020 and 2019, the Group's joint interest receivables were $83 and $5,531, respectively.

The majority of trade receivables are current and the Group believes these receivables are collectible.

Liquidity Risk

Liquidity risk is the possibility that the Group will not be able to meet its financial obligations as they are due. The Group manages this risk by 1) maintaining adequate cash reserves through the use of cash from operations and bank borrowings, and 2) continuously monitors its forecast and actual cash flows to ensure it maintains an appropriate amount of liquidity. The amounts disclosed in the table are the contractual undiscounted cash flows. Balances due within 12 months equal their carrying balances, because the impact of discounting is not significant.

	Not Later Than One Year		Later Than One Year and Not Later Than Five Years		Later Than Five Years		Total
31 December 2020
Trade and other payables	$	19,366	$	-	$	-	$	19,366
Borrowings	64,959		450,503		231,024		746,486
Lease	5,013		13,865		-		18,878
Other liabilities ^(a)	41,143		11,023		-		52,166
Total	$	130,481	$	475,391	$	231,024	$	836,896
31 December 2019
Trade and other payables	$	17,052	$	-	$	-	$	17,052
Borrowings	23,723		515,407		105,789		644,919
Lease	798		1,015		-		1,813
Other liabilities ^(a)	32,932		2,335		-		35,267
Total	$	74,505	$	518,757	$	105,789	$	699,051

(a) Excludes uncertain tax position, taxes payable, asset retirement obligations and revenue to be distributed.

Capital Risk

The Group defines capital as the total of equity shareholders' funds and long-term borrowings net of available cash balances. The Group's objectives when managing capital are to provide returns for shareholders and safeguard the ability to continue as a going concern while pursuing opportunities for growth through identifying and evaluating potential acquisitions and constructing new infrastructure on existing proved leaseholds. The Directors do not establish a quantitative return on capital criteria, but rather promote year-over-year Hedged Adjusted EBITDA per Share growth. The Group uses its Net Debt-to-Hedged Adjusted EBITDA to monitor capital risk and maintain a target of below 2.5x. See Note 9 for more information on Hedged Adjusted EBITDA.

Collateral Risk

The Group has pledged 51.0% of its natural gas and oil properties, excluding the EdgeMarc acquisition, to fulfil the collateral requirements for borrowings under asset-backed securitisation with its senior secured lenders as part of the ABS I and ABS II transactions. In addition the Carbon and EQT natural gas and oil properties have been pledged to fulfil the collateral obligations of the Term Loan I financing arrangement. The fair value is based on a third-party engineering reserve calculation using a 10% cumulative discount cash flow and a commodities futures price schedule. See Notes 5 and 22 for additional information on acquisitions and debt, respectively.

NOTE 27 - 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 31 December 2020 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.

Previously the Group disclosed it was assessing the interpretation of a US tax rule to determine if the Group would be subject to a maximum withholding tax of $8,800 payable to the US tax authorities in relation to its share buyback programme discussed in Note 17. As of 31 December 2020. the Group completed its review of this matter and concluded that it has no liability for taxes, penalties or interest due related to the US Withholding Tax rule.

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 31 December 2020. 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 28 - RELATED PARTY TRANSACTIONS

UK Legal Counsel

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

	Year Ended
	31 December 2020				31 December 2019
Fees paid to related party legal advisor	$	41	£	33	$	195	£	150

Dividend Payments

In 2019, the Directors became aware that aggregate dividends totalling $82,151 paid during this period had been made otherwise than in accordance with the Companies Act 2006, as unaudited interim accounts had not been filed at Companies House prior to the dividend payments. At a General Meeting of Shareholders held on 15 April 2020, a resolution was passed which authorised the appropriation of distributable profits to the payment of the relevant dividends and removed any right for the Group to pursue shareholders or Directors for repayment. This constituted a related party transaction under IAS 24 "Related Party Disclosures". The overall effect of the resolution being passed was to return all parties, so far as possible, to the position they would have been in had the relevant dividends been made in full compliance with the Companies Act 2006.

NOTE 29 - SUBSEQUENT EVENTS

The Group determined the need to disclose the following material transactions that occurred subsequent to 31 December 2020, which have been described within each relevant footnote as follows:

Description		Footnote
Dividends		Note 19

ALTERNATIVE PERFORMANCE MEASURES (UNAUDITED)

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

DGO 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 in understanding the activity taking place across DGO. 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.

	2020		2019
Declared on first quarter results	$	0.0350	$	0.0342
Declared on second quarter results	0.0375		0.0350
Declared on third quarter results	0.0400		0.0350
Recommended on the fourth quarter results	0.0400		0.0350
Average Dividend per Share	$	0.0381	$	0.0348
Total Dividends per Share	$	0.1525	$	0.1392

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 DGO's hedge portfolio.
	The Directors believe these metrics are useful to investors because they provide a meaningful measure of DGO's profitability before recording certain items whose timing or amount cannot be reasonably determined.

	2020		2019
Income (loss) available to shareholders after taxation	(23,474)		99,400
Loss on joint and working interest owners receivable	6,931		730
Gain on bargain purchase	(17,172)		(1,540)
(Gain) loss on fair value adjustments of unsettled financial instruments	238,795		(20,270)
(Gain) loss on natural gas and oil programme and equipment	2,059		-
Non-recurring costs	25,046		16,752
Non-cash equity compensation	5,007		3,065
(Gain) loss on foreign currency hedge	-		(4,117)
(Gain) loss on interest rate swap	202		-
Tax effect on adjusting items	(62,608)		1,598
Adjusted Net Income	$	174,786	$	95,618

Adjusted EPS - basic	$	0.26	$	0.15
Adjusted EPS - diluted	$	0.25	$	0.15

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 DGO'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 DGO'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 DGO'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 DGO'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 DGO's Credit Facility financial covenants; and (4) is used by the Directors as a performance measure in determining executive compensation.

	2020		2019
Operating profit (loss)	$	(77,568)	$	180,507
Depreciation, depletion and amortisation	117,290		98,139
Loss on joint and working interest owners receivable	6,931		730
Gain on bargain purchase	(17,172)		(1,540)
(Gain) loss on natural gas and oil programme and equipment	238,795		(20,270)
(Gain) loss on fair value adjustments of unsettled financial instruments	2,059		-
Non-recurring costs	25,046		16,752
Non-cash equity compensation	5,007		3,065
(Gain) loss on foreign currency hedge	-		(4,117)
(Gain) loss on interest rate swap	202		-
Total adjustments	$	378,158	$	92,759
Hedged Adjusted EBITDA	$	300,590	$	273,266
Less: Cash portion of settled commodity hedges	(144,600)		(53,584)
Unhedged Adjusted EBITDA	$	155,990	$	219,682

Net Debt, 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 DGO's current portion of debt, Credit Facility borrowings and term loan borrowings. Net Debt is a useful indicator of DGO'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 DGO's financial liquidity and flexibility and is used in the calculation of a key metric in one of DGO's Credit Facility financial covenants.

	2020		2019
Cash	$	1,379	$	1,661
Restricted cash	20,350		7,712
Credit Facility	(213,400)		(436,700)
ABS I Note	(180,426)		(200,000)
ABS II Note	(191,125)		-
Bluegrass Note	(156,805)		-
Other	(4,730)		(8,219)
Net Debt	$	(724,757)	$	(635,546)

Hedged Adjusted EBITDA	$	300,590	$	273,266
Pro forma Hedged Adjusted EBITDA ^(a)	$	333,940	$	319,470

Net Debt-to-Hedged Adjusted EBITDA	2.2x		2.0x

(a) Pro forma Hedged Adjusted EBITDA includes adjustments in 2020 for the EQT, Carbon and Utica Shale acquisitions to pro forma their results for a full year of operations. A similar adjustment was made in 2019 to pro forma results for the HG and EdgeMarc acquisitions.

Hedged Adjusted EBITDA per Share	The Directors believe that Hedged Adjusted EBITDA per Share provides direct line of sight into the Group'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.

	2020		2019
Weighted average shares outstanding - diluted	688,348		644,782
Hedged Adjusted EBITDA	$	300,590	$	273,266
Hedged Adjusted EBITDA per Share	$	0.44	$	0.42

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 DGO'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 the Group's Cash Operating Margin. The Directors believe that Cash Operating Margin is a useful measure of DGO'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 DGO's profitability and efficiency as well as its earnings quality.

	2020			2019
Total revenue	$	408,693		$	462,256
Commodity hedge impact	144,600			49,467
Adjusted Total Revenue	553,293			511,723
LESS: Operating expense	(203,963)			(202,385)
Total Cash Operating Income	349,330			309,338
LESS: Adjusted G&A	(47,181)			(36,072)
LESS: Allowance for credit losses - recurring	(1,559)
Hedged Adjusted EBITDA	$	300,590		$	273,266

Cash Margin	54		%	53		%
Cash Operating Margin	63		%	60		%

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 and cash interest expense. The Directors believe that Free Cash Flow is a useful indicator of DGO'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 DGO's total market capitalisation. The Directors believe that, like Free Cash Flow, Free Cash Flow Yield is an indicator of financial stability and reflects DGO's operating strength relative to its size as measured by market capitalisation.

	2020			2019
Hedged Adjusted EBITDA	$	300,590		$	273,266
LESS: Recurring capital expenditures	(15,981)			(17,255)
LESS: Plugging and abandonment costs	(2,442)			(2,541)
LESS: Cash interest expense	(34,335)			(32,715)
Free Cash Flow	$	247,832		$	220,755

Pro forma Free Cash Flow ^(a)	$	281,182		$	266,959
Average share price	$	1.21		$	1.22
Weighted average shares outstanding - diluted	688,348			644,782
Free Cash Flow Yield	34		%	34		%

(a) Pro forma Free Cash Flow includes adjustments in 2020 for the EQT, Carbon and Utica Shale acquisitions to pro forma their results for a full year of operations. A similar adjustment was made in 2019 to pro forma results for the HG and EdgeMarc acquisitions.

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.

	2020		2019
Total production (MBoe)	36,538		30,944

Total operating expense	$	203,963	$	202,385
Adjusted G&A	48,740		36,073
Total Cash Cost	$	252,703	$	238,458

Total Cash Cost per Boe	$	6.92	$	7.71

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.

	2020		2019
Total G&A	$	77,234	$	55,889
LESS: Non-recurring and/or non-cash G&A ^(a)	(30,053)		(19,816)
Base G&A ^(b)	$	47,181	$	36,073
Recurring allowance for expected credit losses	1,559		-
Adjusted G&A ^(c)	$	48,740	$	36,073

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

(c) Adjusted G&A includes all of the same items as Base G&A then also include recurring allowance for expected credit losses.

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