Final Results

RNS Number : 3566R

Diversified Gas & Oil PLC

28 February 2019

Diversified Gas & Oil PLC

("DGO" or the "Company")

Final Results for the year ended 31 December 2018

Diversified Gas & Oil PLC (AIM: DGOC), the US based owner and operator of natural gas, natural gas liquids and oil wells as well as midstream assets, is pleased to announce the publication of its annual results for the year ended 31 December 2018.

Period Highlights:

• Completion of four accretive acquisitions totalling $938m while maintaining net debt/Adjusted EBITDA* at or below 2x

• Operating cash flow per share up 4x to $0.23 (2017: $0.06)

• Materially increased production and reserves through acquisition:

◦ Average daily production of 41,000 Boe/day up ~7x (2017: 6,600 Boe/day)

◦ Exit rate of 70,000 Boe per day for the quarter ended 31 December 2018 up ~7x (2017: 10,400)

◦ 474 MMboe of 1P PDP Reserves at 31 December 2018 up 8x (2017: 55 MMboe)

◦ PV10 of 1P PDP Reserves of $1.6bn up ~6x (2017: 0.3m)

• Total Revenue (Unhedged) up ~600% to $289.8m (2017: $41.8m):

◦ Realised revenue per fully diluted share of $0.71 up ~86% (2017: $0.36)

◦ 4Q18 realised price (unhedged) of $21.71 per Boe up 27% over 4Q17 primarily from changes in DGOs revenue stream (2017: $17.14)

◦ Realised significant and sustainable value from higher liquids volumes and through ownership of mid-stream infrastructure from both DGO and third-party production

• Successful integration process of acquired assets delivering operating synergies:

◦ Total cash unit costs reduced 20% to $8.55 per Boe (2017: $10.74)

• Adjusted EBITDA (Unhedged) up ~910% to $161.9m (2017: $16.0m)

◦ Adjusted EBITDA per fully diluted share up ~240% to $0.42 (2017: $0.13)

◦ Strong 2H18 Unhedged Adjusted EBITDA margins of 60% (2017: ~40%)

• Significantly strengthened balance sheet:

◦ $439m of new equity raised

◦ Established a $1.5bn revolving enlarged credit facility funded by a syndicate of twelve banks, enlarged twice in recognition of proved-developed-producing reserve growth

◦ Post-period, current liquidity of $270m (as of 28 February 2019)

◦ Post-period, current Net Debt/Adjusted EBITDA ratio of ~1.8x (as of 28 February 2019)

• Commencement of quarterly dividend payment:

◦ Q3'18 dividend of 3.30 cents per share to be paid on 29 March 2019

◦ Q4'18 dividend of 3.40 cents per share to be paid on 28 June 2019

◦ Total 2018 dividend per share of 11.225 cents per share up >2x vs 5.4 cents per share in 2017

• Signature of Asset Retirement Agreements:

◦ Successful negotiation and signature of agreements for DGO's asset retirement obligations with two states, West Virginia and Ohio

◦ A third agreement with Kentucky signed post period end in January 2019

◦ In final discussions with the Commonwealth of Pennsylvania regarding an agreement covering wells in the state, with signature expected in the near-term

* Adjusted EBITDA represents earnings before interest, taxes, depletion, depreciation and amortization and adjustments for non-recurring items such as gain on the sale of assets, acquisition related expenses and integration costs, mark-to-market adjustments related to the Company's hedge portfolio, non-cash equity compensation charges and items of a similar nature.

Commenting on the results, CEO and Founder, Rusty Hutson said:

"These results reflect a year of rapid growth as the Company continued to capitalise on opportunities in Appalachia to complete a number of material acquisitions consistent with our stated growth strategy. Despite the strength of these financial results, they only partially reflect the financial capabilities of the business going forward.

DGO is now a substantial producer generating strong free cash flow that enables us to maintain a healthy balance sheet, invest in organic growth and deliver exceptional value to our shareholders through our reliable quarterly dividend. The near-term objective will be to leverage the scale of our expanded footprint to extract maximum operating synergies and cost efficiencies. We continue to consider a robust pipeline of opportunities that fit with our operating profile and acquisition criteria. We believe that our exposure to US natural gas and low-risk business model differentiates us from our UK listed peers and provides us with confidence in our ability to generate long-term value for our shareholders."

Results presentation and audiocast

An analyst presentation will be held at 9.00am GMT on Thursday, 28 February 2019 at the offices of Buchanan (107 Cheapside, London, EC2V 6DN).

The presentation will be made available on the Company website, www.dgoc.com.

An audiocast of the presentation can be accessed shortly after the live presentation concludes through the following link: http://webcasting.buchanan.uk.com/broadcast/5c4b2d8ca0c50933d27109d1

This announcement contains inside information for the purposes of Article 7 of EU Regulation 596/2014.

Diversified Gas & Oil PLC

Rusty Hutson Jr., Chief Executive Officer

Brad Gray, Chief Operating Officer & Finance Director

Eric Williams, Chief Financial Officer

www.dgoc.com

ir@dgoc.com

+ 1 (205) 408 0909

Cenkos Securities plc

(Nominated Adviser)

Russell Cook

Katy Birkin

Ben Jeynes

+44 (0)20 7397 8900

Mirabaud Securities Limited

(Joint Broker)

Peter Krens

Edward Haig-Thomas

+44 (0)20 3167 7221

Stifel Nicolaus Europe Limited

(Joint Broker)

Callum Stewart

Nicholas Rhodes

Ashton Clanfield

+44 (0)20 7710 7600

Buchanan

(Financial Public Relations)

Ben Romney

Chris Judd

Henry Wilson

dgo@buchanan.uk.com

+44 20 7466 5000

Chairman's Statement

A year of tremendous growth

Since its admission to AIM in February 2017, DGO has delivered consistent and significant achievements that have been appropriately labelled as transformative. The Company concluded so many material and company-changing events in just a year that we have emerged as a wholly different company with a structurally different financial and production profile compared to only twelve months ago. As of today, we are proud to be the largest producer on AIM by a comfortable margin and one of the largest conventional producers across the Appalachian Basin within the United States.

Structurally transforming the business with scale, midstream and additional liquids processing

Whilst we undoubtedly accelerated the momentum of our growth in 2018, the strategy to grow the Company around stable cashflow while maintaining a commitment to keep leverage low has remained consistent. The Company has achieved impressive growth through a measured execution of our strategy in terms of acquiring value-accretive and complementary assets within the Appalachian Basin, all of which help to optimise DGO's overall portfolio to deliver impressive cash margins, earnings and return value to our shareholders. Each acquisition completed since listing has delivered larger scale opportunities, allowing us to cement our position and reputation as the consolidator of choice in the region. Our success in selecting the right opportunities for growth has led to the emergence of an environment in which sellers of the types of assets that meet our investment profile now approach the Company for discussions, further enhancing our ability to source value-accretive opportunities for the future.

The market dynamics, upon which DGO's inorganic growth strategy is based, remained favourable throughout the year. Large packages of assets were available at valuations that allowed us to deliver debt-adjusted and per-share accretion to our shareholders. We capitalised on the opportunities to achieve considerable scale, add additional liquids reserves to our portfolio including both crude oil and natural gas liquids and establish a more balanced and diversified business, including the strategic decision to acquire a sizeable midstream footprint. Importantly, the midstream assets not only provide an additional revenue stream as we move gas for other producers in the region, but also affords us the ability to flow our own production to processing facilities that optimise the realised price we receive for our production. Therefore, we not only delivered a six-fold increase in production, but significantly increased the cash margins earned by our business. Through our strategic and structural changes to the business underpinned by scale, midstream assets, higher liquids production and access to processing, we materially enhanced the economics of our business by widening our control of the value stream within the Appalachian Basin and providing cost efficiencies and economies of scale. Additionally, we multiplied our PDP Reserves by 8x from a largely undeveloped acreage position across the Appalachian Basin, which further positions us to unlock incremental value in the years to come.

Investment in accretive growth

A key strategic focus throughout the year has been to invest in our company to ensure it can meet current and future growth expectations. We recognised the requirement to have the appropriate people, systems, processes and controls to effectively and responsibly manage our rapidly growing business. The high quality personnel joining the group through acquisition, their detailed and valuable institutional knowledge of the assets and their commitment to safe and efficient operations have helped ensure smooth integration. We benefit from the overarching professional culture that permeates the Basin and allows us to near seamlessly integrate diverse teams of professionals into one, unified company. While being careful to maintain the institutional knowledge at the well-level, we have streamlined the management oversight of the assets to reduce administrative costs while empowering the individual charged with the wells' performance. To that end, we have invested time and resources into the development of our Company-driven programmes to smartly oversee the efficient operating of a vast landbank and sizeable portfolio of production wells.

Well management and asset retirement

With a portfolio consisting of thousands of wells across multiple states, safety remains our top priority as we demonstrate our commitment to be a good corporate citizen within each community. We remain focused on acquiring mature producing wells with a low-decline profile, on which we then deploy innovative, optimising programs that set a new standard for efficient well-management and the eventual responsible retirement of non-productive wells. One of DGO's core differentiators, and a central component to our overall investment thesis, is our ability to manage assets more efficiently and profitably than the vendors for whom the assets had become non-core. We accomplish this "Smarter Well Management" by leveraging our portfolio's scale, diverse institutional knowledge from a growing body of professionals with unique experience and geographical proximity to extract maximum value, and by implementing our internally developed "Smarter Well Management Program". This program, tailored for each asset, focuses on optimising production from active wells and, where economically possible through a variety of means, returning inactive wells to production.

Of course, with a large base of producing assets, asset retirement is an obligation we understand. We take a proactive approach to long-term environmental and economic sustainability and we are fully committed to fulfilling our duties as an operator of mature assets. The vast majority of our portfolio is long-life and will produce sustainably for many decades to come and we will safely retire non-productive wells in line with the regulatory needs of the states in which we operate.

Managing risk through long-term agreements and hedging

DGO's overall strategy is grounded in the types of assets we acquire and a low-risk approach to how we manage our business and balance sheet. With a strict focus on free cash flow, we ensure a tight handle on all expenditures so that we can budget accordingly and maintain visibility on our earnings and cash flow. Managing our liabilities, particularly those related to asset retirement, is an important element of this approach, and we were delighted to complement our long-term agreement with Ohio by finalising additional long-term agreements with the appropriate regulatory bodies in West Virginia, prior to year-end, and most recently in Kentucky. Collectively, these three agreements provide clear visibility on future asset retirement activities that cover approximately 60% of our assets. We continue to work diligently with regulators in Pennsylvania to finalize a similar, long-term agreement covering our wells in that State and we intend to have the entire DGO portfolio covered by long-term agreements in the near term.

Producing stable cash flow for investors is another of our stated strategic objectives. The Company's liquidity position as at 28 February 2019 is approximately $270 million providing ample liquidity for additional non-dilutive, cash-flow and earnings accretive growth. To assist in this objective, we seek to mitigate risk in the business through our hedging strategies. The spike in US natural gas prices to nearly $5.00 per MMBtu in November 2018 and subsequent fall back to approximately $3.00 per MMBtu in December 2018 highlight the volatile nature of commodity prices. Our hedging strategies are designed to ensure we maintain clear visibility of our cash flow while minimising any exposure to downside risk. Not only does our high degree of vertical integration complement our hedging strategy by insulating us from cost movements within the services sector, but our balance sheet, liquidity, low leverage and exceptional cash margins of approximately 60% in a sub-$3.00 per MMBtu commodity price environment place us in a position of strength to not only to deliver strong results during periods of volatility, but to opportunistically acquire assets that volatility may drive to market. Overall, the long-term fundamentals for US natural gas pricing and regional differentials remain attractive, and with solid execution of our hedging strategies, we are well positioned to lock in upside value.

A gas business with growing exposure to economic-enhancing natural gas liquids

DGO is a gas business with increasing exposure to natural gas liquids which provides us with protection from the uncertain outlook and economic challenges presented by volatile global crude pricing. As demonstrated by our financial results, DGO is highly profitable even at current gas prices, and our growth opportunities remain protected from wider market concerns such as pricing, industry capex and geopolitics. It is our measured approach and uniqueness of our business model that resonates with investors and helps us stand out in a crowded market.

Conclusion

2018 was a second year of remarkable growth for DGO in which we capitalised on favourable market conditions, remained deeply committed to a well-defined strategy and further leveraged our early-mover advantage to develop a robust business model with a niche focus. We have undergone a process of transformational and structural change and the Company is firmly positioned for continued execution of our disciplined strategy. Additionally, we have invested in talented and committed employees that will drive our future growth. I must congratulate my colleagues on the successful execution of such an ambitious yet well-defined growth strategy. I also wish to thank our shareholders, debtholders and other stakeholders for the support that has enabled us to deliver this level of growth in such a short period of time. Our focus for the coming year will be on extracting maximum value from our enlarged portfolio for the benefit of our shareholders.

Robert M. Post

Chairman of the Board

Chief Executive's Statement

Introduction

2018 marks another tremendous year for DGO, during which we once more demonstrated that our business model, supported by a well-defined strategy, delivers sustainable and material value to our shareholders.

We completed four significant acquisitions during the year with an aggregate purchase price of $938 million before customary adjustments, and collectively the acquisitions increased DGO's net daily exit-rate production 7x from ~10,000 boe/d to ~70,000 boe/d and PV-10 from $259 million to $1.6 billion. To fund our transformation and consistent with our commitment to never place the balance sheet at risk for the sake of growth, we raised $492 million of equity financing including $439 million in two significantly oversubscribed public equity offerings and $53 million issued as acquisition consideration through a private placement with the sellers of certain assets.

Moreover, to reduce our borrowing costs, we moved quickly to replace 10% largely term-loan financing with a low-cost facility (currently 5.2%) that began with a syndicate of seven banks and, after two upsizes during the year following acquisitions, ended the year with an expanded syndicate of twelve high-quality banks. Importantly, the facility provides the complementary debt capital needed to continue executing on our growth strategy in the most cost-effective way whilst remaining comfortably within our guided leverage ratio.

Throughout 2018 we reinforced our foundations, and enter 2019 with a stronger, broader platform from which to generate long-term value by capitalising on the benefits of scale and high visibility as the capable consolidator of long-life, stable cash-generative assets.

Delivering on our strategic objectives

Building upon what was already a transformational year in 2017, we continued to deliver results for shareholders that were directly tied to our clearly stated objectives, underpinned by exceptional assets. We emerged from 2018 as the largest producer on AIM, clearly differentiated as a low-risk, cash flow positive, dividend paying E&P. The following table highlights progress in KPIs:

Stated Objective	Unit	FY2017	FY2018	% Change vs 2017FY	4Q17	4Q18	% Change vs 4Q17
Grow through accretive acquisitions	$m	88.7	938	957%	-	183	100%
Increase production	MBOEPD	6.6	41.0	521%	10.4	70.0	573%
Increase proved-developed-producing reserves	MMBOE	55	474	762%	n/a	n/a	n/a
Increase PV-10 reserves	$bn	0.3	1.6	433%	n/a	n/a	n/a
Increase acres held by production	MM Acres	1.6	7.8	388%	n/a	n/a	n/a
Increase revenue (Hedged) (a)	$m	43.3	274.0	533%	16.7	128.4	669%
Increase revenue (Unhedged)	$m	41.8	289.8	593%	16.41	139.7	751%
Reduce unit lease operating costs (b)	$ per BOE	7.02	4.83	(31)%	6.77	4.22	(38)%
Reduce unit recurring G&A	$ per BOE	2.03	1.34	(34)%	1.76	1.32	(25)%
Adjusted EBITDA (Hedged)	$m	17.5	146.2	735%	6.8	73.6	982%
Adjusted EBITDA Margin (Hedged)	%	40%	53%	13 points	41%	57%	16 points
Adjusted EBITDA (Unhedged)	$m	16.0	161.9	912%	6.6	84.9	1,186%
Adjusted EBITDA Margin (Unhedged)	%	38%	56%	18 points	40%	61%	21 points

a)	Includes the impact of settled hedges. See Note 12 below for more information on hedges.
b)	Lease operating expenses are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs include maintenance, repairs, insurance, employee and benefits and automobile expenses. See Note 4 below for more information.

The consolidator of choice

Before expanding upon each of our completed acquisitions, and in turn how we have successfully integrated them into our business, it is important to re-emphasise the strict criteria each acquisition target must meet before we consider it a potential fit for the DGO portfolio. Our disciplined approach to evaluating opportunities ensures that we only pursue those that possess a consistent asset profile, compelling upside and drive positive debt-adjusted cash flow per share that supports our dividend policy. Our refusal to compromise on these investment criteria is demonstrated by all of our acquisitions being immediately accretive due to the incremental contribution obtained from synergistically derived lower unit operating costs compounded by driving our realised prices higher through deliberate and sustainable structural changes in our revenue stream. Indeed, when comparing our realised unhedged price in the fourth quarter of 2018 compared to the same quarter last year, approximately two-thirds of our unhedged realised price increase of $4.57 per Boe is attributable to the structural changes including a higher liquids content and the addition of our midstream capabilities, with the remaining one-third of the unhedged realised price increase attributable to the underlying increase in natural gas spot prices and lower basin differentials.

Key strategic considerations supporting the rationale for our completed 2018 acquisitions included:

Drive sustainable increases in realised prices:

• Increase liquid production

• Create value by controlling the value chain

• Protect cash flows by diversifying gas marketing

Drive well productivity enhancements through DGO's Smarter Well Management:

• Optimise production from neglected wells

• Reduce costs and expand margins with operational efficiencies

During the first quarter, we announced the acquisitions of Alliance Petroleum Corporation ("Alliance") and assets from CNX Gas Corporation ("CNX") for a total consideration of $180 million, $95 million and $85 million respectively. The acquired wells are geographically situated within our operating footprint in the Appalachian Basin, and concentrated in Ohio, Pennsylvania and West Virginia. In combination, our then total net daily production increased by nearly 175 percent to approximately 170,000 Mcfe or 28,000 Boe. Similarly, the combined acquisitions increased Diversified's total proved developed producing reserves by nearly 220 percent to 173 million Boe.

In July, we completed what was the largest acquisition by any oil and gas company in the history of the AIM market - the $575 million acquisition of EQT Corporation's ("EQT") southern Appalachian producing gas and oil and midstream assets. This acquisition delivered a major step change in our financial and operational profile not only by expanding our already strong cash margin generation but also by adding a significant midstream asset that not only enhanced the economics of the upstream assets but also diversified our revenue stream by providing additional revenues from third-parties moving their production on the midstream system. Ultimately, the acquisition increased DGO's daily production by approximately 115% to over 60,000 barrels of oil equivalent per day, firmly establishing DGO as the largest gas and oil producer on AIM.

Building upon an earlier point, the sizeable midstream asset represented a unique characteristic of the EQT acquisition and laid the foundation for complementary growth in the southern region of the Appalachian Basin. Spanning more than 6,400 miles of pipelines and including 59 compressor stations, this strategic operational diversification significantly enhanced the economics of not only the producing wells we acquired and those we previously owned in the region, but further provided DGO with a competitive advantage to acquire additional assets in the region by materially enhancing our cost structure. With respect to our existing wells, the midstream assets created additional value by eliminating third party transport costs while simultaneously providing greater market pricing optionality, which collectively fuelled higher cash margins per unit of production. Furthermore, the midstream assets provide a meaningful additional revenue stream related to the handling of third-party production through owned pipelines and processing facilities.

Rounding out 2018, our acquisition of Core Appalachia Holding Co LLC ("Core") in October for $183 million was a highly synergistic acquisition due to its geographical proximity to the assets we acquired from EQT. By expanding both our upstream and midstream assets in the southern region of the Basin, we unlocked additional value from both packages of assets. Specifically, we have been able to transition to more efficient field operations while using the enlarged midstream asset to flow a significant portion of Core's production to a process facility accessible using the midstream acquired from EQT that allowed DGO to realise the economic uplift of processing and selling the natural gas liquids included in Core's liquids-rich production stream.

We exited the year with a daily production of over 70,000 boepd, and over 10,500 miles of midstream pipeline and associated infrastructure, in a portfolio that establishes DGO as the largest conventional operator in the basin.

Enhancing our capabilities

While additional opportunities for complementary growth exist within the Appalachian Basin, DGO has grown its scale in the region to afford it unique operational synergies. Not only have we exponentially grown our production and cash flow through the course of 2018, we also materially enhanced the composition of our production stream by adding a significant liquids portion while simultaneously expanding our operating capabilities. Over the last twelve months, we have grown our workforce six-fold to nearly 1,000 seasoned and talented employees across the multiple disciplines that support our expanded operations. Near seamlessly integrating our workforce has been a critical component to our success. The vast majority of those joining the Diversified team have done so from the organisation divesting of the acquired assets, which affords us the opportunity to retain the valuable institutional knowledge that perfectly complements our Smarter Well Management. We strive to leverage additional skills, experience and perspective across the enlarged operation seeking to apply best practices while always mindful that one-size does not fit all as we empower the professional at the well level to effect change that drives value.

Recognising that a skilled team requires the right tools to be successful, we look ahead to 2019 with plans to make strategic investments in the underlying technologies and data systems needed to most efficiently manage and optimise our growing base of assets. Specifically, we are taking steps to partner an expanding base of human intellectual capital with sophisticated systems to drive innovative initiatives.

With our broad footprint across the Appalachian Basin, the aggregation of the collective resources including People, Processes and Systems emerges as a core focus to establish DGO as one large and collaborative knowledge base in the region. In this regard, our senior management team fosters a culture of excellence amongst our highly skilled workforce to ensure we achieve our growth objectives and operate the business as safely, efficiently and effectively as possible.

We recognise that with the scale of our operations, DGO has become a Big Data Company necessitating that we invest in the systems needed to effectively manage diverse and expansive data. To this end, we have tasked our Chief Information Officer to lead an effort to establish a network of systems that include a new ERP and managed resource system that encapsulates Supervisory Control and Data Acquisition (SCADA), field data and measurement systems. We expect that these systems will help identify further production enhancement opportunities from the portfolio going forward.

Creating value

In line with our organic growth strategy, one of our fundamental operational objectives is to return previously unproductive wells to production. Not only does doing so defer the need to retire the well, but simultaneously increases production and cash flow while economically benefiting the communities in which we operate by creating jobs, tax revenues and royalty income. Since 2017 DGO has returned more than 650 wells back into production, demonstrating that our approach to managing our assets differs from those divesting of these assets and creates additional value for stakeholders.

Given the average profile of our conventional wells, the process for regenerating production is often straightforward and generally low-cost with payback periods of days or months rather than years. Our Smarter Well Management programme constitutes well maintenance and workover activity to improve production from active wells and return inactive wells into production.

While by no means an exhaustive list, examples of our Smarter Well Management programme geared to lengthening the operational and economic life of our wells include:

• Pumpjack Installation: For wells with higher oil production potential, the team will manage the well to reduce casing pressure and install a pump jack set to run on an optimised cycle that maximises produced oil.

• Setup Optimisation: Reconfiguring wellhead setup (which is usually accomplished by relocating sensors closer to the well) to significantly increase well up-time.

• Annulus / Top Management: Plumbing the annulus into flow lines to establish a steady production rate from previously shut-in wells

• Plunger Lift Setup: Installing plunger lifts on wells to decrease the fluid load on the well, allowing gas to flow more freely.

• Water / Chemical Treatments: Treating the casing and tubing with fresh water, salt and acid sticks, to improve the overall gas flow a well.

• Wellhead Compression: Compression can be costly and is utilised only after several other optimisation methods have been exhausted. In certain cases, the team has managed to link a single well-head compressor to multiple wells, increasing production across all.

Through these and similar initiatives, the Company is able to help offset the natural and already low-decline rate of production thereby creating additional value. An independent analysis of our portfolio of producing wells by Wright & Company, leading reserve engineers who specialise in this region of the United States and who acts as DGO's independent reserve auditor, indicates that the portfolio is declining by approximately 5% annually, consistent with mature assets of this nature in Appalachia. Wright & Company's work also support the long-life production profile of the portfolio, affirming the Company's conclusion that the majority of our operated wells will continue to produce for multiple decades to come.

Capitalising on the unique window of opportunity for M&A in the region, our efforts to grow production have focused exclusively on the vast inorganic opportunity set before us, though we are acutely aware of the potential of our existing asset base. We have a substantial portfolio of approximately 7.8 million net and largely held-by-production acres that has been sparsely drilled and largely undeveloped. Present development sits at >100 acre spacing, whilst a fully developed production programme can constitute approximately 20 acre spacing (implying four additional well locations per producing well).

We are beginning to evaluate selective drilling opportunities across our portfolio to ensure we are well placed to initiate drilling activity at the appropriate time, defined as an environment in which we can generate better rates of return than we do currently do through inorganic growth.

Safe and Systematic Well Retirement

In line with our reputation as a leading operator in the region, DGO is committed to act as a good steward of the environment within the states in which it operates. We have always made provisions for our well asset retirement obligations and during the year, embarked on enhancing and formalising our arrangements with the various state environmental regulatory departments to bolster these commitments. The objective of the agreements is to provide certainty for the states with regard to our commitment to fulfil our obligations as an operator of mature wells, whilst providing all parties, including DGO, our stakeholders and the state with clear long-term visibility on our asset retirement activities, the related liabilities and our ability to fund retirement from free cash flow.

Because of the systematic and ongoing nature of our well retirement programme, we have the ability to create value and improve cash flow by obtaining preferred vendor pricing in exchange for guaranteed utilisation for their service crews while also leveraging the knowledge we derive from a growing body of work to drive efficiencies and reduces costs on a prospective basis.

We are evaluating options to expand the use of and/or add additional skilled in-house labour to reduce third-party costs, using bespoke cement plugs to conform with local regulations as opposed to using standardised design across all wells, and right-sizing location containment to efficiently dispose of well-site waste. These initiatives have resulted in proven plugging cost reductions, in some examples lowering the cost of retiring a well by one-third.

Well capitalised for growth

We could not have achieved our strategic objectives without the confidence and support from our shareholders and lenders. Through 2018, DGO successfully raised $492 million including $439 million in two over-subscribed equity placements and the issuance of $53 million of equity to the vendors of Core Appalachia Holding Co LLC, which we acquired in October 2018, in addition to deploying incremental debt capital via our low-cost revolving credit facility to complete our acquisitions. Collectively, this balanced use of debt and equity financing demonstrates our commitment to maintain a strong balance sheet and low leverage, which we view as a critical component of our success. Our net debt to adjusted EBITDA currently sits at just 1.8x.

With respect to the credit facility we established in March 2018, we significantly expanded our borrowing capacity by upsizing our revolving credit facility twice during 2018 - first in July 2018 to $1.0 billion and most recently in December 2018 to $1.5 billion. Similarly, we grew our borrowing base from $200 million in March 2018 to $600 million in July 2018 and to its current level of $725 million as of December 2018. The bank syndicate, co-arranged by KeyBanc Capital Markets, The Huntington National Bank, Citizens Bank, N.A., Branch Banking and Trust Company ("BB&T") and Royal Bank of Canada ("RBC") includes other lending institutions for a total of 12 participating banks.

The commitment of such a large facility reinforced the faith that these lenders have in our business model, the quality of our assets and our ability to maintain a healthy balance sheet. In line with the Company's measured approach to risk exposure, we continue to operate comfortably within our previously guided leverage ratio of 2-2.5x Adjusted EBITDA/Net Debt. Despite significant growth, we have never wavered from our commitment to maintain a healthy balance sheet underpinned by strong cash flow, which we also re-invest in the business after returning a portion of cash flow to shareholders in the form of quarterly dividends. In fact, in 2018 we paid $31 million to shareholders in the form of dividends, up from $6 million in 2017.

Dividend

The Board is recommending a final dividend of 3.40 cents per share making the total dividend for the full-year of 11.225 cents per share (2017: 5.44 cents per share). The significant growth of our dividend over the last twelve months falls in line with our key strategy of continued shareholder value growth.

If approved the final dividend will be paid on 28 June 2019 to those shareholders on the register on 31 May 2019.

A proven model

The acquisitions made in 2018 highlight the growth strategy in practice in that our acquisitions are not executed for the sake of production growth, but rather, selected on the basis of how they will complement the larger portfolio by delivering operating efficiencies that drive down operating costs and enhance our EBITDA margins. We continue to develop a track record for extracting value upside from integrated assets and this is evidenced through the positive trending financial KPIs addressed in the Financial Review.

Outlook

To call 2018 transformational seems a bit of an understatement given our growth resulted in a series of material step-changes for our operational and financial profile. Certainly pleased, yet never satisfied with our progress, we continue to seek ways to further our strategy of optimising well performance and capitalise on compelling, per-share accretive acquisition opportunities in the Appalachian Basin.

Our primary near-term focus is balanced both on extracting maximum value from our enlarged portfolio by leveraging operating synergies to drive both top line growth and further cost reductions that collectively strengthen our already robust EBITDA margins while prudently evaluating opportunities to expand our assets. The successful execution of our Smarter Well Management programme will contribute to our production targets, whilst we begin to survey infill drilling opportunities across our expansive footprint in the oldest producing basin within the United States. We will continue to operate efficiently and safely and meet our asset retirement obligations as set forth in our agreements.

With our past success creating additional amplification of potential sellers' awareness of DGO as a credible buyer of producing assets, we continue to survey a robust pipeline of potential growth opportunities, and we have managed our balance sheet to enable us to consider opportunities that fit our investment criteria and that offer compelling returns for the benefit of our shareholders.

The outlook for the coming year and beyond is wholly encouraging, and we are fortunate to have strong opportunities on account of our low-risk business model. The Company has undoubtedly achieved rapid expansion and our focus will be on the continued successful integration and value extraction of the material acquisitions completed last year.

Financial Review

	Year Ended 31 December 2018	Year Ended 31 December 2017	$ Change	% Change
Net production
Natural gas (MMcf)	79,051	13,119	65,932	502.6%
Oil (MBbls)	308	163	145	89.0%
NGL (MBbls)	1,467	50	1,417	2,834.0%
Total (MBOE)	14,950	2,400	12,551	523.1%
Average daily production (BOE/d)	40,959	6,574	34,385	523.1%
% gas (BOE basis)	88%	91%
Average realised sales price
(excluding impact of cash settled derivatives)
Natural gas (Mcf)	$2.77	$2.32	$0.45	19.4%
Oil (Bbl)	62.07	49.37	12.70	25.7%
NGL (Bbl)	28.53	20.86	7.67	36.8%
Total (BOE)	$18.74	$16.48	$2.26	13.7%
Average realised sales price
(including impact of cash settled derivatives)
Natural gas (Mcf)	$2.62	$2.44	$0.18	7.3%
Oil (Bbl)	54.88	49.07	5.81	11.8%
NGL (Bbl)	27.53	20.86	6.67	32.0%
Total (BOE)	$17.69	$17.11	$0.58	3.4%
Natural gas and oil revenue
(in thousands)
Natural gas	$219,189	$30,463	$188,726	619.5%
Oil	19,117	8,047	11,070	137.6%
NGL	41,854	1,043	40,811	3,912.8%
Total natural gas, oil and NGL revenue	$280,160	$39,553	$240,607	608.3%
Other revenue	2,294	2,224	70	3.1%
Midstream revenue	7,315	-	7,315	100.0%
Total revenue	$289,769	$41,777	$247,992	593.6%
Gains (losses) on derivative settlements
Natural gas	$(11,979)	$1,574	$(13,553)	(861.1)%
Oil	(2,214)	(49)	(2,165)	4,418.4%
NGL	(1,462)	-	(1,462)	(100.0)%
Net (loss) gains on derivative settlements	$(15,655)	$1,525	$(17,180)	(1,126.6)

Per BOE metrics
Realised price (including impact of cash settled derivatives)	$17.69	$17.12	$0.57	3.3%
Other revenue	0.64	0.93	(0.28)	(30.7)%
Lease operating expenses	4.83	7.02	(2.19)	(31.2)%
Recurring administrative expenses	1.34	2.03	(0.69)	(33.9)%
Production taxes	0.80	0.56	0.24	42.9%
Gathering and transportation	1.58	1.13	0.45	39.5%
Operating margin	$9.78	$7.30	$2.48	34.0%
% Operating margin	53.3%	40.4%

Production, Revenue and Hedging

Total revenue in 2018 was $289.8 million a 593% increase over $41.8 million for 2017. The increase in revenue was primarily attributable to a 523.1% increase in produced volumes sold on a barrel of oil equivalent basis compounded by a 13.7% increase in the average realised sales price. DGO ended 2018 with net MBOE sales of approximately 14,950 vs. the prior year sales of approximately 2,400. Production increases, modestly offset by the customary shallow declines on wells of this nature, were driven primarily by the acquisition of additional producing wells from Alliance Petroleum Company ("APC") and CNX Resources LLC ("CNX") in March 2018, from EQT Production Company ("EQT") in July 2018, and TCF II Core, LLC ("Core") in October 2018. See Note 2 for additional information regarding DGO's acquisitions.

The following table is intended to reconcile the change in oil and natural gas revenue for 2017 by reflecting the effect of changes in volume and in the underlying prices.

	Natural gas		Oil		NGL		Total
Revenue for the year ended 31 December 2017	$	30,463	8,047		1,043		39,553
Volume increase	153,098		7,158		29,559		189,815
Price increase	35,628		3,912		11,252		50,792
Net increase	188,726		11,070		40,811		240,607
Revenue for the year ended 31 December 2018	$	219,189	$	19,117	$	41,854	$	280,160

To manage its cash flows in a volatile commodity price environment, DGO uses a combination of physical and financial derivative instruments. As required by its senior secured credit facility, DGO executed a combination of fixed price physical contracts, price swap financial contracts and two-way collar financial contracts equal to approximately 75% of the Company's forecasted production volumes for a 36-month rolling period. Refer to Note 12 for additional information regarding DGO's hedge portfolio.

Expenses


	Year ended										Total Change				BOE Change
	31 December 2018		Per BOE		31 December 2017		Per BOE		$			%		$			%

Lease operating expenses (a)	$	72,244	$	4.83	$	16,851	$	7.02	$	55,393		329	%	$	(2.19	)	(31)	%
Production taxes	11,978		0.80		1,345		0.56		10,633			791	%	0.24			43	%
Gathering and transportation (b)	23,572		1.58		2,712		1.13		20,860			769	%	0.45			40	%
Total operating expense	107,793		$	7.21	20,908		$	8.71	$	86,887		416	%	$	(1.50	)	(17	)%
Depreciation and depletion	41,988		2.81		7,536		3.14		34,452			457	%	(0.33		)	(11	)%
Administrative expenses	40,524		2.71		8,919		3.72		31,605			356	%	(1.01		)	(27	)%
Total expenses	$	190,307	$	12.73	$	37,363	$	15.57	$	152,944		409	%	(2.84		)	(18	)%

a)		Lease operating expenses are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs include maintenance, repairs, insurance, employee and benefits and automobile expenses.
b)		Gathering and transportation expenses are daily costs incurred to gather, process and transport gas.

In total, DGO's operating expenses in 2018 were $190.3 million compared to $37.4 million in 2017, though on a per-unit basis dropped 18% from $15.57 to $12.73. The $152.9 million increase reflects the following:

• A $86.9 million increase in additional expenses related to newly acquired oil and gas properties from APC, CNX, EQT and Core during 2018 and from the Titan acquisition in 2H17. On a per BOE basis, operating expense decreased by 17% which was attributable to higher production volumes received from an increased number of producing wells from these acquired properties.

• A $34.5 million increase in depreciation and depletion primarily due to an increased depreciable base related to oil and gas properties and higher production volumes as a result of the acquisitions made as discussed above.

• A $31.6 million increase in administrative expenses reflecting costs of the Company's acquisition efforts in 2018 and the investment made in staff and systems to support the Company's growth.

Refer to Note 2 below for additional information regarding DGO's acquisitions.

Finance costs

	Year ended				Year over Year
	31 December 2018		31 December 2017		$ Change		% Change

Interest		$15,433		$3,776		11,657	308.7	%
Finance charge	-		140		(140)		(100.0)	%
Bond financing costs	2,230		675		1,555		230.4	%
Other	80		634		(554)		(87.4)	%
Total finance costs		$17,743		$5,225		12,518	239.6	%

Loss on early retirement of debt		$8,358		$4,468		3,890	(87.1)	%

DGO's finance costs include interest expense on borrowings and non-cash amortisation of deferred financing costs. Interest expense on borrowings of $15.4 million in 2018 increased by $11.7 million compared to $3.8 million in 2017 primarily due to the increase in borrowings used to fund the Company's previously mentioned acquisitions.

In March 2018, the Company closed a new $500 million five year credit facility, initially subject to a borrowing limit of $140 million that stepped up within the same month to $200 million following the closing of the acquisition of certain assets of CNX.

In July 2018 and in conjunction with the acquisition of certain assets of EQT, the Company closed on an enlarged $1 billion, five-year secured revolving credit facility with an initial borrowing base of $600 million, which replaced the existing $500 million facility.

In December 2018 and following the October 2018 acquisition of Core, the Company closed on a further-enlarged $1.5 billion, five-year senior secured credit facility with an initial borrowing base of $725 million, and which replaced the $1 billion facility and fully extinguished Core's facility assumed as part of that acquisition. The facility maintains the July 2023 maturity date of the replaced facility, and has an initial interest rate of 2.75% plus the one-month LIBOR and is subject to a grid that fluctuates from 2.25% to 3.25% plus LIBOR based on utilisation.

In June 2017, the Company closed a new $110.0 million senior secured credit facility, of which, $64.0 million was drawn at closing of the Titan acquisition on 30 June 2017 and a subsequent draw of $11.0 million on 30 September 2017, to partially fund the purchase of oil and gas assets.

As discussed above, DGO entered into the new senior secured revolving credit, in March 2018 that resulted in a non-recurring loss on early extinguishment of debt of $8.4 million, which primarily included a $2.6 million charge for the accelerated amortisation of the remaining deferred financing costs and $5.8 million related to an early payment fee.

In 1H17 and using the proceeds from our successful AIM IPO, DGO repaid its publicly traded bonds and other outstanding debt. Accordingly, DGO incurred a non-recurring loss on the early extinguishment of debt, which primarily included a $3.8 million charge for the accelerated amortisation of the remaining deferred financing costs and $0.6 million in premiums paid to redeem convertible bonds prior to DGO's admission to AIM.

For more information on DGO's acquisitions and borrowings, refer to Notes 2 below and 11 below, respectively.

Income before taxation, EPS and Adjusted EBITDA

DGO reported income before taxation of $261.7 million in 2018 compared to $29.7 million in 2017, an increase of 781%, and reported statutory earnings for 2018 per diluted ordinary share of $0.52 compared to $0.23 per diluted ordinary share in 2017. Adjusted for certain non-cash items such as gains on bargain purchases and similar items, DGO reported adjusted EBITDA per diluted ordinary share of $0.38 per diluted ordinary share, a 159% increase over the prior year's $0.15 adjusted EBITDA per diluted ordinary share. DGO's adjusted EBITDA for 2018 was $146.2 million, a 734% increase over $17.5 million in 2017. Refer to Note 5 for additional information regarding DGO's adjusted EBITDA.

Conclusion

All that remains is for me to thank the team of dedicated and talented employees, including those who have been with us since our humble beginnings in 2001 and those more recently joining the team through acquisitions, for their diligent commitment throughout the year. We are on an incredibly exciting journey and it would not be possible without the hard work and innovation that they all contribute on a daily basis. I would also like to thank the Board of Directors for their leadership, insights and commitment always aimed at making DGO better for the benefit of our shareholders and employees. I am very proud of the success that we have delivered to date, and have full faith in our talented team to maintain the momentum of the business and continued execution of our strategies.

Rusty Hutson Jr.

Chief Executive Officer

Basis of preparation

The consolidated financial statements have been prepared on the going concern basis and in accordance with International Financial Reporting Standards ("IFRSs") as adopted for use in the EU and those parts of the Companies Act 2006 applicable to companies reporting under IFRS.

The consolidated financial statements have been prepared on the basis of the accounting policies set out in the financial statements of Diversified Gas & Oil Plc for the year ended 31 December 2018. Accounting policies have been consistently applied.

The financial information set out in this document does not constitute the statutory accounts of DGO for the years ended 31 December 2018 and 31 December 2017 but is derived from the 2018 annual report and financial statements. The annual report and financial statements for 2017, which were prepared under IFRS, have been delivered to the Registrar of Companies and the Group's annual report and financial statements for 2018, prepared under IFRS, will be delivered to the Registrar of Companies in due course. The Group's external auditors Crowe U.K. LLP have reported on these accounts and have given an unqualified report which does not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

During the period ended 30 June 2018, DGO finalized the fair value measurement related to the previously reported EnerVest and Titan acquisitions. As a result, DGO retrospectively adjusted previously reported provisional amounts related to the EnerVest and Titan Energy acquisitions in accordance with IFRS 3. For the year ended 31 December 2017 the cumulative impact of these adjustments resulted in an $18,579 increase to the Consolidated Statements of Changes in Equity through retained earnings and did not impact net cash provided by operating activities on the Consolidated Statements of Cash Flow.

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard will supersede all current revenue recognition requirements under IFRS when it becomes effective. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoptions.

The Company adopted the new standard on 1 January 2018 using the modified retrospective method at the date of adoption. The adoption of IFRS 15 is not expected to have a material quantitative impact on the Company's financial results and no adjustment arose on transition. There were no contractual arrangements with customers giving rise to material deferred revenues at 1 January 2018 or 31 December 2018.

In July 2014, the IASB issued IFRS 9 Financial Instruments that replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. IFRS 9 incorporates the three aspects of the accounting for financial instruments: classification and measurement; impairment; and hedge accounting. Financial assets are classified as trading activities (assets that are held for collection of contractual trading and are measured at amortised cost) or financial assets held for future sale (assets that are held for collection of contractual cash flows and are measured at fair value through other comprehensive income). DGO adopted the new standard on 1 January 2018. DGO applied the simplified approach permitted by IFRS 9 for trade receivables, which requires expected lifetime losses to be recognised from initial recognition of the receivables. DGO's financial liabilities are initially measured at fair value and subsequently measured at amortised cost. DGO is not a financial institution and does not apply hedge accounting. Its customers are considered creditworthy and pay consistently within agreed payments terms. As such, other than disclosures, this standard will not have a material impact on its financial statements.

In January 2016, the IASB issued IFRS 16 Leases. The standard establishes the principles for the recognition, measurement, presentation and disclosure of leases for both the lessee and lessor. The standard requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities, and to depreciate lease assets separately from interest on lease liabilities in the income statement. IFRS 16 replaces the previous lease standard, IAS 17 Leases, and related interpretations. This standard will be effective on 1 January 2019. The Company does not expect the adoption of this standard will have a material impact on its financial statements.

Consolidated Statements of Profit or Loss and Other Comprehensive Income

(Amounts in thousands, except per-share amounts)

					(Restated)
		Audited			Audited
		Year ended			Year ended
	Note	31 December 2018			31 December 2017

Revenue	3	$	289,769		$	41,777

Operating expense	4	(107,793		)	(20,908		)
Depreciation and depletion	4	(41,988		)	(7,536		)
Gross profit		$	139,988		$	13,333

Administrative expenses	4	$	(40,524	)	$	(8,919	)
Gain on oil and gas programme and equipment		4,079			95
Gain (loss) on derivative financial instruments	12	17,981			(441		)
Gain on bargain purchase	2	173,473			37,093
Operating profit		$	294,997		$	41,161

Finance costs	11	$	(17,743	)	$	(5,225	)
(Loss) gain on early retirement of debt	11	(8,358		)	(4,468		)
Accretion of asset retirement obligation	10	(7,101		)	(1,764		)
Income before taxation		$	261,795		$	29,704

Taxation on income	6	(60,676		)	(2,250		)

Income after taxation available to ordinary shareholders		$	201,119		$	27,454

Other comprehensive income - gain on foreign currency conversion		1			355

Total comprehensive income for the year		$	201,120		$	27,809

Earnings per ordinary share - basic & diluted	7	$	0.52		$	0.23

Weighted average ordinary shares outstanding - basic	7	386,559			120,136

Weighted average ordinary shares outstanding - diluted	7	387,925			120,269

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

Consolidated Statements of Financial Position

(Amounts in thousands)

					(Restated)
		Audited			Audited
	Note	31 December 2018			31 December 2017
ASSETS
Non-current assets
Oil and gas properties, net		$	1,092,951		$	215,325
Property and equipment, net		324,766			6,947
Other non-current assets		25,526			1,036
Indemnification receivable		2,133			-
Total non-current assets		$	1,445,376		$	223,308

Current assets
Trade receivables		$	78,451		$	13,917
Other current assets		30,043			513
Cash and cash equivalents		1,372			15,168
Restricted cash		1,730			744
Total current assets		$	111,596		$	30,342

Total Assets		$	1,556,972		$	253,650

EQUITY AND LIABILITIES
Shareholders' equity
Share capital		$	7,346		1,940
Share premium		540,655			76,026
Merger reserve		(478		)	(478		)

Share based payment reserve		842		59
Retained earnings		200,498		30,691
Total Equity		$	748,863	$	108,238

Non-current liabilities
Asset retirement obligation	10	$	140,190	$	35,448
Capital lease		2,694		836
Borrowings	11	482,528		70,619
Deferred tax liability	6	95,033		17,399
Other non-current liabilities		21,219		5,764
Uncertain tax position		2,133		-
Total non-current liabilities		$	743,797	$	130,066

Current liabilities
Trade and other payables		$	9,383	$	2,132
Borrowings	11	286		373
Capital lease		842		324
Other current liabilities		53,801		12,517
Total current liabilities		$	64,312	$	15,346

Total Liabilities		$	808,109	$	145,412

Total Equity and Liabilities		$	1,556,972	$	253,650

Consolidated Statements of Changes in Equity

(Amounts in thousands)

									Share
									Based
		Share		Share		Merger			Payment		Retained		Total
	Note	Capital		Premium		Reserve			Reserve		Earnings		Equity
Balance at 1 January 2018		$	1,940	$	76,026	$	(478	)	$	59	$	30,691	$	108,238

Income after taxation		-		-		-			-		201,119		201,119
Gain on foreign currency conversion		-		-		-			-		1		1
Total comprehensive income		-		-		-			-		201,120		201,120

Issuance of share capital, initial offering		-			-			-				-			-				-
Issuance of share capital, secondary offering		5,406			464,629			-				-			-				470,035
Equity compensation		-			-			-				783			-				783
Dividends authorised and declared	8	-			-			-				-			(31,313		)		(31,313		)
Transactions with shareholders		5,406			464,629			-				783			(31,313		)		439,505

Balance at 31 December 2018		$	7,346		$	540,655		$	(478	)		$	842		$	200,498			$	748,863

												Share
												Based
		Share			Share			Merger				Payment			Retained				Total
		Capital			Premium			Reserve				Reserve			Earnings				Equity
Balance at 1 January 2017		$	669		$	313		$	(478	)		$	-		$	8,658			$	9,162

Income after taxation (as restated)		-			-			-				-			27,454				27,454
Gain on foreign currency conversion		-			-			-				-			355				355
Total comprehensive income		-			-			-				-			27,809				27,809

Issuance of share capital, initial offering		768			43,550			-				-			-				44,318
Issuance of share capital, secondary offering		503			32,163			-				-			-				32,666
Equity compensation		-			-			-				59			-				59
Dividends authorised and declared		-			-			-				-			(5,776		)		(5,776		)
Transactions with shareholders		1,271			75,713			-				59			(5,776		)		71,267

Balance at 31 December 2017		$	1,940	-	$	76,026	-	$	(478	)	-	$	59	-	$	30,691		-	$	108,238

Consolidated Statements of Cash Flow

(Amounts in thousands)

					(Restated)
					Year ended
	Note	31 December 2018			31 December 2017
Cash flows from operating activities
Income after taxation		$	201,119		$	27,454
Cash flow from operations reconciliation:
Depreciation and depletion		41,988			7,536
Accretion of asset retirement obligation	10	7,101			1,764
Income tax charge	6	60,676			2,250
Provision for working interest owners receivable		-			632
(Gain)/loss on derivative financial instruments	12	(32,768		)	1,965

Gain on oil and gas programme and equipment		(4,079		)	(396		)
Gain on bargain purchase	2	(173,473		)	(37,093		)
Finance costs	11	17,743			4,510
Loss on early retirement of debt		8,358			-
Gain on disposal of property and equipment		-			95
Non-cash equity compensation		783			59
Working capital adjustments:
Change in trade receivables		(41,225		)	(11,464		)
Change in other current assets		(6,286		)	798
Change in other assets		(1,732		)	(38		)
Change in trade and other payables		1,134			(2,495		)
Change in other current and non-current liabilities		8,396			11,345
Net cash provided by operating activities		$	87,735		$	6,922
Cash flows from investing activities
Business combinations net of cash acquired	2	(750,256		)	(89,785		)
Expenditures on oil and gas properties and equipment		(18,515		)	(2,935		)
Asset retirement, plugging		(1,171		)	(78		)
Increase in restricted cash		(986		)	(627		)
Proceeds on disposal of oil and gas properties		4,079			334
Net cash used in investing activities		$	(766,849	)	$	(93,091	)
Cash flows from financing activities
Repayment of borrowings	11	(280,890		)	(42,514)
Proceeds from borrowings	11	581,221			75,000
Financing expense		(15,433		)	(3,298		)
Cost incurred to secure financing		(17,176)			-
Proceeds from capital lease		4,401			1,246
Repayment of capital lease		(1,093		)	(529		)
Proceeds from equity issuance, net		425,601			76,984
Dividends to shareholders		(31,313		)	(5,776		)
Net cash provided by financing activities		$	665,318		$	101,113
Net (decrease) increase in cash and cash equivalents		(13,796		)	14,944
Cash and cash equivalents - beginning of the period		15,168			224
Cash and cash equivalents - end of the period		$	1,372		$	15,168

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 - Significant Accounting Judgments, Estimates and Assumptions

DGO has made the following judgments which may have a significant effect on the amounts recognised in the consolidated audited financial information:

Valuation of intangible oil and gas assets on acquisition

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

Impairment indicators for oil and gas properties

Following a review by the Management of ongoing operational performance of DGO's natural gas and crude oil properties for the year ended 31 December 2018, Management is of the opinion that no impairment indicators are apparent for these assets.

Reserve estimates

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

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

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

Asset retirement obligation costs

The ultimate asset retirement obligation costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, significant estimates and assumptions are made in determining the provision for asset retirement obligations. See Note 10 for more information.

Note 2 - 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 Company accounts for business acquisition under IFRS 3. Where practical to do so the contribution arising from acquisitions up to the reporting date is disclosed. The acquisitions gave rise to bargain purchases due to the prevailing market conditions in the Appalachian Basin, the context of global oil and gas prices, the financial condition of the sellers, and a change in the operational focus of the sellers compelling these sellers to divest of their conventional oil and gas assets.

2018 Acquisitions

Acquisition of the stock of Alliance Petroleum Corporation

In March 2018, DGO acquired the entire share capital of Alliance Petroleum Corporation, including approximately 13,000 conventional natural gas and oil wells in the states of Pennsylvania, West Virginia and Ohio and all other property and equipment. The Company paid consideration of $80,743, excluding customary purchase price adjustments. The Company funded the cash consideration for the purchase with the net proceeds from its equity placing of DGO's stock in February 2018.

Management determined the fair value of the reserves held in the assets acquired to be $129,125, which was approximately 9% cumulative discount reserve valuation derived from a third party engineer at the time of purchase. The provisional estimated fair values of the assets and liabilities assumed were as follows:

Total cash consideration	$	80,743
Less cash received	(8,638		)
Cash consideration, net of cash received	$	72,105

Net Assets Acquired:
Current assets		$	13,403
Oil and gas properties, net		129,125
Property and equipment, net		2,444
Other assets	(a)	2,133
Current liabilities		(7,576		)
Deferred tax liability		(19,852		)
Uncertain tax position	(a)	(2,133		)
Debt	(b)	(25,000		)
Other liabilities		(119		)
Asset retirement obligation		(20,153		)
Net assets acquired		72,272

Gain on bargain purchase		(167		)
Purchase Price		$	72,105

(a) At the date of acquisition DGO determined the Alliance Petroleum Corporation had taken uncertain tax positions, and as a result, an indemnification agreement was executed. DGO recorded an indemnification receivable in the amount of $2,133. In accordance with IFRS 3, DGO 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.

(b) On the date of acquisition DGO repaid the debt in full using proceeds from the February 2018 equity placing.

Acquisition of assets from CNX Resources LLC

In March 2018, DGO acquired approximately 11,000 conventional natural gas and oil wells principally in the states of Pennsylvania and West Virginia and other equipment from CNX Resources LLC ("CNX"). The Company paid purchase consideration of $89,296, excluding customary purchase price adjustments. The Company funded the cash consideration for the purchase with the proceeds from its equity placing of DGO's stock in February 2018. Subsequent to the purchase of these assets, CNX agreed to retain a monthly tariff obligation applicable to the Appalachian assets that requires monthly cash payments to a pipeline transmission company through a portion of calendar year 2022. Tariff payments from the effective date of the purchase through their expiration in 2022 totaled $27,000. In exchange for CNX retaining this $27,000 pipeline tariff obligation, the Company paid CNX $17,000. This one-time payment allows DGO to retain complete and uninterrupted access to the applicable pipeline system and eliminates the $27,000 tariffs the Company would have paid over the remaining term.

Management determined the fair value of the reserves held in the assets acquired to be $130,500, which was approximately 9% cumulative cash flow discount reserve derived from a third-party engineer at the time of purchase. The provisional estimated fair values of the assets and liabilities assumed were as follows:

Oil and gas properties	$	130,500
Oil and gas properties (asset retirement obligation, asset portion)	14,332
Asset retirement obligation	(14,332		)
Other liabilities	(4,790		)
Gain on bargain purchase	(36,414		)
Purchase price	$	89,296

Acquisition of assets from EQT Production Company

In July 2018, DGO acquired approximately 11,250 conventional natural gas wells and a wholly-owned midstream gathering and a compression system with approximately 6,400 miles of pipeline and 59 compressor stations in the states of Kentucky, West Virginia and Virginia and other equipment from EQT Production Company ("EQT"). The Company paid purchase consideration of $527,158, excluding customary purchase price adjustments. The Company funded the cash consideration for the purchase with the proceeds from its equity placing of stock in July 2018 and a draw of $336,200 from the debt facility discussed in Note 11. At the time of acquisition DGO engaged a third party valuation firm to further substantiate management's valuation assumptions. As a result of this valuation, the fair value of the reserves held in the assets acquired was $363,300, which was derived using a cumulative discount rate of 10.5%. The tangible assets acquired were determined to have a fair value of $237,894, which was derived using a cumulative discount rate of 9.5%. The provisional estimated fair values of the assets and liabilities assumed were as follows:

Oil and gas properties	$	363,300
Oil and gas properties (asset retirement obligation, asset portion)	26,257
Pipelines	205,810
Compressors	46,634
Mobile Equipment	8,562
Rights of Way	3,250
Buildings	620
Land	2,420
Inventory	5,047
Asset retirement obligation	(26,257		)
Suspense	(4,764		)
Other	(3,428		)
Gain on bargain purchase	(100,293		)
Purchase price	$	527,158

Acquisition of the stock of Core Appalachia Holding Co, LLC

In October 2018, DGO acquired Core Appalachia Holding Co, LLC ("Core"), which included approximately 5,000 conventional natural gas wells and a wholly-owned midstream gathering and compression system with approximately 4,100 miles of pipeline and 47,000 horsepower of compression in the states of Kentucky, West Virginia and Virginia. The Company funded the acquisition with $40,000 of cash and 35,000 shares of common stock (at an assumed offering price of $1.41 per share (1.07 pence), which was the last reported sale price of our common stock on the acquisition date). At the time of acquisition DGO engaged a third party valuation firm to further substantiate management's valuation assumptions. As a result of this valuation, the fair value of the reserves held in the assets acquired was $176,860, which was derived using a cumulative discount rate of 10.5%. The tangible assets acquired were determined to have a fair value of $48,812 which was derived using a cumulative discount rate of 9% The provisional estimated fair values of the assets and liabilities assumed were as follows:

Cash consideration	$	45,938
Less cash received	(4,454		)
Fair value of stock consideration	49,159
Total consideration	$	90,643

Net assets acquired:
Oil and gas properties	$	176,860
Oil and gas properties (asset retirement obligation, asset portion)	19,214
Pipelines	27,797
Compressors	6,401
Mobile Equipment	4,206
Buildings	3,880
Land	6,440
Other	88
Accounts receivable	11,506
Other current assets	3,754
Other long term assets	6,617

Asset retirement obligation	(19,214		)
Accounts payable	(5,586		)
Taxes payable	(7,020		)
Notes payable assumed	(93,246		)
Other current liabilities	(12,259		)
Other long term liabilities	(1,898		)
	$	127,540

Gain on bargain purchase	(36,897)
Purchase price	$	90,643

Other Acquisitions

In July 2018, DGO purchased for $20,212 additional working interest in certain wells it already operated. These assets were previously held in seven limited partnerships with working interest ranges from 54% to 82% to which the Company served as the managing general partner. The Company funded the cash consideration for the purchase with a draw on its debt facility.

2017 Acquisitions (Restated)

EnerVest Acquisition

In April 2017, DGO acquired approximately 1,300 conventional natural gas and oil wells in Ohio and equipment from EnerVest. The Company paid in cash the consideration totalling $1,750. Management considered the fair value of the reserves held in the assets acquired to be $8,500, which was the 30% cumulative cash flow discount reserve valuation derived from a third-party engineer at the time of purchase. During 2018, DGO finalised the fair value measurement of the EnerVest acquisition. As a result, DGO retrospectively adjusted previously reported provisional amounts related to the acquisition in accordance with IFRS 3. The fair values of the assets and liabilities assumed were as follows:

		(Restated)
Oil and gas properties	$	8,500
Oil and gas properties (asset retirement obligation, asset portion)	2,406
Asset retirement obligation	(2,406		)
Gain on bargain purchase	(6,750		)
Purchase price	$	1,750

Titan Energy Acquisition

In June 2017, DGO acquired approximately 8,380 producing conventional natural gas and oil wells in the states of Pennsylvania, Ohio, and Tennessee (including approximately 1,140 non-operated wells) and equipment from Titan Energy. The Company paid total consideration of $77,343, excluding customary purchase price adjustments. The cash consideration for the purchase was funded by a $110,000 Senior Secured Loan Facility, of which, $64,000 was drawn at closing on 30 June 2017, and an equity placing of DGO's stock. DGO placed 39,300 new ordinary shares at $0.89 per share with certain existing and new institutional investors to raise $35,020. The equity placing occurred in two tranches of 11,400 shares which raised $10,158 and 27,900 shares were placed with the second tranche, which raised $24,862. During 2018, DGO finalised the fair value measurement of the Titan Energy acquisition. As a result, DGO retrospectively adjusted previously reported provisional amounts related to the acquisition in accordance with IFRS 3.

Management determined the fair value of the reserves held in the assets acquired on 30 June 2017 to be $108,011. The fair values of the assets and liabilities assumed were as follows:

		(Restated)
Oil and gas properties	$	108,011
Oil and gas properties (asset retirement obligation, asset portion)	16,366

Other PPE	1,752
Asset retirement obligation	(16,366		)
Other liabilities	(2,279		)
Gain on bargain purchase	(30,141		)
Purchase price	$	77,343

NGO Acquisition

In November 2017, DGO acquired approximately 550 wells in Central Ohio from NGO Development Corporation, Inc. The Company paid cash consideration totalling $3,114. Management determined the fair value of the reserves held in the assets acquired to be $3,003, which was approximately 25% cumulative cash flow discount reserve valuation derived from a third-party engineer at the time of purchase. The fair values of the assets and liabilities assumed were as follows:

		(Restated)
Oil and gas properties	$	3,003
Oil and gas properties (asset retirement obligation, asset portion)	818
Other PPE	352
Asset retirement obligation	(818		)
Other liabilities	(39		)
Gain on bargain purchase	(202		)
Purchase price	$	3,114

Note 3 - Revenue

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

			(Restated)
	Year ended		Year ended
	31 December 2018		31 December 2017

Natural gas	$	219,189	$	30,463
Oil	19,117		8,047
NGL	41,854		1,043
Total natural gas, oil and NGL	$	280,160	$	39,553
Midstream revenue	7,315		-
Other	2,294		2,224
Total revenue	$	289,769	$	41,777

DGO adopted IFRS 15 Revenue from Contracts with Customers 1 January 2018 using the modified retrospective method at the date of adoption. During the year ended 31 December 2018, DGO derived approximately 97% of its revenues from the sale of natural gas, NGLs and crude oil. Revenue from those sales is recognised when the product is physically transferred into a vessel, pipe, sales meter or other delivery mechanism. Contracts with customers for the sale, gathering and transportation of natural gas, NGLs and crude oil are predominantly of a short duration and have specific outcomes and performance obligations.

A significant portion of DGO's trade receivables represent receivables related to either sales of oil, natural gas, NGL or operational services. Oil, natural gas, and NGL trade receivables are generally uncollateralised.

During the year ended 31 December 2018, two customers individually totalled more than 10% of total revenues, totalling 24% and 18%. For the year ended 31 December 2017, two customers individually totalled more than 10% of total revenues, totalling 25%, and 17%. Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production.

Note 4 - Expenses by Nature

The following table provides a detail of the Company's expenses:

		(Restated) Year ended
	Explanation	31 December 2018		31 December 2017

Employees and benefits		$	35,061	$	8,539
Automobile		5,569		1,441
Insurance		4,698		491
Transportation		10,221		-
Production taxes (severance taxes, property taxes and other taxes)		11,978		1,345
Gathering and compression		9,186		2,712
Well operating expenses, net		31,080		6,380
Total operating expense	(a)	$	107,793	$	20,908

Depreciation		$	10,272	$	1,469
Depletion		31,716		6,067
Total depreciation and depletion		$	41,988	$	7,536

Employees and benefits		$	12,653	$	2,655
Other administrative		1,834		1,611
Professional fees		5,070		360
Auditors' remuneration
Fees payable to the Company's auditor for the audit of the group and Company's annual accounts		95		55
Fees payable to the Company's auditor and its associates for other services:
Audit of the accounts of subsidiaries		310		125
Corporate finance services		142		73
Total auditors' remuneration		$	547	$	253
Recurring administrative expenses		$	20,104	$	4,879
Non-recurring costs associated with acquisitions & contribution of assets		19,637		3,349
Provision for working interest owners receivable		-		632
Non-cash equity compensation	(b)	783		59
Non-recurring administrative expenses		$	20,420	$	4,040
Total administrative expenses	(a)	$	40,524	$	8,919

Total expenses	(a)	$	190,305	$	37,363

Aggregate remuneration (including Directors):
Wages and salaries		$	30,238	$	8,272
Payroll taxes		1,972		729
Benefits		4,323		2,252
Total employees and benefits expense	(a)	$	36,533	$	11,253

a)		The increase in expenses is primarily related to the oil and gas properties and midstream assets acquired during 2018. See Note 2 for more information about the Company's acquisitions.

b)		Non-cash equity issuance in 2018 and 2017 reflects the expense recognition related to the issuance of restricted stock units to certain key managers.

For the years 31 December 2018 and 31 December 2017, DGO's average workforce was comprised of approximately 600 and 209 employees, respectively. For the year ended 31 December 2018, DGO employed an average of 112 employees in administrative, which is inclusive of management, and an average of 488 employees in field operations. For the year ended 31 December 2017, DGO employed an average of 34 employees in administration, which is inclusive of management, and an average of 175 employees in field operations.

Certain prior period amounts have been reclassified to conform with current presentation.

Note 5 - Adjusted EBITDA

Adjusted EBITDA is a non-IFRS financial measure, which is of particular interest to the industry and Management, as it is essentially the cash generated from operations that DGO has free for interest payments and capital investment. Adjusted EBITDA should not be considered as an alternative to operating profit (loss), comprehensive income, cash flow from operating activities or any other financial performance or liquidity measure presented in accordance with IFRS. Adjusted EBITDA is a non-IFRS financial measure that is defined as operating profit plus or minus items detailed below in the table below.

The Company believes Adjusted EBITDA is a useful measure because it enables a more effective way to evaluate operating performance and compare the results of operations from period-to-period and against its peers without regard to DGO's financing methods or capital structure. The Company excludes the items listed in the table below from operating profit in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

The following table reconciles operating profit to Adjusted EBITDA:

	Year ended
	31 December 2018			31 December 2017

Operating profit	$	294,997		$	41,161

Depreciation and depletion	41,988			7,536
Gain on bargain purchase	(173,473		)	(37,093		)
Gain on oil and gas programme and equipment	(4,079		)	(95		)
(Gain) loss on derivative financial instruments	(33,636		)	1,965
Non-recurring costs associated with acquisitions & contribution of assets	19,637			3,349
Provision for working interest owners receivable	-			632
Non-cash equity issuance included in administrative expense	738			59
Total adjustments	(148,825		)	(23,647		)

Adjusted EBITDA	$	146,172		$	17,514

Weighted average ordinary shares outstanding - basic	386,559			120,136
Weighted average ordinary shares outstanding - diluted	387,925			120,269

Adjusted EBITDA per share - basic and diluted	$	0.38		$	0.15

Note 6 - Taxation

For taxable year ending 31 December 2016, all DGO subsidiaries lost their pass-through tax status, are subject to U.S. federal and state income tax and began filing a consolidated U.S. federal and state income tax returns and several separate state income tax returns. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes related to differences between the basis of assets and liabilities for financial and income tax reporting.

For taxable year ending 31 December 2018 and 2017, DGO had tax expenses of $60,676 and $2,251, respectively. The Company's effective tax rate was 23.20% and 7.50%, respectively, for the same periods. The effective tax rate is primarily impacted by recognition of federal tax credits, and also is impacted by recurring permanent differences, such as meals and entertainment, state taxes, and other deferred tax, as the Company is currently generating operating losses for United States taxation purposes.

The provision for income taxes for the years ended 31 December 2018 and 31 December 2017 in the Statements of Comprehensive Income are summarised below:

			Year ended
	31 December 2018		31 December 2017
Current income tax expense
Federal	$	-	$	-
State	2,894		-
Total current income tax expense	$	2,894	$	-

Deferred income tax (benefit) expense
Federal	$	47,554	$	883
State	10,228		1,367
Total deferred income tax (benefit) expense	$	57,782	$	2,250

Total income tax (benefit)	$	60,676	$	2,250

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

Expected tax at U.S. statutory income tax rate	$	54,954		21.0	%
Increase (decrease) in tax resulting from:
State income taxes, net of federal tax benefit	12,515			4.7	8%
Federal credits	(7,084		)	(2.7	)%
Other - net	291			0.1	%
Total taxation on income	$	60,676		23.12	%

The Company had a net deferred tax liability of $95,033 and $17,399 as of 31 December 2018 and 31 December 2017, respectively. The deferred tax liability increased by $77,633, primarily due to 2018 acquisitions whereby bargain purchase gains were recorded for financial reporting purposes but not for tax purposes and immediate expensing for tax purposes of purchase consideration assigned to tangible property acquired. Additionally, the net deferred tax liability increased due to unrealised gains for unsettled derivatives and decreased due to an increase of Federal net operating loss generated.

The components of the net deferred tax liability included in non-current liabilities are as follows:


	Year ended		Year ended
	31 December 2018		31 December 2017
Deferred tax assets
Asset retirement obligation asset	$	46,893	$	9,133
Derivative adjustment	-		742
Allowance for doubtful accounts	577		166
Federal net operating loss	53,904		1,056

State net operating loss	3,177			216
Federal tax credits carryover	14,365			250
Capital loss carryover	1,988
Valuation allowance	(1,988		)
Other	1,334			83
Total deferred tax assets	$	120,250		$	11,646
Deferred tax liabilities
Premises, equipment and oil and gas properties	$	(206,795	)	$	(29,045	)
Derivative adjustment	(8,488		)	-
Total deferred tax liabilities	(215,283		)	(29,045		)
Net deferred tax liability	$	(95,033	)	$	(17,399	)

For U.S. federal tax purposes, DGO is taxed as one consolidated entity, which includes its parent company, PLC. PLC is subject to additional taxes in its home jurisdiction of the United Kingdom. For the years ended 31 December 2018 and 31 December 2017, PLC did not incur any income tax liability in the United Kingdom.

On 22 December 2017, the President of the United States signed into law the Tax Cuts and Jobs Act ("TCJA") tax reform legislation. This legislation makes significant change in U.S. tax law including a reduction in the corporate tax rates, changes to net operating loss carryforwards and carrybacks, and a repeal of the corporate AMT. The legislation reduced the U.S. corporate tax rate from the current rate of 34% to 21% for the year ended December 31, 2018. As a result of the enacted law, the Company is required to revalue deferred tax assets and liabilities at 22 December 2017. The revaluation of deferred taxes for the rate reduction resulted in $8,525 of benefit to income tax expense for the year ended 31 December 2017. The other provisions of the TCJA are not expected to have a material impact on the Company's consolidated financial statements in future years. The other provisions of the TCJA are not expected to have a material impact on the Company's consolidated financial statements in future years.

At 31 December 2018, the Company had federal net operating loss carryforwards of approximately $256,70. Federal net operating loss carryforwards of $5.9 million expire in the years 2035 through 2037. The Federal net operating loss carryforward of $250,800 generated in the year ended 31 December 2018 does not have an expiration date as a result of the 22 December 2017 tax law changes discussed above. Additionally, the Company has state net operating loss carryforwards of approximately $62,700, which expire in the years 2036 through 2038.

At 31 December 2018, the Company had federal marginal well tax credit carryforwards of approximately $14,300 , which expire in the years 2036 through 2037.

During 2018, the Company completed a Section 382 study in accordance with the Internal Revenue Code of 1986, as amended. The study concluded that the Company has experienced ownership changes as defined by Section 382 on 3 February 2017 and on 6 March 2018. This causes the Company's utilisation of its net operating loss and tax credit carryforwards to be subject to annual limitations. The Company expects its net operating loss carryforwards to be fully available for utilisation by 31 December 2019 and tax credit carryforwards to be fully available for utilisation by 2024. The Company's ability to utilise its federal and state net operating loss and tax credit carryforwards may be further limited as a result of subsequent ownership changes. All such limitations could result in the expiration of carryforwards before they are utilised.

Note 7 - Earnings Per Share

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

	Year ended
Calculation	31 December 2018	31 December 2017

Income after taxation available to ordinary shareholders	A	$	201,119	$	27,454

Weighted average ordinary shares outstanding - basic	B	386,559		120,136
Weighted average ordinary shares outstanding - diluted	C	387,925		120,269

Earnings per ordinary share - basic	= A/B	$	0.52	$	0.23

Earnings per ordinary share - diluted	= A/C	$	0.52	$	0.23

Adjusted EBITDA per ordinary share - basic & diluted	Note 5	$	0.38	$	0.15

Note 8 - Dividends

The following table summarises the Company's dividends paid and declared:

	Dividend per Ordinary Share
Date Declared	USD	GBP	Record Date	Pay Date	Shares Outstanding	Gross Dividends Paid $'000
Dividend declared 15 June 2017	0.0199	0.0155	07 July 2017	31 July 2017	145,076	$	2,888
Dividend declared 11 September 2017	0.0199	0.0149	17 November 2017	20 December 2017	145,076	2,888
Cumulative dividends declared as at for the year ended 31 December 2017						$	5,776

Dividend declared 30 April 2018	0.0345	0.0251	11 May 2018	25 May 2018	311,476	$	10,746
Dividend declared 29 June 2018	0.0173	0.0131	13 July 2018	24 September 2018	311,476	5,373
Dividend declared 11 September 2018	0.0280	0.0223	30 November 2018	19 December 2018	542,633	15,194
Dividends paid during the year ended 31 December 2018						31,313
Cumulative dividends declared for the year ended 31 December 2018						37,089
Cumulative dividends declared as at for the year ended 31 December 2018						$	37,089

Dividend declared 14 December 2018	0.0330	Pending	8 March 2019	29 March 2019	Pending	Pending

Note 9 - Oil and Gas Properties

The following table summarizes the Company's oil and gas properties for each of the periods presented:

	Costs				Depletion and Impairment
Period	Beginning Balance	Additions	Disposals	Ending Balance		Beginning Balance	Period Charges	Disposals	Ending Balance	Net Book Value
As at and for the year ended 31 December 2018	$239,814	908,514	(93)	$1,148,235		$(24,489)	$(30,795)	-	$(55,284)	$1,092,951
As at and for the year ended 31 December 2017	$94,608	145,527	(321)	$239,814		$(17,815)	$(6,674)	-	$(24,489)	$215,325

See Note 2 for more information about the Company's acquisitions.

Note 10 - Asset Retirement Obligation

The Company records a liability for future cost of asset retirement production facilities and pipelines. The asset retirement obligation liability represents the present value of asset retirement costs relating to oil and gas properties, which the Company expects to incur over the long producing life of its wells, presently estimated through to 2093 when the Company expects its producing oil and gas properties to reach the end of their economic lives.

These liabilities represent Management's best estimates of the future obligation. Management's assumptions are based on the current economic environment, and represent what they believe is a reasonable basis upon which to estimate the future liability. Management reviews these estimates regularly and adjust for any identified material changes to the assumptions. However, actual asset retirement costs will ultimately depend upon future market prices at the time the asset retirement services are performed. Furthermore, the timing of asset retirement 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 discount rate and the cost inflation rate used in the calculation of the asset retirement obligation was 8.0% as at each of the periods presented. The table below summarises the activity for the Company's asset retirement obligation:

	Year ended			Year ended
	31 December 2018			31 December 2017

Balance at 1 January	$	35,448		$	12,265
Additions (a)	96,508			21,497
Accretion	7,101			1,764
Disposals	(1,161		)	(78		)
Revisions to estimate (b)	4,829			-
Balance at 31 December	142,725			35,448
Less: Current asset retirement obligation	2,535			-
Long-term asset retirement obligation	$	140,190		35,448

a)		See Note 2 for more information about the Company's acquisitions.
b)		During the year Management revised the plugging programme to more closely align with operations. As a result of this revision, cost inputs and assumptions made surrounding the life of certain wells were amended.

Note 11 - Borrowings

DGO's borrowings consist of the following amounts for the periods presented:

	31 December 2018			31 December 2017
Individuals and institutional investor bonds, interest rate of 8.50%, maturing June 2020, unsecured	$	86		$	81
Financial institution, interest rate of 2.75% plus LIBOR (2018) and 8.25% plus LIBOR (2017), maturing July 2020, secured by oil and gas properties	495,284			73,249
Miscellaneous notes, primarily for real estate and equipment	2,337			495
Total borrowings	$	497,706		$	73,825

Less current portion of long-term debt	(286		)	(373		)
Less deferred financing costs	(15,093		)	(2,833		)
Total non-current borrowings, net	$	482,327		$	70,619

In March 2018, the Company closed a new $500,000 five year credit facility, initially subject to a borrowing limit of $140,000. Following the closing of the acquisition of certain assets of CNX Resources in March 2018, as discussed in Note 2, the borrowing limit increased to $200,000. In July 2018, in conjunction with the acquisition of certain assets of EQT, the Company closed on an enlarged $1,000,000, five-year secured revolving credit facility with an initial borrowing base of $600,000, which replaced the existing $200,000 facility. In November 2018, following the October 2018 acquisition of Core, the Company closed on a further-enlarged $1,5,000,000, five-year senior secured credit facility. The enlarged facility consolidates the Company's previous $1,000,000 facility with Core Appalachia's facility and has an initial borrowing base of $725,000. The facility maintains the maturity date of the previous $1,000,000 facility of July 2023. In December 2018, DGO extinguished $93,000 of debt assumed with the Core acquisition. The facility has an initial interest rate of 2.75% plus the one-month LIBOR and is subject to a grid that fluctuates from 2.25% to 3.25% plus LIBOR based on utilisation.

The following table provides a reconciliation of DGO's future maturities of its total borrowings for each of the periods presented:

	31 December 2018		31 December 2017
Not later than one year	$	286	$	373
Later than one year and not later than five years	497,420		73,452
Total borrowings	$	497,706	$	73,825

Reconciliation of borrowings arising from financing activities:

	31 December 2018		31 December 2017
At the beginning of the period	$	70,992	$	37,294
Acquired as part of business combination	118,223		-
Proceeds from new borrowings	581,221		75,000
Repayments of borrowings	(275,115)		(42,514)
Financing fees paid	(17,176)		-
Amortisation of financing fees	4,812		1,212
Interest paid in cash	(15,433)		(3,298)
Deferred finance costs	15,290		3,298
At the end of the period	$	482,814	$	70,992

(a) During 2018 DGO acquired $25,000 and $93,000 of debt, respectively, from the APC and Core acquisitions discussed in Note 2. During 2018, DGO repaid $281,177 of outstanding debt, including the debt assumed through the aforementioned acquisitions, received proceeds of $581,221 and financed a $5,837 early payment fee related to the March 2018 refinancing.

Gain/Loss on Debt Extinguishment

As discussed above, DGO entered into the new senior secured revolving credit in March 2018 that resulted in a non-recurring loss on early extinguishment of debt of $8,358, which primarily included a $2,583 charge for the accelerated amortisation of the remaining deferred financing costs and $5,776 related to an early payment fee.

As discussed above, DGO entered into a new senior secured credit facility in June 2017 that resulted in a non-recurring loss on the early extinguishment of debt, which primarily included a $3,835 charge for the accelerated amortisation of the remaining deferred financing costs and $633 in premiums paid to redeem convertible bonds.

Note 12 - Derivatives

The following table summarises the Company's calculated fair value of derivative financial instruments:

(Liabilities)/Assets	31 December 2018			31 December 2017

Natural gas
Swaps	$	4,053		$	28
Collars	131			311
Basis swaps	(1,720		)	(965		)
Put options	7,292			-
Total natural gas financial derivative contracts	$	9,756		$	(626	)

Natural gas liquids
Swaps	26,208			-
Total natural gas financial derivative contracts	$	26,208		$	-

Oil
Swaps	$	676	$	(56	)
Collars	2,929		(2,222		)
Total oil financial derivative contracts	$	3,605	$	(2,278	)

Total financial derivative contracts	$	39,569	$	(2,904	)

The Company reports derivative financial instrument assets and liabilities net in its balance sheet. The following table reconciles the Company's derivative financial instrument gross assets and gross liabilities for the periods presented:

Derivative Financial	Statement of
Instruments	Financial Position line item	31 December 2018			31 December 2017

Non-current assets		$	49,854		$	1,348
Current assets		29,068			955
Total assets		$	78,922		$	2,303

Non-current liability		$	(28,109	)	$	(3,291	)
Current liabilities		(11,495		)	(1,916		)
Total liabilities		$	(39,604	)	$	(5,207	)

Net assets - non-current	Other non-current assets	$	21,746		$	(1,943	)
Net assets - current	Other current assets	17,573			(961		)
Net (liabilities)/assets		$	39,319		$	(2,904	)

The Company recorded the following gain (loss) on derivative financial instruments in the Consolidated Statements of Profit or Loss and Other Comprehensive Income for the periods presented:

	Year ended
	31 December 2018			31 December 2017

Net loss (gain) on settlements	$	15,655		$	(1,524	)
Net (gain) loss on fair value adjustments on unsettled financial instruments	(33,636		)	1,965
Total (gain) loss on derivative financial instruments	$	(17,981	)	$	441

Note 13 - Report and Accounts and Presentation

Copies of the Annual Report will be available on the Company's website, www.dgoc.com and from the Company's registered office at 27/28 Eastcastle Street, London W1W 8DH shortly. A copy of the Company's results presentation will also be available on the Company's website in due course.

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

END

FR SELSSAFUSEFE

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Diversified Energy Company (DEC)

Friday, 20th December 2024

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