Diversified Gas and Oil PLC Announces Interim Results

BIRMINGHAM, AL / ACCESSWIRE / August 10, 2020 / London-LSE quoted Diversified Gas & Oil PLC (LSE:DGOC); "DGO" or the "Company"), the U.S. based owner and operator of natural gas, natural gas liquids and oil wells as well as midstream assets, announces its Interim Results for the six months ended 30 June 2020.

Highlights

Key Highlights

June 2020 exit rate net production of 109.0 MBoepd (653.8 MMcfepd)
- Exit rate net production of 18.7 MBoepd (112.0 MMcfepd) from the EQT Corporation ("EQT") and Carbon Energy ("Carbon") acquisitions completed in May 2020 (collectively, the "Acquisitions")
- 1H20 Legacy¹ assets maintained at ~70 MBoepd for 8^th consecutive quarter
- 1H20 average net production of 95.1 MBoepd (570.9 MMcfepd) (1H19: +26% vs 75.3 MBoepd; 2H19: +1% vs. 94.2 MBoepd)

1H20 Adjusted EBITDA²of $146 million (1H19: +11% vs $131 million; 2H19: +3% vs. $142 million)
Net income of $18 million (1H19: -71% vs $62 million; 2H19: -51% vs $37 million)
- Net operating loss of $(31) million (1H19: -129% vs $108 million; 2H19: -142% vs $73 million) includes a $110 million non-cash charge to mark derivative contracts to fair value
- Net income also includes an offsetting $70 million benefit from federal well tax credits related to wells with production of less than 90 Mcf/day
- Cash derivative contract settlements of $83.5 million during the period significantly offset historically low commodity prices; Unsettled derivative contracts had a net current asset value of $61.5 million at 30 June 2020
Declared 2Q20 interim dividend of $0.0375 per share (1Q20: $0.035), an increase of 7% reflecting the Board's confidence in the Company's outlook
Total cash operating expenses, including total operating expenses and Adjusted General and Administrative² expenses, of $7.05/Boe ($1.17/Mcfe) (1H19: -15% vs $8.30/Boe; 2H19: -2% vs $7.24/Boe)

Completed transition to the Premium Segment of the Main Market of the London Stock Exchange from AIM
Completed upstream and midstream asset acquisitions from EQT ($125 million) and Carbon ($110 million) in May financed through successful $86 million (gross) share placing and $160 million (gross) amortising 10-year term loan underwritten by Munich Re Reserves Risk Financing, Inc. ("MRRF")

Other Financial Highlights

Base Lease Operating Expense of $2.50/Boe ($0.42/Mcfe) (1H19: -34% vs $3.78/Boe; 2H19: -15% vs $2.93/Boe)
55% Cash Margin² in 1H20 (1H19: 54%; 2H19: 53%), supported by a $2.70/MMBtu average 1H20 natural gas hedge price
1H20 Free Cash Flow² of ~$120 million supports $47 million in distributed shareholder dividends and $16 million in share buybacks in the year to date
- 32% Free Cash Flow Yield² in 1H20 (1H19: 26%; 2H19: 26%)

Closed a $200 million (gross) fully-amortising financing to refinance a portion of the Company's revolving credit facility
June 2020 liquidity (including available cash) of $220 million reflective of a successful, full reaffirmation of the $425 million borrowing base
Net Debt-to-Adjusted EBITDA² of 2.2x

Rusty Hutson, Jr., CEO of Diversified, commented:

"I'm pleased to report another successful period of stable production that recently surpassed the 100 MBoepd milestone, healthy cash generation funding an increasing dividend and prudent growth as we navigate a global pandemic and commodity price volatility. In traditional Diversified fashion, we have remained busy over the past several months, and as an essential services provider, our operations continue without interruption or negative impact from COVID while our teams work diligently to integrate the recent acquisition of assets from EQT and Carbon.

"Our field operations have continued to deliver with production from our Legacy assets essentially flat for the past eight consecutive quarters as they continue to execute our Smarter Well Management programme while they also work diligently to integrate the recently acquired assets from EQT and Carbon. Our finance team successfully funded the recent acquisitions and further strengthened the balance sheet with the closings of two secured, amortising financing transactions and an equity raise which combined totaled nearly $450 million in aggregate. Notably, our teams did all of this while supporting our successful transition from AIM to the Premium Segment of the London Stock Exchange.

"Our commitment to an opportunistic yet fiscally disciplined business strategy continues to deliver tangible results for our shareholders with nearly $150 million of adjusted EBITDA during the first half of the year, supported by a robust hedge portfolio and low operating costs that underpin a 55% cash operating margin including operating and all administrative cash costs. While others have been forced to cut or suspend their dividends over the past several months, the strength and durability of our cash flows allow us to not just sustain but to increase our second quarter dividend by 7% to 3.75 cents per share, wholly reflective of the confidence the Board has in the near-medium-term outlook for the business.

"As we enter the second half of 2020 with approximately $220 million of total liquidity, a healthy balance sheet and with a focused and efficient operation, we are well-positioned to capitalise on the opportunities these challenging times create, all with our unrelenting focus on creating long-term value for shareholders."

¹ Legacy assets defined as assets owned at 31 December 2018 and excluding the Company's 2019 and 2020 acquisitions of HG Energy, EdgeMarc Energy, EQT and Carbon.

² This non-IFRS alternative performance measure referenced throughout is defined and reconciled within the Company's Interim Report under the caption "Alternative Performance Measures".

Conference Call and Webcast

The Company will host a conference call and webcast on Monday, 10 August 2020 at 11:00 a.m. BST (5:00 a.m. CDT) to discuss the interim financial and operating results. To participate, dial international toll-free 800-756-3429 or US toll-free 877-407-5976. The conference call will webcast live at https://www.dgoc.com/news-events/ir-calendarevents and will be available as a replay, subsequent to the event.

A mid-year results presentation will be posted to the Company's website before the conference call and webcast. The presentation can be found at https://ir.dgoc.com/presentations.

Company Contact: Teresa Odom, VP Investor Relations | IR@dgoc.com | 205 408 0909

DIVERSIFIED GAS & OIL PLC

Strategic Review

(Unaudited)

Focused Execution Creates Opportunities in a Challenging Environment

I am pleased to provide shareholders of Diversified Gas & Oil PLC ("DGO" or the "Company") with an overview of another eventful period, during which, we:

Uplisted to the Premium Segment of the Main Market at the London Stock Exchange;
Completed two acquisitions (the "Acquisitions") for $235 million (gross) producing ~18,100 Boepd;
- EQT Corporation ("EQT") upstream assets ($125 million) producing ~9,000 Boepd;
- Carbon Energy ("Carbon") upstream assets ($110 million) producing ~9,100 Boepd; and
- Financed by
  - $85 million (gross) equity raise; and
  - $160 million ten-year fully-amortising term loan (the "Term Loan I") with Munich Re, underpinned by a long-term hedging programme.
Refinanced a portion of our Credit Facility with a successful $200 million (gross) fully-amortising note ("ABS II Note") with Nuveen (investment manager of ESG-focused TIAA) as the lead investor, underpinned by a long-term hedging programme matching long-term assets with low-cost, long-term financing; and
Solidified nearly $220 million in liquidity by completing the redetermination of the borrowing base of our Credit Facility with a successful re-affirmation of the $425 million base.

Collectively, these successes reflect our commitment to create long-term shareholder value through a relentless focus on:

Maintaining a healthy balance sheet, strong liquidity and systematic debt repayment;
Pursuing disciplined growth;
Utilising our long-life, low -decline asset base to secure long-term hedges to solidify our cash flows; and
Continuing to drive operational excellence that improves production, lowers costs and ultimately generates high cash margins to strengthen the visibility to consistent, reliable dividends even during periods of low commodity prices.

While our operations were essentially unaffected by the global COVID-19 pandemic, we have observed volatility in commodity prices and uncertainty for the broader economy. For financially healthy companies like DGO, these times provide rare opportunities for growth and to create long-term shareholder value through responsible, consistent execution of our clearly stated strategy.

Today, with an expanded base of low-decline wells across which to deploy our Smarter Well Management programmes, we remain focused on delivering impressive operational and financial results. Additionally, we remain diligent in our efforts to reduce leverage and maintain a strong financial profile, which we've enhanced by replacing interest-only Credit Facility debt with fully-amortising structures. Today, approximately two-thirds of our debt resides in these stable, declining structures, and we have once again demonstrated that our business model, supported by a proactive hedging policy, positions us to generate compelling margins and returns in future periods.

Financial Results Overview

For the six months ended 30 June 2020, we recorded net income of $18 million and Adjusted EBITDA[1] of $146 million. These results reflect average production of 95 MBoepd, including one month's contribution from the Acquisitions, which continues to benefit from our Smarter Well Management programme and continues to maintain our Legacy production at nearly 70 MBoepd. Historically low commodity prices drove a 23% decline in commodity revenue, which was offset by a 1,025% increase in our net cash settlements from commodity derivative contracts, demonstrating the strength of our robust hedging programme.

We also reported a gross profit of $30 million and a net operating loss of $31 million, reflective of the low commodity prices and non-cash $110 million charge to adjust our long-dated derivative contract portfolio to their estimated current market value. Our proactive hedging programme and low-cost operating structure sustained an operating Cash Margin¹ above 50%, since the second half of 2018. As we look out across the natural gas futures price curve, we're encouraged to see supply rebalancing and thus providing a foundation for higher prices. To reduce the volatility of our cash flows and to support our long-life, low-cost financing strategy, we utilise long-tenor hedging to provide price protection on a portion of our production for up to 10 years.

Of course, while we benefit from rising prices on the unhedged volumes we produce and sell, higher prices can generate non-cash mark-to-market valuation adjustments on existing derivative contracts, particularly those that are long-dated with significant time-related option value. As we see the futures natural gas price curve, signaling higher prices, certain of our long-term derivatives sit in a liability position.

While at 30 June 2020, our commodity derivative contract portfolio reflects a net $40 million liability, when we compare the futures price curve to our actual hedged prices, the cash settlement value of the portfolio is a positive $31 million, which will positively impact our cash flow. This analysis demonstrates that the contracts' option value over such a long horizon drives the estimated net liability balance. As time passes and the option time value declines, absent changes to the future price curve, this liability will decline with no impact to cash flow.

During the first half of 2020, we received approximately $84 million from our derivative contract settlements, and they are poised to continue positively contributing to our cash flow, with a $62 million net current asset value. Net income also includes the benefit of significant federal tax credits we earn from producing gas in a low price environment that sustains hundreds of jobs and pays millions of dollars of production taxes into the local economies in which we operate. These tax benefits of approximately $70 million in 2020, not only offset much of the current-period non-cash unsettled derivative contracts valuation adjustment, but more importantly may offset significant federal cash taxes for several years based on current earnings levels.

Corporate Milestones

Reflective of a differentiated business model, we successfully secured both debt and common equity financing during a time when these markets have been firmly closed to most U.S. producers. We used this access to further strengthen our balance sheet, positioning us for continued success in the current environment.

We began the year welcoming Credit Suisse, Goldman Sachs and Morgan Stanley to the lending syndicate, increasing our Credit Facility lending group to 17 banks, and further enhancing the suite of available hedging counterparties to protect our cash flow. We rounded out the half-year in the midst of a turbulent market environment with this group of banks collectively reaffirming our borrowing base at $425 million, whilst many other producers saw their facilities reduced as the result of lower commodity prices. Our lenders' reaffirmation is a testament to the quality of our low-decline, long-life reserves and their confidence in our team's ability to continue the successful progression of our strategy.

Beyond our bank syndicate, in April 2020, we announced the ABS II Note, principally anchored by ESG-focused investors like Nuveen, the investment manager of TIAA. The ABS II Note is fully-amortising over 8.5 years and has a 5.25% fixed -rate coupon demonstrating our commitment to prudently use our Free Cash Flow¹ to repay debt ratably over time supported by our robust hedging portfolio and long-life, low-decline assets.

In May, we funded a portion of the Acquisitions with the Term Loan I, underwritten and funded by Munich Re Reserve Risk Financing, Inc. "(MRRF"), a wholly-owned subsidiary of Munich Re. While its 6.5% fixed coupon is slightly higher than the ABS II Note, and reflects a widening in credit spreads during the pandemic, the rate supports an accretive addition of assets to our asset portfolio and benefits from its own 10-year hedge portfolio to protect the financed assets' underlying cash flows. MRRF's financing of the secured term loan marked the second time in seven months that it invested in our business model, increasing their investment in Diversified to $360 million including its investment in our inaugural $200 million fully-amortising note ("ABS I Note") in November 2019.

To complement the Term Loan I and complete our funding of the Acquisitions, we completed a successful equity raise of approximately $85 million from a broadening base of institutional investors.

During the last nine months, we successfully completed three financings, the ABS I Note, ABS II Note and Term Loan I, that refinanced at more compelling rates than Credit Facility borrowings, thus reducing our reliance on the bank syndicate and eliminating redetermination risk. As a result, approximately 72% of our debt now sits within fully-amortising structures over an eight to ten year period, which provides visibility to our declining leverage and eliminates the refinancing risk associated with bullet maturities. We have proactively positioned ourselves with a strong balance sheet and supportive group of lenders to pursue growth opportunities.

Turning to the Acquisitions, for $112 million (net of customary purchase price adjustments to the effective date) we acquired from EQT approximately 900 net operated conventional and unconventional wells along with the related infrastructure. Due to the geographic concentration of these wells within our own existing operational footprint, we have been able to leverage our talented Legacy field personnel to manage the assets, successfully folding these wells into our portfolio. The EQT assets also included 13 wells classified as proved, developed non-producing, or PDNP, which offer additional upside to the transaction since we allocated no value to these wells in our valuation. We are currently evaluating these wells to determine the time and costs required to turn them to production. Notably, this purchase marks the second package of wells we purchased from EQT (the first being the $575 million largely conventional package of wells in mid-2018) demonstrating the value of our established, in-basin relationships as EQT and others pursue strategic initiatives such as asset sales to reduce debt, focusing their operations around core areas, or both.

The Acquisitions also included approximately 6,100 conventional wells and 4,700 miles of midstream assets from Carbon for cash consideration of $98 million (net of customary purchase price adjustments to the effective date). Strategically, the addition of these midstream assets expands our midstream system to nearly 17,000 miles and enhances our ability to (1) control the flow of our own production, (2) access premium priced markets, and (3) generate third-party revenue by transporting others' production on the system. We recognised immediate synergies from the acquisition of these geographically proximate assets by retaining approximately 80% of the existing Carbon workforce, reducing associated payroll expense by approximately 25%.

The Acquisitions in total add approximately 6,900 conventional and some 70 unconventional producing wells to our Appalachian portfolio. The conventional wells further establish our presence throughout the basin, uniquely allowing us to rapidly scale our operations. Adding the unconventional wells to the portfolio with their higher per-well production rates allows us to leverage the fixed costs of an already assembled workforce and further reduce unit-level operating costs.

Having closed on the Acquisitions, we now turn our attention to the successful integration of these assets into our Smarter Well Management Programme with its proven ability to enhance well productivity while reducing unit-level expenses. Inclusive of these newly acquired assets, we exited the mid-year with net daily production of 109 MBoepd.

Strong Cash Flow Translates to Dividends and Liquidity

Our focus on acquiring assets from which we can generate healthy Free Cash Flow¹, even in an environment of lower commodity pricing, remains central to our business model. Our discipline in properly valuing acquired assets, protecting the associated cash flows with an opportunistically placed hedge portfolio and proactively working to enhance the assets' productivity and reduce expenses, ensures their accretion to earnings and dividends. This period was no exception as we maintained a strong Cash Margin¹ of 55% through the six months ended 30 June 2020, exited the half-year with a Free Cash Flow Yield¹ of 32% and increased our 2Q20 dividend by 7% over the 1Q20 dividend.

Our long-life, low-decline assets require minimal ongoing capital expenditures, thus generating significant Free Cash Flow¹. Since our 2017 IPO, we've consistently distributed approximately 40% of this Free Cash Flow¹ to our shareholders through our stable dividend with a similar amount allocated to debt repayments. Over the same time period, our dividends paid and declared are approximately $218 million and total $166 million paid through June 2020. With a consolidated Trailing Twelve Month ("TTM") Net Debt-to-Adjusted EBITDA¹ at 30 June 2020 of 2.19x and approximately $220 million in liquidity, inclusive of cash and availability on our Credit Facility, we are well-positioned to respond to opportunities that create long-term shareholder value.

During this period of economic uncertainty stemming from the COVID-19 pandemic, companies across all sectors have cut, suspended or eliminated their dividends, and volatile commodity prices have increased the strain on companies within our sector. Our sustained dividend differentiates us from our peers, and in the first six months of this year we have paid more than $47 million in dividends. Further, differentiating our model and following another operating period of consistent and strong cash flows, our Board is pleased to declare an interim dividend of 3.75 cents per share in respect of the three-month period ended 30 June 2020, which as previously mentioned is 7% higher than the immediately preceding period per share dividend.

Commodity Volatility

For the six months ended 30 June 2020, we recorded net income of $18 million and Adjusted EBITDA¹ of $146 million. Net income was largely reflective of a $110 million non-cash loss on unsettled mark-to-market derivatives partially offset by $70 million in federal well tax credits while Adjusted EBITDA¹ was primarily driven by the strength of our hedge portfolio and high-margin assets.

Commodity price volatility continued during the first half of 2020 when realised natural gas prices (unhedged) averaged $1.67/Mcf, well below that of our realised natural gas prices (hedged) of $2.34/Mcf for the period. The strength of our well-placed commodity hedges contributed to a total $84 million settled hedge gain for the period and drove an Adjusted EBITDA¹ of $146 million. Current forward commodity prices have since begun to rebound, driving natural gas prices in excess of our longer tenor portfolio hedged prices and generating a $110 million non-cash mark-to-market loss on unsettled derivatives as of 30 June 2020. The non-cash loss on derivatives adversely impacted net income of $18 million for the period. The rebound in commodity prices, however, does bode well for our future revenue as future unhedged production stands to benefit from higher market prices.

Our relentless focus on expense management has served to bolster our already lean cost structure and to meaningfully offset lower commodity prices as experienced in the first half of 2020. Our daily operational goals focus on "Efficiency-every dollar counts" and "Production-every unit counts" and empower our employees to seek out and implement cost reducing processes and activities so we can thrive in any commodity price environment and continuously return value to our shareholders.

Our focus on expense management is only half the story as we strive to fully enhance margins with a proactive and consistent hedging policy. Our prudent risk management practices result in timely layering in short and long-term hedge protection in the form of financial NYMEX swaps, collars and basis swaps. We strategically execute NYMEX hedges when the respective prices move higher, or add basis hedge protection when prices move lower, and basis differentials are often compressed. Our long-life, Free Cash Flow asset portfolio dictates a longer-term approach to hedging than most of peers in our industry. The longer-tenor hedges in our portfolio not only insulate our fully-amortising debt from commodity price volatility, they also add durability to our cash flows and support a consistently strong dividend to our shareholders.

We also seek to minimise the impact of lower commodity prices with our vertically integrated upstream and midstream systems by strategically moving gas production to alternative accessible markets. Our midstream system provides important flow assurance and allows us to nimbly shift transportation of our production to more attractively priced markets to capture value beyond the wellhead.

Continued Operational Excellence

We are living in an unprecedented, challenging time with the global COVID-19 pandemic which is having a substantial impact to people and economies around the world. I would like to thank our more than 1,000 employees at DGO who have quickly adapted to these challenging times to ensure the uninterrupted production of low-cost, reliable energy for the communities in which we operate. It is a testament to the daily commitment and care of our family that we have managed through this time with unwavering perseverance and dedication to deliver operational excellence.

With a midstream system that now spans approximately 17,000 miles, we similarly expand our "Acquire-Optimise-Produce" business model to be "Acquire-Optimise-Produce-Transport' to better reflect our strict focus on cost discipline and operational efficiencies. While we fully integrate our newly acquired EQT and Carbon assets, we continue to engage in daily activities in both our upstream and midstream operations that seek to increase production, minimise costs, and maximise revenue - all of which contribute to our ongoing ability to fund dividends and reduce leverage. Some of the many examples of these activities within our midstream system include:

Transporting gas production to premium-priced markets and re-routing Btu-rich gas from NGL processing plants during periods of low NGL prices to maximise realised prices;
Right-sizing and eliminating redundant or leased compression equipment to help ensure flow control and optionality in addition to lowering operating expenses and increasing production; and
Gathering and transporting third-party gas volumes to optimise assets and further supplement revenue.

ESG and Corporate Responsibility

Environment and Sustainability

As announced in our full-year results and evidenced by our inaugural Sustainability Report in March of this year, our Board and Management team continue to place significant focus on ESG. We believe wisely stewarding the resource already developed by our industry is central to ESG. Accordingly, we've placed particular emphasis on effectively managing later-life producing wells to fully realise their productive lives before safely and responsibly retiring those wells.

With approximately 99% of our total production coming from natural gas and NGLs, we are supporting the U.S.' drive to reduce carbon dioxide emissions. Approximately 37% of total U.S. natural gas supply comes from Appalachia, and that production continues to be a major contributor to the consistent and substantial reductions in U.S. carbon dioxide emissions as natural gas fills the market share lost by coal and oil. The positive environmental benefits of increased natural gas consumption for energy generation are evident when you consider that natural gas emits approximately 50% less carbon dioxide emissions compared to coal.

Our business model is built on the concept of sustainability - we acquire neglected or non-core assets and then focus on optimising their productivity or usefulness until the end of their natural lives. This model works for both our upstream and midstream assets where we consistently engage in smarter "asset" management activities that not only reduce unit operating costs, create efficiencies and increase margins but also eliminate potential associated emissions that may be present. We recently enhanced our emission detection efforts with the implementation of multiple hand-held leak detection devices capable of detecting flows as small as one part per million of methane in the air. While these devices serve to aid in the detection of carbon emissions, they do not replace the daily efforts our well tenders apply in inspections of the wells, related equipment or midstream assets during their routine well site visits.

We also serve as good stewards of the environment in our cooperative agreements for the retirement of wells within our operating states. In March 2020, we extended our original five-year definitive asset retirement agreement with the state of Ohio by an additional five years, now covering asset retirement activities through the period ending 31 December 2029. This action brings all our retirement agreements, alongside those in Kentucky, West Virginia and Pennsylvania, to a minimum of 10 years - establishing ourselves as a long-term partner with our primary states of operation and providing us with operational and financial stability and visibility in regard to the plugging programme.

In the year to date, we have retired 52 wells at an average cost of $24,779 per well as compared to our expected average cost to retire of $25,054 per well, in line with our cost estimates and reflective of our diligence to plug wells safely and efficiently. These retirements represent approximately 60% of our current year retirement obligation as per the agreements. Since inception of our retirement agreements with the states in 2018, we have now retired 192 wells at an average cost of $23,463 per well.

Social

During this ongoing COVID-19 pandemic, we remain fully committed to the health and safety of our employees and the citizens of the communities in which we operate. We are pleased to report that though this unprecedented time has been economically challenging for many individuals and companies, DGO has not experienced similar difficulty and instead has incurred no personnel layoffs nor reduced the salaries or benefits paid to any of our employees. In fact, as part of our continued growth through acquisitions, we welcomed 124 employees to the Diversified family who came from the Carbon acquisition and we extended the same excellent health and wellness benefits to these newest team members. Additionally, as part of our expanding employee resources, our new team members are also eligible to participate in our recently adopted company-wide educational assistance programme which encourages continuing education in job-related areas or that may lead to promotional opportunities within our company.

Governance

As an acquisitive company, we've experienced tremendous change and growth since our IPO on AIM in February 2017, spending during this time nearly $1.7 billion to acquire accretive, cash generative assets that have allowed us to build both scale and operating synergies. The AIM was a tremendous springboard for us in our pursuit to establish and build our position on the London market through the successful execution of a clearly defined growth strategy. As a result of that growth and after just three years, we announced last year our intention to obtain admission to the Premium Segment of the London Stock Exchange, and we saw that goal come to fruition in May with our move up to the Main Market. We believe the move to the Main Market, among many benefits, provides a better suited and enlarged funding platform to continue the execution of our growth plan that is driven by both a disciplined fiscal policy and rewarding dividend policy.

Our step up to the Main Market came under the vision and leadership of a governance structure that was also transforming. Last year, we increased the composition, independence and diversity of our Board with the addition of three new independent non-executive Directors. We named an independent Board Chairman and Lead Director, and also appointed independent non-executive Directors to chair the Audit & Risk, Remuneration, and newly created Sustainability & Safety committees of the Board. We further appointed new independent legal advisors, accounting auditors and reserve auditors. A move to the Main Market inherently brings with it a commitment to strong governance, reporting and operating standards, and we believe these Board and advisory changes will support that commitment as we progress our strategy.

Positive Outlook

Despite the current market backdrop, we are well-positioned to step into the second half of 2020 and continue to do what we do best - engage in operational activities that minimise cost and maximise production; create value through opportunistic hedging practices and value-adding financing arrangements; and, strive to maintain a clear line of sight to cash flows that provide strong shareholder returns and drive debt reductions. As near-term priorities, we will continue to integrate the EQT and Carbon assets and identify value-deriving smarter "asset" management activities for both the existing and newly acquired upstream and midstream assets.

This lingering period of low commodity prices has not been helpful for our natural gas and oil industry peers who have traditionally focused on expensive growth through the drill bit and now find themselves over-leveraged and with near-term maturities that must be satisfied. Recognising the need to lower costs and generate positive cash flow, those companies are now being forced to reevaluate their portfolios and determine what assets they can trim to best re-fortify their balance sheets. As these companies work to realign their forward growth and financial strategies, we believe it will provide ample opportunity for continued complementary and accretive growth for us, and we continue to look for such opportunities.

Financial Review

	Six Months Ended
	30 June 2020			30 June 2019			Change		% Change
Net production
Natural gas (MMcf)	94,043			73,196			20,847		28	%
NGLs (MBbls)	1,453			1,313			140		11	%
Oil (MBbls)	190			189			1		1	%
Total (MBoe)	17,317			13,701			3,616		26	%
Average daily production (Boepd)	95,148			75,696			19,452		26	%
% Gas (Boe basis)	91		%	89		%

Average realised sales price *(excluding impact of derivatives settled in cash)*
Natural gas (Mcf)	$	1.67		$	2.66		$	(0.99)	(37)	%
NGLs (MBbls)	4.84			14.04			(9.20)		(66)	%
Oil (MBbls)	36.33			53.16			(16.83)		(32)	%
Total (MBoe)	$	9.86		$	16.30		$	(6.44)	(40)	%

Average realised sales price *(including impact of derivatives settled in cash)*
Natural gas (Mcf)	$	2.34		$	2.64		$	(0.30)	(11)	%
NGLs (MBbls)	16.76			21.08			(4.32)		(20)	%
Oil (MBbls)	51.87			52.96			(1.09)		(2)	%
Total (MBoe)	$	14.69		$	16.84		$	(2.15)	(13)	%

Revenue (in thousands)
Natural gas	$	156,900		$	194,810		$	(37,910)	(19)	%
NGLs	7,029			18,439			(11,410)		(62)	%
Oil	6,903			10,048			(3,145)		(31)	%
Total commodity revenue	$	170,832		$	223,297		$	(52,465)	(23)	%
Other revenue	663			1,396			(733)		(53)	%
Midstream revenue	13,383			12,765			618		5	%
Total revenue	$	184,878		$	237,458		$	(52,580)	(22)	%

Gains (losses) on derivative settlements (in thousands)
Natural gas	$	63,233		$	(1,780)		$	65,013	(3,652)	%
NGLs	17,321			9,241			8,080		87	%
Oil	2,952			(39)			2,991		(7,669)	%
Net gain (loss) on derivative settlements	$	83,506		$	7,422		$	76,084	1,025	%

Per Boe metrics
Realised price (including impact of derivatives settled in cash)	$	14.69		$	16.84		$	(2.15)	(13)	%
Other revenue	0.81			1.03			(0.22)		(21)	%
Base lease operating expense	2.50			3.78			(1.28)		(34)	%
Gathering and compression, owned	1.41			1.50			(0.09)		(6)	%
Adjusted G&A¹	1.34			1.35			(0.01)		(1)	%
Production taxes	0.45			0.53			(0.08)		(15)	%
Gathering and transportation, third party	1.35			1.13			0.22		19	%
Operating margin	$	8.45		$	9.58		$	(1.13)	(12)	%
% Operating margin	54.5		%	53.6		%

Production, Revenue and Hedging

Total revenue (unhedged) in 1H20 of $184.9 million decreased 22.1% from $237.5 million reported for 1H19. This decline is primarily due to a 39.5% decrease in the average realised sales price. This was offset in part by 26.4% higher production. We ended 1H20 with net sales of approximately 17,317 MBoe versus prior year sales of approximately 13,701 MBoe. The increase in production was driven by the full integration of the previously acquired HG Energy and EdgeMarc assets in 2019 and the Carbon and EQT assets in May 2020. Average realised sales prices dropped as a result of decreases in commodity prices. The average Henry Hub quoted price for 1H20 was $1.83 per MMBtu versus $2.89 per MMBtu for 1H19. The average Mont Belvieu quoted price for 1H20 was $18.65 per barrel versus $27.58 per barrel for 1H19. The average WTI quoted price for 1H20 was $37.01 per barrel versus $57.33 per barrel in 1H19.

Refer to Note 3 in the Notes to the Group Interim Financial Information for additional information regarding our acquisitions.

Commodity Revenue (Unhedged)

The following table is intended to reconcile the change in commodity revenue (excluding the impact of hedges settled in cash) for 1H20 by reflecting the effect of changes in volume and in the underlying prices (in thousands):

	Natural gas		NGLs		Oil		Total
Commodity revenue for the six months ended 30 June 2019	$	194,810	$	18,439	$	10,048	$	223,297
Volume increase (decrease)	55,453		1,966		53		57,472
Price increase (decrease)	(93,363)		(13,376)		(3,198)		(109,937)
Net increase (decrease)	(37,910)		(11,410)		(3,145)		(52,465)
Commodity revenue for the six months ended 30 June 2020	$	156,900	$	7,029	$	6,903	$	170,832

To manage our cash flows in a volatile commodity price environment, we utilise hedges. See the tables below for our hedging impact on revenue and average realised prices (in thousands, except per unit data):

	Six Months Ended 30 June 2020
	Natural gas				NGLs				Oil				Total Commodity
	Revenue		Realised $		Revenue		Realised $		Revenue		Realised $		Revenue		Realised $
Excluding hedge impact	$	156,900	$	1.67	$	7,029	$	4.84	$	6,903	$	36.33	$	170,832	$	9.86
Hedge impact	63,233		0.67		17,321		11.92		2,952		15.54		$	83,506	4.82
Including hedge impact¹	$	220,133	$	2.34	$	24,350	$	16.76	$	9,855	$	51.87	$	254,338	$	14.69

	Six Months Ended 30 June 2019
	Natural gas				NGLs				Oil				Total Commodity
	Revenue		Realised $		Revenue		Realised $		Revenue		Realised $		Revenue		Realised $
Excluding hedge impact	$	194,810	$	2.66	$	18,439	$	14.04	$	10,048	$	53.16	$	223,297	$	16.30
Hedge impact	(1,780)		(0.02)		9,241		7.04		(39)		(0.21)		$	7,422	0.54
Including hedge impact¹	$	193,030	$	2.64	$	27,680	$	21.08	$	10,009	$	52.96	$	230,719	$	16.84

Refer to Note 16 in the Notes to the Group Interim Financial Information for additional information regarding our hedging portfolio.

Expenses

(In thousands, except per unit data)	Six Months Ended
			Per				Per		Total Change				Per Boe Change
	30 June 2020		Boe		30 June 2019		Boe		$		%		$		%
Base lease operating expense ^(a)	$	43,368	$	2.50	$	51,777	$	3.78	$	(8,409)	(16)	%	$	(1.28)	(34)	%
Production taxes ^(b)	7,748		0.45		7,277		0.53		471		6	%	(0.08)		(15)	%
Gathering and compression ^(c)	24,380		1.41		20,552		1.50		3,828		19	%	(0.09)		(6)	%
Gathering and transportation ^(d)	23,455		1.35		15,523		1.13		7,932		51	%	0.22		19	%
Total operating expense	$	98,951	$	5.71	$	95,129	$	6.94	$	3,822	4	%	$	(1.23)	(18)	%
Adjusted G&A¹ ^(e)	23,129		1.34		18,470		1.35		4,659		25	%	(0.01)		(1)	%
Non-recurring and/or non-cash G&A ^(f)	11,567		0.67		3,212		0.23		8,355		260	%	0.44		191	%
Total operating and G&A expense	$	133,647	$	7.72	$	116,811	$	8.53	$	16,836	14	%	$	(0.81)	(9)	%
Depreciation and depletion	55,837		3.22		45,342		3.31		10,495		23	%	(0.09)		(3)	%
Total expenses	$	189,484	$	10.94	$	162,153	$	11.84	$	27,331	17	%	$	(0.90)	(8)	%

Base lease operating expense is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.
Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, natural gas liquids 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 oil and gas properties and midstream assets.
Gathering and compression expenses are daily costs incurred to operate our owned midstream assets inclusive of employee and benefit expenses.
Gathering and transportation expenses are daily costs incurred to gather, process and transport the Group's natural gas, natural gas liquids and oil.
Adjusted general and administrative expense ("Adjusted G&A")¹ includes payroll and benefits for our corporate staff, costs of maintaining 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.
Non-recurring and/or non-cash general and administrative expense ("Non-recurring and/or non-cash G&A") includes costs related to acquisitions, our uplist to the main market of the LSE, non-cash equity compensation and one-time projects.

As a result of our significant, value-focused growth, per unit expenses decreased 8%, or $0.90 per Boe as a result of the following:

Lower per Boe base lease operating expenses, which declined 34%, or $1.28 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 15%, or 0.08 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 gathering, processing and compression expenses, which declined 6%, or 0.09 per Boe, primarily due to economies of scale whereby fixed operating costs for our owned midstream assets were spread across a larger base of producing assets.

Partially offsetting these per Boe declines were increases due to:

Higher per Boe gathering and transportation due to third-party transportation expense related to the HG Energy and EdgeMarc assets acquired in April 2019 and September 2019, respectively;
Higher Adjusted G&A¹ as a result of investments made in staff and systems to support our growth; and
Higher non-recurring and/or non-cash G&A due to costs associated with the uplist to the main market of the LSE, expenses related to the Carbon and EQT acquisitions, and expenses for a one-time hedge portfolio restructuring.

Refer to Note 3 in the Notes to the Group Interim Financial Information for additional information regarding our acquisitions.

Derivative Financial Instruments

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

(In thousands)	Six Months Ended
	30 June 2020		30 June 2019		$ Change		% Change
Net gain (loss) on derivative settlements ^(a)	$	83,506	$	7,422	$	76,084	1025	%
Gain on foreign currency hedge	-		4,120		(4,120)		(100)	%
Total gain (loss) on settled derivative instruments	$	83,506	$	11,542	$	71,964	623	%
Gain (loss) on fair value adjustments of unsettled financial instruments ^(b)	(109,680)		21,252		(130,932)		(616)	%
Total gain (loss) on derivative financial instruments	$	(26,174)	$	32,794	$	(58,968)	(180)	%

Represents the cash settlement of hedges that settled during the period.
Represents the change in fair value of financial instruments net of removing the carrying value of hedges that settled during the period.

Total loss on derivative financial instruments of $26.2 million in 1H20 decreased $59.0 million compared to a gain of $32.8 million in 1H19, primarily due to a loss of $109.7 million on fair value adjustments of unsettled financial instruments in 1H20, a decrease of $130.9 million, as compared to a gain of $21.3 million in 1H19. Offsetting the loss was a gain of $83.5 million attributable to derivative instruments settled in cash in 1H20, an increase of $72.0 million over 1H19.

Refer to Note 16 in the Notes to the Group Interim Financial Information for additional information regarding our derivative financial instruments.

Finance Costs

(In thousands)	Six Months Ended
	30 June 2020		30 June 2019		$ Change		% Change
Interest expense, net of capitalised and income amounts	$	17,476	$	15,676	$	1,800	11	%
Amortisation of deferred finance cost	3,515		1,930		1,585		82	%
Other	421		2		419		20,950	%
Total finance costs	$	21,412	$	17,608	$	3,804	22	%

Interest expense on borrowings of $17.5 million in 2020 increased $1.8 million compared to $15.7 million in 2019, primarily due to the increase in borrowings used to fund our previously mentioned acquisitions. As of 30 June 2020 and 2019, total borrowings were $771.1 million and $625.2 million, respectively. The weighted average interest rate on borrowings was 4.6% for 1H20 as compared to 5.2% for 1H19.

Refer to Notes 3 and 14 in the Notes to the Group Interim Financial Information for additional information regarding our acquisitions and borrowings, respectively.

Taxation

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

	Six Months Ended
	30 June 2020			30 June 2019			$ Change		% Change
Income (loss) before taxation	$	(59,227)		$	84,047		$	(143,274)	(170)	%
Income tax benefit (expense)	77,712			(21,881)			99,593		(455)	%
Effective tax rate	131.2		%	26.0		%			105	%

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

	Six Months Ended
	30 June 2020		30 June 2019
Expected tax at statutory US federal income tax rate	21.0	%	21.0	%
State income taxes, net of federal tax benefit	3.8	%	5.0	%
Federal credits	108.5	%	(4.5)	%
Other, net	(2.1)	%	4.5	%
Effective tax rate	131.2	%	26.0	%

We reported a tax benefit of $77.7 million for 1H20, an increase of $99.6 million, compared to expense of $21.9 million for 1H19. The resulting effective tax rates for 1H20 and 1H19 were 131.2% and 26.0%, respectively. The effective tax rate is primarily impacted by recognition of the federal well tax credit available to qualified producers in 2020 due to the low commodity pricing environment.

Refer to Note 7 in the Notes to the Group Interim Financial Information for additional information regarding Taxation.

EPS and Adjusted EBITDA¹

We reported a loss before taxation of $59.2 million in 1H20 compared to income of $84.0 million in 1H19, a decrease of 170%, and reported statutory income for 1H20 per diluted ordinary share of $0.03 compared to income of $0.10 per diluted ordinary share in 1H19. However, when adjusted for certain non-recurring and/or non-cash items and similar items, we reported Adjusted EBITDA¹ (hedged) per diluted ordinary share of $0.22, consistent with the prior year's $0.22. Our Adjusted EBITDA¹ (hedged) for 1H20 was $146.3 million, a 11% increase from $131.3 million in 1H19.

Refer to Notes 8 and 6 in the Notes to the Group Interim Financial Information for additional information regarding our EPS and Adjusted EBITDA¹, respectively.

Liquidity and Capital Resources

Our principal sources of liquidity have historically been cash generated from operating activities and, to the extent necessary, commitments available under our credit facility. We monitor our working capital to ensure that the levels remain adequate to operate the business. In addition to working capital management, we have a disciplined approach to allocating capital resources by focusing on flexible assets, capital modification and re-use, when and where appropriate, and managing our fixed costs, all of which support overall cash flow generation in our business operations.

(In thousands)	Six Months Ended
	30 June 2020		30 June 2019		$ Change		% Change
Net cash provided by operating activities	$	123,359	$	130,541	$	(7,182)	(6)	%
Net cash used in investing activities	(231,396)		(407,193)		175,797		(43)	%
Net cash provided by financing activities	113,091		275,280		(162,189)		(59)	%
Net change in cash and cash equivalents	$	5,054	$	(1,372)	$	6,426	(468)	%

Net Cash Provided by Operating Activities

Net cash generated by operating activities decreased by $7.2 million, or 6%, to $123.4 million in 1H20 from $130.5 million in 1H19. The change in operating activities was predominantly attributable to the following:

A decrease in revenue, offset by an increase in settlements of hedges;
An increase in certain operating expenses related to acquired properties;
An increase in Adjusted G&A¹ as a result of investments made in staff and systems to support our growth;
An increase in non-recurring and/or non-cash G&A due to costs associated with the uplist to the main market of the LSE, expenses related to the Carbon and EQT acquisitions, and hedge portfolio restructuring costs; and
A change related to the timing of working capital payments and receipts.

Production, realised prices, operating expenses, and general and administrative expenses are discussed above in the Financial Review. Refer to Notes 3 and 16 in the Notes to the Group Interim Financial Information for additional information regarding our acquisitions and derivatives, respectively.

Net Cash Used in Investing Activities

Net cash used in investing activities decreased by $175.8 million, or 43%, to $231.4 million in 1H20 from $407.2 million in 1H19. The change in net cash used in investing activities was primarily attributable to the following:

For 1H20, we paid purchase consideration of approximately $103.6 million and $119.4 million for the Carbon and EQT acquisitions, respectively. For 1H19, we paid a purchase consideration of $384.0 million for the HG Energy acquisition.

Refer to Note 3 in the Notes to the Group Interim Financial Information for additional information regarding our acquisitions.

Net Cash Provided by Financing Activities

Net cash provided by financing activities decreased by $162.2 million, or 59%, to $113.1 million in 1H20 from $275.3 million in 1H19. The change in net cash provided by financing activities was primarily attributable to the following:

During 1H20 our Credit Facility activity resulted in net repayments of $225.4 million versus net proceeds of $119.9 million in 1H19;
Proceeds from borrowings, net of repayments, on our new debt facilities was $344.2 million, an increase of $336.9 million as compared to 1H19;
A decrease of $140.3 million in proceeds from an equity issuance in 1H20 that raised $81.6 million as compared to $221.9 million raised 1H19.
An increase of $10.9 million in dividends paid in 1H20 as compared to 1H19; and
A decrease of $3.5 million in repurchases of shares in 1H20 as compared to 1H19.

Refer to Notes 9, 12 and 14 in the Notes to the Group Interim Financial Information for additional information regarding our dividends, share capital and borrowings, respectively.

Principal Risks and Uncertainties

The directors have reconsidered the principal risks and uncertainties we face, particularly in relation to COVID-19. The directors consider that the principal risks and uncertainties published in the Annual Report for the year ended 31 December 2019 remain appropriate. The risks and associated risk management processes, including financial risks, can be found in our 2019 Annual Report, which is available in the Investor Resources section of our website at www.dgoc.com.

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

Managing growth;
Commodity price volatility;
Market risk;
Liquidity risk; and
Environmental and regulatory risk.

COVID-19

The COVID-19 pandemic has brought considerable change to the risk landscape in the first half of the year, increasing the impact of many of our principal risks and creating uncertainty in how the future risk landscape will unfold. We have reassessed all of our principal risks and, where necessary, we have implemented further mitigation activities. COVID-19 has severely impacted our industry particularly when considered in connection with the decline in oil, gas, and NGLs prices in 2020. However despite this negative trend in the industry, COVID-19 has resulted in limited direct disruption to our ability to operate, and our unique business model has allowed us to continue to grow and deliver shareholder returns.

COVID-19 also has the potential to be a health and safety risk to our employees. To help safeguard our employees, we responded proactively by issuing personal protective equipment ("PPE") guidance, establishing social distancing policies and supporting remote working environments where possible. We have also closely monitored guidance issued by state and local governments as well as the Center for Disease Control and Occupational Health and Safety Administration to ensure we are compliant with all regulatory authorities. Our business model also naturally lends itself to a socially distant operating environment provided our employees are most commonly working in small teams in remote areas when servicing wells. We will continue to monitor the changing risk landscape and respond proactively to ensure the health and safety of our employees.

Going Concern

As described in Note 2 in the Notes to the Group Interim Financial Information, the directors have formed a judgement, at the time of approving the Group Interim Financial Information, that there is a reasonable expectation that we are sufficiently well funded to be able to operate as a going concern for at least the next twelve months from the date of approval of the Group Interim Financial Information. In making this judgement, they have considered the impacts of current and severe but plausible consequences arising from COVID-19 to our activities. For this reason, the directors continue to adopt the going concern basis in preparing the Group Interim Financial Information.

Responsibility Statement

We confirm to the best of our knowledge that:

The Group Interim Financial Information has been prepared in accordance with IAS 34 "Interim Financial Reporting";
The interim Strategic Review includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and
The interim Strategic Review includes a fair review of the information required by DTR 4.2.8R (disclosure of related party transactions and changes therein).

Conclusion

We have enjoyed an eventful and successful 2020 so far, and look forward to continued progress as we focus our attention towards the second half of 2020. I would like to thank the growing Diversified family for its commitment to safe and efficient operations, the Board for its diligent oversight and guidance, and our shareholders and stakeholders who entrust to us the capital to fuel our growth. I look forward to reporting back to you with our full-year results.

David Johnson

Chairman

DIVERSIFIED GAS & OIL PLC

Alternative Performance Measures

(Amounts in thousands, except per share data)

Alternative Performance Measures

This interim report refers to Alternative Performance Measures ("APMs") such as "Adjusted EBITDA," "Cash Margin," "Free Cash Flow," "Net Debt," and "Total Revenue (Hedged)." See definitions and reconciliations below. These measures are provided in addition to, and not as an alternative for, the information contained in the Group's financial statements prepared in accordance with IFRS including the Notes thereto, and should be read in conjunction with the Group's annual reports and related presentations.

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

Adjusted EBITDA

As used herein, Adjusted EBITDA represents earnings before interest, taxes, depletion, depreciation and amortisation and 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 the Group's hedge portfolio, non-cash equity compensation charges and items of a similar nature.

Adjusted EBITDA should not be considered in isolation or as a substitute for operating income or loss, net income or loss, or cash flows provided by operating, investing and financing activities. However, Management believes it is useful to an investor in evaluating the Group's financial performance because this measure (1) is widely used by investors in the oil and natural gas industry as an indicator of underlying business performance; (2) helps investors to more meaningfully evaluate and compare the results of the Group'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 the Group's Credit Facility financial covenants; and (4) is used by our Directors as a performance measure in determining executive compensation.

	1H20		1H19		2H19
Operating profit (loss)	$	(30,780)	$	107,763	$	72,744
Depreciation and depletion	55,837		45,342		52,797
Gain on bargain purchase	-		-		(1,540)
(Gain) loss on oil and gas programme and equipment	-		336		-
(Gain) loss on fair value adjustments of unsettled financial instruments	109,680		(21,252)		982
Non-recurring costs	10,061		2,804		14,678
Non-cash equity compensation	1,506		408		2,657
Gain on foreign currency hedge	-		(4,120)		3
Total adjustments	$	177,084	$	23,518	$	69,241
Adjusted EBITDA (hedged)	$	146,304	$	131,281	$	141,985
Less: Cash portion of settled hedges	83,506		11,542		42,042
Adjusted EBITDA (unhedged)	$	62,798	$	119,739	$	99,943

Adjusted Total Revenue

As used herein, Adjusted Total Revenue includes the impact of derivatives settled in cash. Management believes that Adjusted Total Revenue is a useful measure because it enables investors to discern the Group's realised revenue after adjusting for the settlement of derivative contracts.

Adjusted EBITDA Cash Margin	As used herein, Adjusted EBITDA Cash Margin is measured as Adjusted EBITDA as a percentage of total revenue (including natural gas, natural liquids and crude oil commodity revenue, midstream revenue and other revenue) plus settled net hedging gains (losses) as applicable. Management believes that Adjusted EBITDA Cash Margin is a useful measure of the Group's profitability and efficiency as well as its earnings quality.
		1H20			1H19			2H19
Total revenue (unhedged)		$	184,878		$	237,458		$	224,798
Hedge impact		83,506			7,422			42,045
Adjusted Total Revenue		$	268,384		$	244,880		$	266,843

Adjusted EBITDA (hedged)		$	146,304		$	131,281		$	141,985

Cash Margin		55		%	54		%	53		%

Free Cash Flow and
Free Cash Flow Yield

As used herein, Free Cash Flow represents Adjusted EBITDA less recurring capital expenditures, asset retirement costs and cash interest expense. Management believes that Free Cash Flow is a useful indicator of the Group'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 the Group's total market capitalisation. Management believes that, like Free Cash Flow, Free Cash Flow Yield is an indicator of financial stability and reflects the Group's operating strength relative to its size as measured by market capitalisation.

	1H20			1H19			2H19
Adjusted EBITDA (hedged)	$	146,304		$	131,281		$	141,985
LESS: Recurring capital expenditures	(8,208)			(8,775)			(8,480)
LESS: Plugging and abandonment costs	(1,201)			(1,237)			(1,304)
LESS: Cash interest expense	(17,693)			(15,683)			(16,979)
Free Cash Flow	$	119,202		$	105,586		$	115,222

Annualised Free Cash Flow	$	238,404		$	211,172		$	230,444
Average share price	$	1.13		$	1.35		$	1.35
Weighted average ordinary shares outstanding - diluted	667,293			604,996			644,782
Free Cash Flow Yield	32		%	26		%	26		%

Net Debt and Net Debt-to-Adjusted EBITDA

As used herein, Net Debt represents total debt as recognised on the balance sheet less unrestricted cash and cash equivalents. Total debt includes the Group's current portion of debt, credit facility borrowings and term loan borrowings. Net Debt is a useful indicator of the Group's leverage and capital structure.

As used herein, Net Debt-to-Adjusted EBITDA is measured as Net Debt divided by Adjusted EBITDA. Management believes that this metric is a key measure of the Group's financial liquidity and flexibility and is used in the calculation of a key metric in one of the Group's Credit Facility financial covenants.

	1H20
Cash	$	6,715
Restricted cash	16,865
Credit Facility	(211,300)
ABS I Note	(193,353)
ABS II Note	(200,000)
Bluegrass Note	(160,000)
Leases	(8,966)
Other	(6,398)
Net Debt	$	(756,437)

Adjusted EBITDA (hedged)	$	146,304
TTM Adjusted EBITDA (hedged) ^(a)	$	345,231

TTM Net Debt-to-Adjusted EBITDA (hedged)	2.19x

TTM Adjusted EBIDTA (hedged) was calculated by adding the Adjusted EBITDA (hedged) amounts for 1H20 and 2H19, then adjusting EQT and Carbon Adjusted EBITDA (Hedged) amounts to pro forma their results for a twelve month period.

Adjusted G&A

As used herein, Adjusted G&A represents total administrative expenses excluding non-recurring and/or non-cash acquisition and integration costs. Management uses 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.

	1H20		1H19		2H19
Total general and administration expense	$	34,696	$	21,682	$	34,937
LESS: Non-recurring and/or non-cash G&A ^(a)	(11,567)		(3,212)		(17,334)
Adjusted G&A ^(b)	$	23,129	$	18,470	$	17,603

Non-recurring and/or non-cash G&A includes costs related to acquisitions, the Group's uplist to the main market, and one-time projects.
Adjusted G&A includes payroll and benefits for our corporate staff, costs of maintaining 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.

Independent review report to Diversified Gas & Oil PLC

Report on the interim financial information

Our conclusion

We have reviewed Diversified Gas & Oil PLC's interim financial information (the "interim financial statements") in the Interim Report 2020 of Diversified Gas & Oil PLC for the 6 month period ended 30 June 2020. Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with International Accounting Standard 34, ‘Interim Financial Reporting', as adopted by the European Union and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

What we have reviewed

The interim financial statements comprise:

the Consolidated Statements of Financial Position as at 30 June 2020;
the Consolidated Statements of Comprehensive Income for the period then ended;
the Consolidated Statements of Cash Flows for the period then ended;
the Consolidated Statements of Changes in Equity for the period then ended; and
the explanatory notes to the interim financial statements.

The interim financial statements included in the Interim Report 2020 have been prepared in accordance with International Accounting Standard 34, ‘Interim Financial Reporting', as adopted by the European Union and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

As disclosed in note 2 to the interim financial statements, the financial reporting framework that has been applied in the preparation of the full annual financial statements of the Group is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the directors

The Interim Report 2020, including the interim financial statements, is the responsibility of, and has been approved by, the Directors. The Directors are responsible for preparing the Interim Report 2020 in accordance with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

Our responsibility is to express a conclusion on the interim financial statements in the Interim Report 2020 based on our review. This Report, including the conclusion, has been prepared for and only for the Company for the purpose of complying with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

What a review of interim financial statements involves

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

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

We have read the other information contained in the Interim Report 2020 and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants

London

10 August 2020

DIVERSIFIED GAS & OIL PLC

Consolidated Statements of Comprehensive Income

(Amounts in thousands, except per-share amounts)

		Unaudited				Audited
		Six Months Ended				Year Ended
	Note	30 June 2020		30 June 2019		31 December 2019
Revenue	4	$	184,878	$	237,458	$	462,256
Operating expense	5	(98,951)		(95,129)		(202,385)
Depreciation and depletion	5,10	(55,837)		(45,342)		(98,139)
Gross profit		$	30,090	$	96,987	$	161,732
General and administrative expenses	5	(34,696)		(21,682)		(56,619)
Gain (loss) on oil and gas programme and equipment		-		(336)		-
Gain (loss) on derivative financial instruments	16	(26,174)		32,794		73,854
Gain on bargain purchase		-		-		1,540
Operating profit (loss)		$	(30,780)	$	107,763	$	180,507
Finance costs		(21,412)		(17,608)		(36,667)
Accretion of asset retirement obligation	13	(7,395)		(6,108)		(12,349)
Other income (expense)		360		-		-
Income (loss) before taxation		$	(59,227)	$	84,047	$	131,491
Income tax benefit (expense)		77,712		(21,881)		(32,091)
Income (loss) available to ordinary shareholders after taxation		$	18,485	$	62,166	$	99,400
Other comprehensive income (loss)		(28)		-		-
Total comprehensive income (loss) for the year		$	18,457	$	62,166	$	99,400

Earnings per ordinary share- basic and diluted	8	$	0.03	$	0.10	$	0.15

Weighted average ordinary shares outstanding - basic	8	662,804		603,807		641,666
Weighted average ordinary shares outstanding - diluted	8	667,293		604,996		644,782

The notes are an integral part of these consolidated interim financial statements.

DIVERSIFIED GAS & OIL PLC

Consolidated Statements of Financial Position

(Amounts in thousands)

		Unaudited		Audited
	Note	30 June 2020		31 December 2019
ASSETS
Non-current assets:
Oil and gas properties, net	10	$	1,679,150	$	1,490,905
Intangible assets		13,163		15,980
Property and equipment, net	11	360,026		325,866
Restricted cash		15,657		6,505
Derivative financial instruments	16	2,155		3,803
Other non-current assets	15	5,550		2,521
Total non-current assets		$	2,075,701	$	1,845,580
Current assets:
Trade receivables		69,642		73,924
Derivative financial instruments	16	65,529		73,705
Other current assets	15	10,204		9,863
Cash and cash equivalents		6,715		1,661
Restricted cash		1,208		1,207
Total current assets		$	153,298	$	160,360
Total assets		$	2,228,999	$	2,005,940
EQUITY AND LIABILITIES
Shareholders' equity:
Share capital	12	9,516		8,800
Share premium	12	841,347		760,543
Merger reserve		(478)		(478)
Capital redemption reserve		592		518
Share based payment reserve		5,413		3,907
Retained earnings		120,422		164,845
Total equity		$	976,812	$	938,135
Non-current liabilities:
Asset retirement obligations	13	230,613		196,871
Leases		6,664		1,015
Borrowings	14	681,053		598,778
Deferred tax liability		41,372		124,112
Derivative financial instruments	16	104,103		15,706
Other non-current liabilities	15	12,044		4,468
Total non-current liabilities		$	1,075,849	$	940,950
Current liabilities:
Trade and other payables		13,201		17,052
Borrowings	14	58,245		23,723
Leases		2,302		798
Derivative financial instruments	16	3,997		-
Other current liabilities	15	98,593		85,282
Total current liabilities		$	176,338	$	126,855
Total liabilities		$	1,252,187	$	1,067,805
Total equity and liabilities		$	2,228,999	$	2,005,940

The notes are an integral part of these consolidated interim financial statements.

DIVERSIFIED GAS & OIL PLC

Consolidated Statements of Changes in Equity

(Amounts in thousands)

	Note	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings		Total Equity
Balance at 1 January 2020		$	8,800	$	760,543	$	(478)	$	518	$	3,907	$	164,845	$	938,135
Income after taxation		-		-		-		-		-		18,485		18,485
Other comprehensive income (loss)		-		-		-		-		-		(28)		(28)
Total comprehensive income (loss)		$	-	$	-	$	-	$	-	$	-	$	18,457	$	18,457
Issuance of share capital	12	790		80,804		-		-		-		-		81,594
Equity compensation		-		-		-		-		1,506		-		1,506
Repurchase of shares	12	(74)		-		-		74		-		(15,634)		(15,634)
Dividends	9	-		-		-		-		-		(47,246)		(47,246)
Transactions with shareholders		$	716	$	80,804	$	-	$	74	$	1,506	$	(62,880)	$	20,220
Balance at 30 June 2020		$	9,516	$	841,347	$	(478)	$	592	$	5,413	$	120,422	$	976,812

	Note	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings		Total Equity
Balance at 1 January 2019		$	7,346	$	540,655	$	(478)	$	-	$	842	$	200,498	$	748,863
Income after taxation		-		-		-		-		-		62,166		62,166
Other comprehensive income (loss)		-		-		-		-		-		-		-
Total comprehensive income (loss)		$	-	$	-	$	-	$	-	$	-	$	62,166	$	62,166
Issuance of share capital	12	1,972		219,888		-		-		-		-		221,860
Equity compensation		-		-		-		-		408		-		408
Repurchase of shares	12	-		-		-		-		-		(19,181)		(19,181)
Dividends	9	-		-		-		-		-		(36,358)		(36,358)
Transactions with shareholders		$	1,972	$	219,888	$	-	$	-	$	408	$	(55,539)	$	166,729
Balance at 30 June 2019		$	9,318	$	760,543	$	(478)	$	-	$	1,250	$	207,125	$	977,758

	Note	Share Capital		Share Premium		Merger Reserve		Capital Redemption Reserve		Share-Based Payment Reserve		Retained Earnings		Total Equity
Balance at 1 January 2019		$	7,346	$	540,655	$	(478)	$	-	$	842	$	200,498	$	748,863
Income after taxation		-		-		-		-		-		99,400		99,400
Other comprehensive income (loss)		-		-		-		-		-		-		-
Total comprehensive income (loss)		$	-	$	-	$	-	$	-	$	-	$	99,400	$	99,400
Issuance of share capital	12	1,972		219,888		-		-		-		-		221,860
Equity compensation		-		-		-		-		3,065		-		3,065
Repurchase of shares	12	(518)		-		-		518		-		(52,902)		(52,902)
Dividends	9	-		-		-		-		-		(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

The notes are an integral part of these consolidated interim financial statements.

DIVERSIFIED GAS & OIL PLC

Consolidated Statements of Cash Flows

(Amounts in thousands)

		Unaudited				Audited
		Six Months Ended				Year Ended
	Note	30 June 2020		30 June 2019		31 December 2019
Cash flows from operating activities:
Income after taxation		$	18,485	$	62,166	$	99,400
Cash flows from operations reconciliation:
Depreciation and depletion		55,837		45,342		98,139
Accretion of asset retirement obligation	13	7,395		6,108		12,349
Income tax (benefit) expense		(77,712)		21,881		32,091
(Gain) loss on fair value adjustments of unsettled financial instruments	16	109,680		(21,252)		(20,270)
Asset retirement (plugging)		(1,201)		(1,237)		(2,541)
Gain on oil and gas programme and equipment		377		-		-
Gain on bargain purchase	3	-		-		(1,540)
Finance costs	14	21,412		17,608		36,667
Non-cash equity compensation	12	1,506		408		3,065
Working capital adjustments:
Change in trade receivables		6,280		3,384		4,528
Change in other current assets		(1,253)		2,138		2,606
Change in other assets		(6,706)		220		409
Change in trade and other payables		(3,897)		(1,849)		7,669
Change in other current and non-current liabilities		(6,844)		(4,376)		6,584
Net cash provided by operating activities		$	123,359	$	130,541	$	279,156
Cash flows from investing activities:
Business Acquisitions	3	$	(98,121)	$	(388,064)	$	(439,272)
Acquisition of Assets	3	(112,347)		-		-
Expenditures on oil and gas properties and equipment		(11,775)		(19,178)		(32,313)
(Increase) decrease in restricted cash		(9,153)		49		(5,302)
Proceeds on disposals of oil and gas properties and equipment		-		-		10,000
Net cash used in investing activities		$	(231,396)	$	(407,193)	$	(466,887)
Cash flows from financing activities:
Repayment of borrowings	14	$	(456,502)	$	(189,993)	$	(618,010)
Proceeds from borrowings	14	575,350		317,267		765,236
Financing expense		(17,683)		(16,024)		(32,715)
Cost incurred to secure financing		(5,780)		(1,581)		(11,574)
Proceeds from equity issuance, net		81,594		221,860		221,860
Principal element of lease payments		(1,008)		(710)		(1,724)
Dividends to shareholders	9	(47,246)		(36,358)		(82,151)
Repurchase of shares		(15,634)		(19,181)		(52,902)
Net cash provided by financing activities		$	113,091	$	275,280	$	188,020
Net change in cash and cash equivalents		5,054		(1,372)		289
Cash and cash equivalents, beginning of period		1,661		1,372		1,372
Cash and cash equivalents, end of period		$	6,715	$	-	$	1,661

The notes are an integral part of these consolidated interim financial statements.

DIVERSIFIED GAS & OIL PLC

Notes to the Group Interim Financial Information

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

Index to the Notes to the Group Interim Financial Information

Footnote	Page	Footnote	Page
Note 1 - General Information	26	Note 11 - Property and Equipment	35
Note 2 - Accounting Policies	26	Note 12 - Share Capital	35
Note 3 - Acquisitions	29	Note 13 - Asset Retirement Obligation	36
Note 4 - Revenue	30	Note 14 - Borrowings	37
Note 5 - Expenses by Nature	31	Note 15 - Other Assets and Liabilities	38
Note 6 - Adjusted EBITDA	32	Note 16 - Derivatives	40
Note 7 - Taxation	33	Note 17 - Fair Value and Financial Instruments	43
Note 8 - Earnings Per Ordinary Share	33	Note 18 - Contingencies and Provisions	45
Note 9 - Dividends	34	Note 19 - Related Party Transactions	45
Note 10 - Oil and Gas Properties	34	Note 20 - Subsequent Events	45

Note 1 - General Information

Diversified Gas & Oil PLC 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 lives and slow decline profiles. The Group's assets are exclusively located within the Appalachian Basin of the United States. The Group is headquartered in Birmingham, Alabama, USA with field offices located in the states of Pennsylvania, Ohio, West Virginia, Kentucky, Virginia and Tennessee.

The Group was incorporated on 31 July 2014 in England and Wales as a private limited company under company number 09156132. The Group‘s registered office is located at 27/28 Eastcastle Street, London W1W 8DH, United Kingdom.

In February 2017, the Group's ordinary shares were admitted to trading on AIM under the ticker "DGOC." In May 2020, the Group's ordinary shares were admitted to trading on the LSE's main market for listed securities. The ordinary shares trading on AIM were cancelled concurrent to their admittance on the LSE.

Note 2 - Accounting Policies

Basis of Preparation and Measurement

The Group's interim consolidated financial statements (the "Group Interim Financial Information") are unaudited and do not represent statutory accounts within the meaning of section 434 of the Companies Act 2006. The financial information for the year ended 31 December 2019 is based on the statutory accounts for the year ended 31 December 2019. Those accounts, upon which the auditors issued an unqualified opinion, have been delivered to the Registrar of Companies and did not contain statements under section 498(2) or (3) of the Companies Act.

The Group Interim Financial Information has been prepared on the basis of the accounting policies set out in the Group's 2019 statutory accounts in accordance with IAS 34 "Interim Financial Reporting". The Group Interim Financial Information does not include all of the information required for a full annual financial report and should be read in conjunction with the Group's financial statements for the year ended 31 December 2019, which were prepared in accordance with IFRS as adopted by the European Union.

Unless otherwise stated, the Group Interim 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 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 balance sheet date. Diversified Gas & Oil PLC has a different functional currency and its results and financial position are translated into the presentation currency as follows:

Assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet;
Income and expenses for each 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 Statements of Comprehensive Income.

The Group Interim Financial Information has been prepared on the going concern basis, under the historical cost convention, as modified by financial assets and financial liabilities (including derivative instruments) at fair value through profit or loss.

Going concern

The Group Interim 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 COVID-19. The Financial overview section of this Interim Report includes a summary of the Group's financial position, cash flows, liquidity position and borrowing facilities.

The Directors closely monitor and carefully manage the Group's liquidity risk. 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 the Group's producing assets. The Group's cash flow projections have been updated in light of COVID-19. There remains significant uncertainty over the impact of COVID-19, however to date, the Group's day-to-day operations continue without being materially affected. This is evident through the Group's sustained growth during the pandemic. To consider potential negative impacts of COVID-19 such as price volatility or other operational issues, the Directors have prepared a downside sensitivity scenario for each of the years ending 31 December 2020 and 31 December 2021. The severe but plausible downside sensitivity scenario includes, but is not limited to, the following assumptions:

A 10% reduction to prices and a 10% increase to the price differential;
Reducing production by approximately 10%; and
Increasing operating and midstream expenses by approximately 2%.

Consistent with the Group's base operations the modeled scenario includes the financial impact of the Group's current hedging contracts in place, being approximately 81% of total production volumes hedged for the year ending 31 December 2020 and 73% for the year ending 31 December 2021. The scenario also includes the scheduled principal and interest payments on the Group's current debt arrangements.

Under this downside sensitivity scenario, 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 June 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 totaled $213,700 as of 30 June 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 scenario, 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 recent months since the outbreak occurred, a decline in production volume and pricing well in excess of that experienced in any month in the first six months of 2020, 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.

When evaluating the modeled scenario, the Directors also considered the risk of a temporary shutdown resulting from the COVID-19 pandemic. 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 United States.

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 Interim Financial Information.

Prior period reclassifications

The Group has reclassified certain amounts relating to its prior year results to conform to its current period presentation. These changes in classification do not affect total comprehensive income previously reported in the Consolidated Statements of Comprehensive Income. During the year ended 31 December 2019, the Group reclassified $15,980 related to its ERP software from property and equipment to intangible fixed assets.

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 Interim Financial Information for the six month period ended 30 June 2020 reflects the following corporate structure of the Group:

The Group, and its 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
  - 64 DrillCo Partnerships
- Diversified Midstream LLC
  - Cranberry Pipeline Corporation
  - Coalfield Pipeline Company
- Diversified Energy Marketing LLC
- DGOC Holdings LLC
  - DGOC Holdings Sub III LLC

Segmental Reporting

The Group complies with IFRS 8 "Operating Segments", to determine its operating segments and has identified one reportable segment that produces natural gas 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.

Significant Accounting Policies

The preparation of the Group Interim Financial Information in compliance with IFRS requires management to make estimates and exercise judgment in applying the Group's accounting policies. In preparing the Group Interim Financial Information, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the Group Financial Information for the year ended 31 December 2019 with the addition of a significant judgement made with respect to the adopted amendments of IFRS 3.

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 acquisitions of a business 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 conclusions reached with respect to this judgement is included in Note 3.

Note 3 - 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.

2020 Acquisitions

Carbon Energy Corporation ("Carbon") Business Combination

In May 2020, the Group acquired approximately 6,100 conventional wells in the states of Kentucky, West Virginia and Tennessee from Carbon. The Group paid purchase consideration of $98,121, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were $393. Depending on future natural gas prices and measured on an annual basis over the next three years, Carbon may earn additional contingent consideration of up to $15,000 in aggregate if actual NYMEX natural gas prices exceed certain established thresholds. Based on forward NYMEX natural gas prices at the time of closing, total estimated contingent consideration is $5,462. The Group funded the cash consideration for the purchase with proceeds from the $160,000 Term Loan I, discussed in Note 14.

In the period from its acquisition to 30 June 2020 the acquisition of Carbon increased the Group's natural gas and oil production by 1,832,771 Mcf and 9,313 Bbls, respectively. The properties associated with the acquisition have been co-mingled with our existing properties and it is impractical to provide stand-alone operational results related to these acquired properties for the six month period ended 30 June 2020. The Group is still finalising the valuation of the recently acquired assets. The provisional fair value of the assets and liabilities assumed were as follows:

Oil and gas properties	$	80,204
Oil and gas properties (asset retirement obligation, asset portion)	23,853
Property and equipment	26,733
Derivative financial instruments, net	3,464
Trade receivables	1,999
Deferred tax asset	1,210
Asset retirement obligation, liability portion	(23,853)
Trade and other payables	(46)
Other current liabilities	(9,981)
Net assets acquired	$	103,583

EQT Corporation ("EQT") Asset Acquisition

In May 2020, the Group acquired 889 proved developed wells and related gathering infrastructure in the states of Pennsylvania and West Virginia from EQT. The Group paid purchase consideration of $111,588, excluding customary purchase price adjustments. Transaction costs associated with the acquisition were $759 and have been capitalised to oil and gas properties. Depending on future natural gas prices and measured on a quarterly basis over the next three years, EQT may earn additional contingent consideration of up to $20,000 in aggregate if actual NYMEX natural gas prices exceed certain established thresholds. As of 30 June 2020 the fair value of the contingent consideration is $7,082.The Group funded the purchase with proceeds from the $160,000 Term Loan I, discussed in Note 14, and a short-term draw from the revolving credit facility, discussed in Note 14.

In the period from its acquisition to 30 June 2020 the acquisition of EQT increased the Group's natural gas production by 2,389,821 Mcf. The properties associated with the acquisition have been co-mingled with our existing properties and it is impractical to provide stand-alone operational results related to these acquired properties for the six month period ended 30 June 2020. The Group is still finalising the valuation of the recently acquired assets. The provisional fair value of the assets and liabilities assumed were as follows:

Oil and gas properties	$	114,259
Oil and gas properties (asset retirement obligation, asset portion)	3,142
Property and equipment	7,124
Asset retirement obligation, liability portion	(3,142)
Other current liabilities	(1,954)
Net assets acquired	$	119,429

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. The Group funded the cash consideration for the purchase with the proceeds from an equity placing of ordinary shares in April 2019 and a draw from the Credit Facility, discussed in Notes 12 and 14, respectively.

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. The Group funded the cash consideration for the purchase from a draw on the Credit Facility, discussed in Note 14.

Note 4 - 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 United States of America. The following table reconciles the Group's revenue for the periods presented:

	Six Months Ended				Year Ended
	30 June 2020		30 June 2019		31 December 2019
Natural gas	$	156,900	$	194,810	$	384,121
NGLs	7,029		18,439		33,685
Oil	6,903		10,048		20,474
Total commodity revenue	$	170,832	$	223,297	$	438,280
Gathering and compression	13,383		12,765		22,166
Other	663		1,396		1,810
Total revenue	$	184,878	$	237,458	$	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 collected within 30-to-60 days depending on the commodity, location and well-type.

Note 5 - Expenses by Nature

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

	Six Months Ended				Year Ended
	30 June 2020		30 June 2019		31 December 2019
Base lease operating expense ^(a)	$	43,368	$	51,777	$	102,302
Production taxes ^(b)	7,748		7,277		16,427
Gathering and compression ^(c)	24,380		20,552		44,060
Gathering and transportation ^(d)	23,455		15,523		39,596
Total operating expense ^(e)	$	98,951	$	95,129	$	202,385
Depreciation	14,601		11,290		23,568
Depletion	41,236		34,052		74,571
Total depreciation and depletion	$	55,837	$	45,342	$	98,139
Employees and benefits (administrative)	13,281		8,952		20,914
Other administrative ^(f)	5,066		3,554		7,384
Professional fees ^(g)	4,391		5,964		6,879
Rent	391		-		896
Adjusted G&A¹ ^(h)	$	23,129	$	18,470	$	36,073
Non-recurring costs associated with acquisitions ⁽ⁱ⁾	1,406		2,804		9,210
Other non-recurring costs ^(j)	8,655		-		7,542
Provision for working interest owners receivable ^(k)	-		-		730
Non-cash equity compensation ^(l)	1,506		408		3,064
Non-recurring and/or non-cash G&A ^(m)	$	11,567	$	3,212	$	20,546
Total G&A	$	34,696	$	21,682	$	56,619
Total expense	$	189,484	$	162,153	$	357,143

Aggregate remuneration (including Directors):
Wages and salaries	33,242		32,645		68,226
Payroll taxes	2,726		1,324		2,869
Benefits	7,329		2,886		5,766
Total employees and benefits expense	$	43,297	$	36,855	$	76,861

Base lease operating expense is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.
Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural gas, natural gas liquids 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 oil and gas properties and midstream assets.
Gathering and compression expenses are daily costs incurred to operate our owned midstream assets inclusive of employee and benefit expenses.
Gathering and transportation expenses are daily costs incurred to gather, process and transport the Group's natural gas, natural gas liquids and oil.
Total operating expense increased due to one month of operating expense related to the EQT and Carbon acquisitions as well as a full six month period of operating expenses related to the HG Energy and EdgeMarc assets acquired in April 2019 and September 2019, respectively. See Note 3 for additional information on acquisitions.
Other administrative expense includes general liability insurance, information technology services, other office expenses and travel.
Professional fees include legal, marketing, payroll, and consultation fees, as well as auditor remuneration fees and costs associated with being a public company.
Adjusted general and administrative expense ("Adjusted G&A")¹ includes payroll and benefits for our corporate staff, costs of maintaining 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.
Non-recurring costs associated with acquisitions primarily relate to legal and consulting costs directly related to the acquisitions.
Other non-recurring costs for 2020 are associated with legal and professional fees related to the uplist to the main market of the LSE and expenses for a one-time hedge portfolio restructuring. 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.
Provision for working interest owners receivable reflects a portion of receivables from working interest owners that the Group considers uncollectable.
Non-cash equity issuances in 2020 and 2019 reflect the expense recognition related to stock compensation provided to certain key managers.
Non-recurring and/or non-cash general and administrative expense ("Non-recurring and/or non-cash G&A") includes costs related to acquisitions, the Group's uplist to the main market of the LSE, and one-time projects.

Note 6 - Adjusted EBITDA

Adjusted EBITDA¹ is defined as operating profit (loss) plus or minus items detailed in the table below, which is of particular interest to the industry and the Group, as it is essentially the cash generated from operations that the Group has free for principal and interest payments, capital investments and dividend payments. Adjusted EBITDA¹ (hedged) and Adjusted EBITDA¹ (unhedged) 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 Group believes Adjusted EBITDA¹ (hedged) and Adjusted EBITDA¹ (unhedged) 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 its peers without regard to the Group's financing methods or capital structure. The Group excludes the items listed in the table below from operating profit (loss) in arriving at Adjusted EBITDA¹ (hedged) and Adjusted EBITDA¹ (unhedged) 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
- Costs associated with gains on oil & gas properties or 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 administrative expenses.

The following table reconciles operating profit (loss) to Adjusted EBITDA¹ for the periods presented:

	Six Months Ended				Year Ended
	30 June 2020		30 June 2019		31 December 2019
Operating profit (loss)	$	(30,780)	$	107,763	$	180,507
Depreciation and depletion	55,837		45,342		98,139
Gain on bargain purchase	-		-		(1,540)
(Gain) loss on fair value adjustments of unsettled financial instruments	109,680		(21,252)		(20,270)
(Gain) loss on oil and gas programme and equipment	-		336		-
Non-recurring costs	10,061		2,804		17,482
Non-cash equity compensation	1,506		408		3,065
Gain on foreign currency hedge	-		(4,120)		(4,117)
Total adjustments	$	177,084	$	23,518	$	92,759
Adjusted EBITDA¹ (hedged)	$	146,304	$	131,281	$	273,266
Less: Cash portion of settled hedges	83,506		11,542		53,584
Adjusted EBITDA¹ (unhedged)	$	62,798	$	119,739	$	219,682

Weighted average ordinary shares outstanding - basic	662,804		603,807		641,666
Weighted average ordinary shares outstanding - diluted	667,293		604,996		644,782

Adjusted EBITDA¹ (hedged) per ordinary share - basic	$	0.22	$	0.22	$	0.43
Adjusted EBITDA¹ (hedged) per ordinary share - diluted	$	0.22	$	0.22	$	0.42

Note 7 - Taxation

Income tax expense is recognised based on management's estimate of the weighted average effective annual income tax rate expected for the full financial year. The estimated tax rate used for the year to 30 June 2020 is 131.2%, compared to 26.0% for the six months ended 30 June 2019. The effective tax rate is primarily impacted by recognition of the federal well tax credit available to qualified producers in 2020 due to the low commodity pricing environment. 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 IRS 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 Mcf 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 state taxes and recurring permanent differences, such as meals and entertainment.

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

	Six Months Ended						Year Ended
	30 June 2020			30 June 2019			31 December 2019
Income (loss) before taxation	$	(59,227)		$	84,047		$	131,491
Income tax benefit (expense)	$	77,712		$	(21,881)		$	(32,091)
Effective tax rate	131.2		%	26.0		%	24.4		%

	Six Months Ended				Year Ended
	30 June 2020		30 June 2019		31 December 2019
Expected tax at statutory US federal income tax rate	21.0	%	21.0	%	21.0	%
State income taxes, net of federal tax benefit	3.8	%	5.0	%	6.0	%
Federal credits	108.5	%	(4.5)	%	(5.3)	%
Other, net	(2.1)	%	4.5	%	2.7	%
Effective tax rate	131.2	%	26.0	%	24.4	%

Note 8 - Earnings Per Ordinary Share

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

Six Months Ended

Year Ended

Calculation

30 June 2020

30 June 2019

31 December 2019

Income (loss) available to ordinary shareholders after taxation

18,485

62,166

99,400

Weighted average ordinary shares outstanding - basic

662,804

603,807

641,666

Weighted average ordinary shares outstanding - diluted

667,293

604,996

644,782

Earnings per ordinary share- basic

= A/B

0.03

0.10

0.15

Earnings per ordinary share- diluted

= A/C

0.03

0.10

0.15

Adjusted EBITDA1 (hedged) per ordinary share - basic

Note 6

0.22

0.43

Adjusted EBITDA1 (hedged) per ordinary share - diluted

0.22

0.42

Note 9 - Dividends

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

	Dividend per Ordinary Share
Date Dividends Declared/Paid	USD		GBP		Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid
Declared on 14 December 2018	$	0.0330	£	0.0434	8 March 2019	29 March 2019	542,654	$	17,908
Declared on 28 February 2019	0.0340		0.0432		12 April 2019	28 June 2019	542,654	18,450
Paid during the six months ended 30 June 2019								$	36,358
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
Paid during the six months ended 30 June 2020								$	47,246

On 4 May 2020 the Group announced a dividend of $0.0350 per ordinary share. The dividend will be paid on 25 September 2020 to shareholders on the register on 4 September 2020. This dividend was not approved by shareholders, thereby qualifying it as an "interim" dividend. No liability was recorded in the Group Interim Financial Information in respect of this interim dividend as at 30 June 2020.

Subsequent Events

On 10 August 2020 the Group announced a dividend of $0.0375 per ordinary share. The dividend will be paid on 18 December 2020 to shareholders on the register on 27 November 2020. This dividend was not approved by shareholders, thereby qualifying it as an "interim" dividend. No liability was recorded in the Group Interim Financial Information in respect of this interim dividend as at 30 June 2020.

Note 10 - Oil and Gas Properties

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

	Six Months Ended		Year Ended
	30 June 2020		31 December 2019
Costs:
Beginning balance	$	1,620,760	$	1,148,235
Additions ^(a)	229,481		482,525
Disposals ^(b)	-		(10,000)
Ending balance	$	1,850,241	$	1,620,760
Depletion and impairment:
Beginning balance	$	(129,855)	$	(55,284)
Period changes	(41,236)		(74,571)
Disposals	-		-
Ending balance	$	(171,091)	$	(129,855)

Net book value	$	1,679,150	$	1,490,905

For the six months ended 30 June 2020, $104,057 and $117,401 were related to the acquisitions of Carbon and EQT, respectively. 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 3 for additional information regarding these acquisitions.
In November 2019, the Group sold the three drilled but uncompleted unconventional wells that were acquired in the EdgeMarc acquisition. The carrying value of the wells at the time of sale was $10,000.

Impairment of oil and gas properties

In preparing the Group Interim Financial Information, the Directors considered whether there is any evidence that the Group's oil and gas properties are impaired for the period ended 30 June 2020. Having identified an impairment indicator relating to the decline of natural gas and oil prices and the macroeconomic impacts of COVID-19 the Group undertook an impairment test in line with its accounting policy. Having performed this assessment no impairment was recognised.

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

Note 11 - Property and Equipment

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

	Six Months Ended		Year Ended
	30 June 2020		31 December 2019
Property & equipment:
Beginning balance	$	360,237	$	337,618
Additions ^(a,b)	46,938		22,619
Disposals	(556)		-
Ending balance ^(c)	$	406,619	$	360,237
Accumulated depreciation and disposals:
Beginning balance	$	(34,371)	$	(12,432)
Period changes	(12,402)		(21,939)
Disposals	180		-
Ending balance	$	(46,593)	$	(34,371)

Net book value	$	360,026	$	325,866

Of the $46,938 in 2020 additions, $26,733 and $7,124 related to the acquisitions of Carbon and EQT, respectively. See Note 3 for additional information regarding these acquisitions.
Additions relate to routine capital projects on our compressor and gathering systems, vehicle and equipment additions, and costs related to the Group's ERP project.
Property & equipment is inclusive of right of use assets associated with the Group's leases.

Note 12 - Share Capital

In May 2020, the Group placed 64,281 new ordinary shares at $1.33 per share (£1.08) to raise gross proceeds of $85,415 (approximately £69,423). The Group used the proceeds to partially fund the acquisition of certain assets of Carbon and EQT discussed in Note 3.

In April 2019, the Group placed 151,515 new ordinary shares at $1.52 per share (£1.17) to raise gross proceeds of $230,676 (approximately £177,278). The Group used the proceeds to fund the HG Energy acquisition, discussed in Note 3.

In 2019, the Group announced the terms of a share buyback programme. For the period ended 30 June 2020, the Group repurchased 12,958 shares at an average price of $1.21 totalling $15,634. The Group has accounted for the repurchase of these shares as a direct reduction to retained earnings. All repurchased 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 1 January 2020	655,730	$	8,800	$	760,543
Issuance of share capital	64,281	790		80,804
Repurchase of shares	(12,958)	(74)		-
Balance at 30 June 2020	707,053	$	9,516	$	841,347

	Number of Shares	Total Share Capital		Total Share Premium
Balance at 1 January 2019	542,654	$	7,346	$	540,655
Issuance of share capital	151,515	1,972		219,888
Repurchase of shares	(38,662)	(518)		-
Other issues	223	-		-
Balance at 31 December 2019	655,730	$	8,800	$	760,543

Note 13 - Asset Retirement Obligation

The Group records a liability for the future cost of decommissioning its oil and gas 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 2094). 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.

In estimating the present value of future decommissioning costs of oil and gas 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 ceases to produce economically, which makes the determination dependent upon future oil and gas 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 risk adjusted discount rate used in the calculation of the decommissioning liability in 2020 was 7.2% (2019: 7.3%) and the allowance for annual cost increases 1.6% (2019: 2.3%) resulting in a net rate of 5.6% (2019: 5.0%).

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

	Six Months Ended		Year Ended
	30 June 2020		31 December 2019
Balance at beginning of period	$	199,521	$	142,725
Additions ^(a)	26,995		252
Accretion	7,395		12,349
Plugging costs	(1,201)		(2,541)
Revisions to estimate ^(b)	553		46,736
Balance at end of period	$	233,263	$	199,521
Less: Current asset retirement obligation	2,650		2,650
Non-current asset retirement obligation	$	230,613	$	196,871

See Note 3 for more information about the Group's acquisitions.
At 31 December 2019, the Group revised its asset retirement obligation to more closely align estimated plugging costs with historical cost incurred to plug and abandon wells, which resulted in a $4,086 increase to the liability. Additionally, in 2019, the Group updated its net discount rate from 5.8% at 31 December 2018 to 5.0% at 31 December 2019. This revision resulted in a $46,736 increase to the liability. At 30 June 2020 the Group performed normal revisions to its asset retirement obligation which resulted in an immaterial adjustment.

Changes to assumptions used as inputs for the estimation of the Group's asset retirement obligation could result in a material change in the carrying value of the liability. A one hundred basis point decline in the gross discount rate could have an approximately $90,269 impact on the Group's asset retirement obligation as at 30 June 2020.

Note 14 - Borrowings

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

	30 June 2020		31 December 2019
Credit Facility Interest rate of LIBOR plus 2.50% (2020) and LIBOR plus 2.00% (2019)	$	211,300	$	436,700
ABS I Note Interest rate of 5.00%	193,353		200,000
ABS II Note Interest rate of 5.25%	200,000		-
Term Loan I Interest rate of 6.50%	160,000		-
Miscellaneous, primarily for real estate, vehicles and equipment	6,398		8,219
Total borrowings	$	771,051	$	644,919
Less: Current portion of long-term debt	(58,245)		(23,510)
Less: Deferred financing costs	(24,896)		(22,631)
Less: Original issue discounts	(6,857)		-
Total non-current borrowings, net	$	681,053	$	598,778

Credit Facility

In June 2020, the Group reaffirmed its borrowing base on the $1,500,000 Credit Facility at $425,000. The Credit Facility is secured by oil and gas 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. The next redetermination is expected to occur in November 2020. As of 30 June 2020 the Group was in compliance with all financial covenants.

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.

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 Term Loan I was issued at a 1% discount. The Group used the proceeds of $158,400, net of discount to fund the Carbon acquisition, as discussed in Note 3, and to pay down its Credit Facility.

The Term Loan I is secured by the Group's producing assets acquired from Carbon and EQT discussed in Note 3.

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 30 June 2020, the Group incurred $1,039 in interest related to the Term Loan I which is recognised under the effective interest rate method.

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 manager 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 also subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the Term Loan I, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments. As of 30 June 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. During the period ended 30 June 2020, the Group incurred $2,657 in interest related to the ABS II Note which is recognised under the effective interest rate method.

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 also subject to certain customary events of default, including events relating to non-payment of required interest, principal or other amounts due on or with respect to the ABS II Note, failure to comply with covenants within certain time frames, certain bankruptcy events, breaches of specified representations and warranties, failure of security interests to be effective and certain judgments. As of 30 June 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 through a BBB- rated bond. The ABS I Note is secured by 21.6% of the Group's producing assets.

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

	30 June 2020		31 December 2019
Not later than one year	$	58,245	$	23,510
Later than one year and not later than five years	447,914		515,620
Later than five years	264,892		105,789
Total borrowings	$	771,051	$	644,919

Subsequent Events

In August 2020, subsequent to the 30 June 2020 Consolidated Statements of Financial Position date, and 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 has dedicated internal resources to the ABS I Note and the Term Loan I and believed the rating agencies' reviews and oversight were unnecessary. Both agencies affirmed the BBB- rating of the ABS I Note concurrent with the ratings withdraw, 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.

Note 15 - Other Assets and Liabilities

The following table includes details of other assets and liabilities as of the reporting date as follows:

	30 June 2020		31 December 2019
Other non-current assets
Other non-current assets	$	3,417	$	388
Indemnification receivable ^(a)	2,133		2,133
Total other non-current assets	$	5,550	$	2,521
Other current assets
Prepaid expenses	$	3,097	$	4,317
Other receivables	2,097		383
Inventory	5,010		5,163
Total other current assets	$	10,204	$	9,863
Other non-current liabilities
Uncertain tax position ^(a)	$	2,133	$	2,133
Other non-current liabilities ^(b)	9,911		2,335
Total other non-current liabilities	$	12,044	$	4,468
Other current liabilities
Accrued expenses	$	30,270	$	23,645
Taxes payable	27,156		19,379
Net revenue clearing ^(c)	9,114		9,287
Asset retirement obligation - current	2,650		2,650
Revenue to be distributed ^(d)	29,403		30,321
Other current liabilities	-		-
Total other current liabilities	$	98,593	$	85,282

At the date of acquisition, management determined that Alliance Petroleum had taken uncertain tax positions, and as a result, an indemnification agreement was executed. The Group recorded an indemnification receivable in the amount of $2,133. 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.
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 3.
Net revenue clearing is estimated revenue that is payable to third-party working interest owners.
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 16 - Derivatives

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. These risks are managed by the Group's use of certain derivative financial instruments. As of 30 June 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 MMBtu
	Volume			Sold		Purchased		Sold		Basis		Fair Value at
	(MMBtu)	Swaps		Puts		Puts		Calls		Differential		30 June 2020
2020
Swaps	84,084,198	$	2.69	$	-	$	-	$	-	$	-	$	58,517
Collars	2,910,000	-		-		2.55		2.76		-		1,844
Basis Swap	76,587,000	-		-		-		-		(0.41)		(2,803)
Total	163,581,198											$	57,558
2021
Swaps	159,866,549	$	2.62	$	-	$	-	$	-	$	-	$	1,522
Collars ^(a)	-	-		-		-		-		-		(1,058)
Stand-Alone Calls	7,300,000	-		-		-		2.60		-		(2,487)
Basis Swap	86,452,000	-		-		-		-		(0.40)		(3,040)
Total	253,618,549											$	(5,063)
2022
Swaps	101,724,000	$	2.51	$	-	$	-	$	-	$	-	$	8,516
Collars ^(a)	-	-		-		-		-		-		551
Stand-Alone Calls	92,691,750	-		-		-		2.77		-		(19,277)
Basis Swap	26,239,000	-		-		-		-		(0.45)		(1,432)
Total	220,654,750											$	(11,642)
2023
Swaps	88,957,000	$	2.44	$	-	$	-	$	-	$	-	$	5,661
Stand-Alone Calls	85,416,750	-		-		-		2.79		-		(15,381)
Basis Swap	900,000	-		-		-		-		(0.46)		(98)
Total	175,273,750											$	(9,818)
2024
Swaps	81,739,000	$	2.42	$	-	$	-	$	-	$	-	$	2,908
2025
Swaps	65,864,000	$	2.39	$	-	$	-	$	-	$	-	$	(647)
2026
Swaps	42,454,000	$	2.37	$	-	$	-	$	-	$	-	$	(3,602)
2027
Swaps	33,820,000	$	2.36	$	-	$	-	$	-	$	-	$	(2,715)
2028
Swaps	32,190,000	$	2.34	$	-	$	-	$	-	$	-	$	(4,594)
2029
Swaps	29,190,000	$	2.34	$	-	$	-	$	-	$	-	$	(6,764)
2030
Swaps	5,450,000	$	2.27	$	-	$	-	$	-	$	-	$	(2,252)
Swaptions
1/1/2022-12/1/2022 ^(b)	7,300,000	$	2.70	$	-	$	-	$	-	$	-	$	(926)
10/1/2024-9/1/2028 ^(c)	14,610,000	2.72		-		-		-		-		(2,789)
1/1/2025-12/1/2029 ^(d)	36,520,000	2.59		-		-		-		-		(6,519)
4/1/2026-3/1/2030 ^(e)	97,277,000	2.40		-		-		-		-		(29,718)
4/1/2030-3/1/2032 ^(f)	42,627,000	2.40		-		-		-		-		(21,006)
Total	198,334,000											$	(60,958)

Total	1,302,169,247											$	(47,589)

Residual value associated with offsetting trades.
Option expires on December 23, 2021.
Option expires on September 6, 2024.
Option expires on December 23, 2024.
Option expires on March 23, 2026.
Option expires on March 22, 2030.

*NGL CONTRACTS*		Weighted Average Price per Gallon
	Volume			Sold		Purchased		Sold		Basis		Fair Value at
	(Gallons)	Swaps		Puts		Puts		Calls		Differential		30 June 2020
2020
Swaps ^(a)	35,863,417	$	0.59	$	-	$	-	$	-	$	-	$	3,192
2021
Swaps ^(a)	37,018,421	$	0.38	$	-	$	-	$	-	$	-	$	(1,451)

Total	72,881,838											$	1,741

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		Basis		Fair Value at
	(Bbl)	Swaps		Puts		Puts		Calls		Differential		30 June 2020
2020
Swaps	111,000	$	70.32	$	-	$	-	$	-	$	-	$	3,418
Collars	33,000	-		-		53.21		56.74		-		621
Total	144,000											$	4,039
2021
Swaps	139,084	$	44.21	$	-	$	-	$	-	$	-	$	530
Collars	120,563	-		-		52.24		67.49		-		2,042
Total	259,647											$	2,572
2022
Swaps	110,494	$	43.06	$	-	$	-	$	-	$	-	$	187
2023
Swaps	69,947	37.00		-		-		-		-		(391)
2024
Swaps	64,044	37.00		-		-		-		-		(425)
2025
Swaps	56,075	37.00		-		-		-		-		(436)
2026
Swaps	13,467	37.00		-		-		-		-		(114)

Total	717,674											$	5,432

Derivative Financial Instruments	Consolidated Statements of Financial Position	30 June 2020		31 December 2019
Assets:
Non-current assets	Derivative financial instruments	$	2,155	$	3,803
Current assets	Derivative financial instruments	65,529		73,705
Total assets		$	67,684	$	77,508
Liabilities
Non-current liabilities	Derivative financial instruments	$	(104,103)	$	(15,706)
Current liabilities	Derivative financial instruments	(3,997)		-
Total liabilities		$	(108,100)	$	(15,706)
Net assets (liabilities):
Net assets (liabilities) - non-current	Other non-current assets (liabilities)	$	(101,948)	$	(11,903)
Net assets (liabilities) - current	Other current assets (liabilities)	61,532		73,705
Total net assets (liabilities)		$	(40,416)	$	61,802

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

	Six Months Ended				Year Ended
	30 June 2020		30 June 2019		31 December 2019
Net gain (loss) on derivative settlements ^(a)	$	83,506	$	7,422	$	49,467
Gain on foreign currency hedge	-		4,120		4,117
Total gain (loss) on settled derivative instruments	$	83,506	$	11,542	$	53,584
Gain (loss) on fair value adjustments of unsettled financial instruments ^(b)	(109,680)		21,252		20,270
Total gain (loss) on derivative financial instruments	$	(26,174)	$	32,794	$	73,854

Represents the cash settlement of hedges that settled during the period.
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.

Note 17 - 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 marked (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" 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 Management's 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. Management has elected to not 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. Management has 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 30 June 2020, 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 allows the Group, in the event of default by its counterparties, to elect early termination. The Group monitors the creditworthiness of its counterparties but are not able to predict sudden changes and hence may be limited in their 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 period ended 30 June 2020, 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 period ended 30 June 2020.

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 during the reporting period.

Financial Instruments

For trade receivables, the Group applies the simplified approach permitted by IFRS 9 "Financial Instruments", 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:

	Six Months Ended		Year Ended
	30 June 2020		31 December 2019
Cash and cash equivalents at amortised cost	$	6,715	$	1,661
Trade receivables and accrued income at amortised cost	69,642		73,924
Financial assets at amortised cost	5,514		771
Financial liabilities at amortised cost	(78,698)		(65,588)
Derivative financial instruments at fair value	(40,416)		61,802
Borrowings, net of deferred financing costs	(746,155)		(622,288)
Total	$	(783,398)	$	(549,718)

Note 18 - Contingencies and Provisions

The Group is involved in various pending legal issues that have arisen in the normal course of business. The Group may be subject to a withholding tax of a maximum of $8,800 payable to the US tax authorities in relation to its share buyback programme discussed in Note 12. At the date of approval of the Group Interim Financial Information, there is no formal tax assessment or audit from the US tax authorities in relation to this. As the share buyback transactions are recognised outside profit or loss, should the outcome of the determination process be that the Group is found to be liable to pay an amount of withholding tax, any necessary adjustment would be recognised through equity. The Group has no other contingent liabilities that would have any material impact on the Group's financial position or results of operations.

The Group's operations are subject to environmental regulation in all the jurisdictions in which it operates and was in compliance as at 30 June 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 19 - Related Party Transactions

UK legal counsel

During the six months ended 30 June 2020, Martin Thomas was a partner at Wedlake Bell LLP, the UK legal advisor to the Group. The total billings from Wedlake Bell LLP to the Group totaled $22 (approximately £18) for the six months ended 30 June 2020.

Dividend payments

For the year ended 31 December 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 20 - Subsequent Events

The Group determined the need to disclose the following material transactions that occurred subsequent to 30 June 2020, which have been described within each relevant footnote as follows:

Description		Footnote
Dividends		Note 9
Borrowings		Note 14

Glossary of Certain Terms

£		British pound sterling
$		U.S. dollar
AIM		Alternative Investment Market
APMs		Alternative performance measures
Base LOE		Base lease operating expense is defined as the sum of employee and benefit expenses, well operating expense (net), automobile expense and insurance cost.
Bbl		Barrel or barrels of oil or natural gas liquids
Boe		Barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas. The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
Boepd		Barrels of oil equivalent per day
Btu		A British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
E&P		Exploration and production
EBITDA		Earnings before interest, tax, depreciation and amortisation
EBITDAX		Earnings before interest, tax, depreciation, amortisation and exploration expense
EPS		Earnings per share
ERP		Enterprise resource planning
ESG		Environmental, Safety and Governance
GBP		British pound sterling
Henry Hub		A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
HBP		Held by production
IAS		International Accounting Standard
IASB		International Accounting Standards Board
IFRS		International Financial Reporting Standards as adopted by the European Union
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.
LIBOR		London Inter-bank Offered Rate
LOE		Lease operating expense is defined as base lease operating expenses, plus the owned gathering and compression expense, third-party gathering and transportation expense and production taxes.
LSE		London Stock Exchange
MBbls		Thousand barrels
MBoe		Thousand barrels of oil equivalent
Mcf		Thousand cubic feet of natural gas
Midstream		Midstream activities include the processing, storing, transporting and marketing of natural gas, NGLs and oil.
MMBoe		Million barrels of oil equivalent
MMBtu		Million British thermal units
MMcf		Million cubic feet of natural gas
Mont Belvieu		A mature trading hub with a high level of liquidity and transparency that sets spot and futures prices for NGLs.
NGLs		Natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production streams.
NYMEX		New York Mercantile Exchange
Oil		Includes crude oil and condensate
Realised price		The cash market price less all expected quality, transportation and demand adjustments.
TIAA		Teachers Insurance and Annuity Association of America
WTI		West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

[1] This metric is a non-IFRS financial measure. See "Alternative Performance Measures" included within this report for related disclosures and calculations.

SOURCE: Diversified Gas & Oil PLC

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Released August 10, 2020