Final Results

RNS Number : 4812M

Diversified Gas & Oil PLC

30 April 2018

 

30 April 2018

Diversified Gas & Oil PLC

("DGO" or the "Company")

 Final Results for the year ended 31 December 2017

Diversified Gas & Oil PLC ("DGO"), a leading independent US-based gas and oil producer focused on the Appalachian Basin, is pleased to announce the publication of its annual results for the year ended 31 December 2017.

Highlights:

•       Completion of three accretive acquisitions totalling $89 million

•       Total revenue up 144% to $41.8 million (2016: $17.1 million)

•       Adjusted EBITDA up 308% to $17.5 million (2016: $4.3 million)

•       Strong 2H17 EBITDA margins over 40%

•       Balance sheet strengthened by equity proceeds and low leverage

•       2H17 Lease Operating Expense $6.10/BOE (down 36% vs 2016 average)^(a)

•       Final dividend for 2017 of 3.45 cents per share. Total dividend for the year of 5.44 cents per share, a 173% increase on FY2016

Post-Period Highlights:

•       Completion of materially transformative acquisitions of Alliance Petroleum ($95 million) and conventional assets from CNX Resources ($85 million)

•       Net daily production up to 28 MBOE, a 170% increase from year-end 2017

•       Transformation of capital structure to strengthen balance sheet via $189 million equity raise and refinancing of debt. Leverage currently stands at ~1.2x

•       Moved to a quarterly dividend policy

•       2H17 dividend goes ex-div in 10 May 2018 and payable on 31 May 2018

 (a) Lease Operating Expense excludes uncontrollable G&T (gathering and transportation) and production taxes.

Commenting on the results, CEO Rusty Hutson said:

"Our first year as a public company can be characterised as one of remarkable success, transformation and progress.  We delivered everything we said we would do at the time of our admission to AIM in terms of growing production through acquisition and subsequently provided the Company with robust production and increasing cashflow that enables us to return cash to our shareholders as a reliable source of income through our dividend policy.

The current financial year has already delivered further material growth with the recent completion of two transformative acquisitions that increase our daily net production to c.28,000 boepd.  As a result, Diversified Gas & Oil is now the largest producer on AIM.  These acquisitions represent a material step-change in our production profile and cashflow generation, and have enabled us to reduce both the corporate and operating costs of the Company as we capitalise on the synergies provided by our expanded footprint.

Our strategic focus remains unchanged and we will continue to extract maximum value from our extensive portfolio whilst also considering the many complementary opportunities that we continue to see within our pipeline. We have successfully built a very solid growth platform and look forward to the future with confidence."

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

For further information contact:

Diversified Gas & Oil PLC Rusty Hutson Jr., Chief Executive Officer Brad Gray, Finance Director / Chief Operating Officer Eric Williams, Chief Financial Officer / Investor Relations www.dgoc.com	+001 205 408 0909
Smith & Williamson Corporate Finance Limited (Nominated Adviser) Russell Cook, Katy Birkin	[phone]
Mirabaud Securities Limited (Joint Broker) Peter Krens, Edward Haig-Thomas	[phone]
Stifel Nicolaus Europe Limited (Joint Broker)                   Callum Stewart, Nicholas Rhodes, Ashton Clanfield	[phone]
Buchanan (Financial Public Relations) Ben Romney, Chris Judd, Henry Wilson [e-mail]	[phone]

Chairman's Statement

As Chairman of DGO, I am delighted to provide this statement following a remarkable and eventful 2017.  While the global energy markets continue to rebalance, creating challenges for many traditional E&Ps, DGO flourished. Against a sector backdrop of uncertainty in which cash flow is key, our commitment to fiscal and operational discipline resonated with shareholders, including blue-chip institutional investors, who supported our successful admission to AIM in early February 2017 raising $50 million.  Quickly delivering on our stated objectives to grow our high quality, long-life, cash-flow producing asset base, DGO became the largest producer on AIM and one of the leading conventional producers in the prolific Appalachian Basin. Importantly, our shareholders participated in our success through two 2017 dividend payments totalling nearly $6 million, with a third dividend declared and payable in May 2018.

When we came to AIM, we clearly defined our long-term vision and near-term growth strategy, which centred on growing through attractively priced acquisitions near our existing assets to grow cash flow, achieve operating efficiencies, and return cash to shareholders in the form of stable dividends.  We more than doubled our production and cash flows in 2017, paid two dividends totalling nearly $6 million and continue to navigate a dynamic industry landscape that is marked for us by a robust pipeline of opportunities to grow the business in ways that are highly accretive to our shareholders. In fact, in just the first quarter of 2018, the Company has announced and closed two additional transformational acquisitions, significantly transformed our capital structure with a dramatic reduction in our borrowing costs and declared our third dividend which, on a per-share basis, is nearly 75% higher than our previous two dividends.

We have demonstrated that our strategy is effective, one that is clearly defined, contrarian to traditional E&P companies and, whilst on the face of it quite simple, requires the unique skillset, experience and discipline possessed by our Company. While most US-based operators choose to focus on costly unconventional development opportunities, we seek to leverage our relationships and operational excellence within the Appalachian Basin to capitalise on the unique window of opportunity to acquire largely conventional, long-life, producing assets at compelling valuations.  As we focus on acquisitions that produce free cash flow and complement our significant scale in the region, we can extract additional value from each acquisition through a commitment to cost discipline, reducing operating costs and extracting maximum value from all hydrocarbons that we produce.  

The Company made three acquisitions during the year: one transformational and two smaller yet synergistic bolt-on transactions.  This trebled our production, doubled our PDP reserve and materially increased our cash flow growth.  The largest, our acquisition of Appalachian gas and oil wells and related assets from Titan Energy LLC for $84 million, significantly enhanced not only our core business, but also served as an important catalyst to place DGO on the regional stage as a capable consolidator of large asset packages. Importantly, successfully completing and integrating an acquisition of this size validated to the international capital markets our business model, the capabilities of our management team and our operational excellence converting the acquisitions to dividend paying cash flows.  The acquisitions provide us with additional scale and an enhanced operational platform to deliver even more ambitious growth. 

Ultimately, we exist to create sustainable shareholder value, and we do so without placing our balance sheet at risk.  We have structured our operations to efficiently manage mature producing assets that generate significant free cash flow. Unlike other E&P companies with significant leverage and fixed-costs that require the flush production from recently completed wells to support their cost structures, DGO actively manages its operations to keep its administrative and production costs low while optimising its production with dedicated well tenders, tailoring their work to the wells' needs. This operating philosophy has enabled us to remain profitable even during this sustained period of low commodity prices.

Lower global commodity prices create unique growth opportunities for DGO since they encourage financially challenged companies to monetise assets to meet their obligations and motivate traditional onshore US E&Ps to monetise non-core or mature production assets and reinvest into unconventional drilling prospects. We are actively navigating the current environment to identify complementary acquisition opportunities within our target acquisition criteria.  

We have recently taken steps to prepare for current and future growth by reducing our cost of debt capital while also affording us the ability to fund sizable purchases with limited equity dilution. As we acquire assets, we are committed to maintaining an optimal capital structure that appropriately uses low-cost leverage to reduce dividend dilution.

Though we continue to see a large inventory of complementary acquisition opportunities within our existing geographic footprint comprised of mature, conventional wells, we also believe future mature production consolidation could materialise during which operators of mature, unconventional production may seek to monetise those assets. Further, and should commodity prices rise prompting some E&Ps to reduce the pace of asset divestitures, our large, stable production base will increase our ability to focus on organic growth across our vast acreage position and proven reserve base.

The achievement of such operational scale by the Company in the first 12 months as a public company, is a testament to our visionary Board, dedicated management team and supportive shareholder base.  Leveraging our strong reputation, our ability to access capital, and our proven ability to complete and integrate acquisitions, we seized the opportunity to acquire Alliance Petroleum Corporation ("APC") and assets from CNX Resources LLC ("CNX") in March 2018.  We were pleased to gain extraordinary support from new and existing shareholders who understood the rationale and value accretive impact of these transactions. 

Having recently completed both transactions, our net production currently stands at approximately 28kboepd from a proven and fully producing reserve base of 173 mmboe from a vast acreage position covering more than four million acres.  While growth opportunities abound, we remain vigilantly focused on the efficient integration of each acquisition, committed to achieving operating synergies from our expanded footprint.  

My friend and business partner, Rusty Hutson's great grandfather, grandfather and father invested their careers in the Appalachian oil and gas business, and so we feel a unique sense of satisfaction to see DGO thrive as we begin our second year as an AIM quoted company. I am extremely proud of what the team has accomplished and on behalf of our shareholders, I want to commend every member of our team whose exceptional talent, dedication and commitment to safety and operational excellence collectively strengthen the strong foundation of our long-term success. As we look ahead to a year already marked by significant opportunity, I have tremendous confidence in our team. Their efforts have affirmed DGO as a best-in-class Appalachian operator, one that stands ready to capitalise on an exciting set of near-term growth opportunities.

Robert M. Post

Chairman of the Board

Strategic Report

Transforming the company

Following our admission to AIM in February, 2017 proved to be a transformational year, setting us on a path that continues to deliver significant growth and shareholder value. On admission to AIM, we communicated a clear strategic vision for DGO: leverage our established position in the Appalachian Basin to capitalise on unique market conditions and acquire complementary producing assets on attractive valuation metrics to grow production and cash flow, which DGO will use to fund a consistent dividend to shareholders. Using equity raised, we completed nearly $90 million of acquisitions in 2017, which increased to nearly $270 million by the end of March 2018. Through these acquisitions, we increased our year-on-year net production by 125%, though with the addition of the Titan assets in the second half of 2017, net production increased more than 250% compared to FY2016, resulting in DGO producing an average of more than 10,400 boepd in the second half 2017. With the additional acquisitions in March 2018, net daily production is now up over 850% compared to FY2016. 

Importantly, our objective is never to grow-for-growth's sake. Instead, we maintain strict discipline as we evaluate each acquisition opportunity to ensure that, if completed, it complements our existing portfolio and generates value for the benefit of shareholders. To deliver value, we optimise the management of each well, many of which have been neglected over time by the seller. We also leverage our scale in the Appalachian Basin to achieve economies that reduce unit operating costs while, at times, increasing production from wells within the portfolio. Illustrative of our success in effecting this strategy, with the enlarged asset base from our 2017 acquisitions, we reduced our operating costs or lease operating expense (LOE) per boe by 30% to less than $7.50 per boe in the second half of 2017 vs. the FY2016 average. The effect of DGO's business model is higher profit margins driving adjusted EBITDA higher by nearly 500% in the second half of 2017 compared to the same period of 2016. Income before tax decreased by 85%. We increased our dividend per share by 73%, and we look forward to maintaining a progressive dividend policy as we grow DGO. 

Delivering on our strategic objectives

Results for the year reflect DGO's solid performance, delivering on our stated objectives and building upon our already strong platform for additional growth.  We have rapidly transformed the business to become what we believe to be a unique investment proposition on AIM: a low-risk, cash flow positive, dividend paying E&P company. The following table highlights just some of our key successes:

Stated Objective		Unit		FY2016				FY2017				% Change vs 2016FY			2H17				% Change vs 2016FY			(e) 1Q18 PF				% Change vs 2016FY
Grow through accretive acquisitions		$m		$	11.8			$	88.7			652	%		87.2				639	%		$	269			2,180	%
Increase production		MBOEPD		3.0				6.6				120	%		10.4				247	%		28.1				837	%
Increase proved reserves		MMBOE		28				55				96	%		n/a				n/a			173				518	%
Increase PV-10 reserves		$m		$	125			$	259			107	%		n/a				n/a			$	619			395	%
Increase acres held by production		MM Acres		0.8				1.6				100	%		1.6				100	%		4.0				400	%
Increase revenue (Hedged) (a)		$m		$	17.2			$	43.3			152	%		$	32.3			276	%		$	38.4			123	%
Increase revenue (Un-hedged)		$m		$	17.1			$	41.8			144	%		$	30.9			261	%		$	38.7			126	%
Reduce unit lease operating costs (b)		$ per BOE		$	9.59			$	6.50			(32	)%		$	6.10			(36	)%		$	6.33			(34	)%
Reduce unit recurring G&A (c)		$ per BOE		$	2.37			$	2.03			(14	)%		$	1.84			(22	)%		$	1.44			(39	)%
Adjusted EBITDA (Hedged) (d)		$m		$	4.3			$	17.5			307	%		$	13.4			212	%		$	15.5			1,342	%
Adjusted EBITDA Margin (Hedged)		%		25		%		40		%		15 points			42		%		17 points			40		%		15 points
Adjusted EBITDA (Un-hedged) (d)		$m		$	4.2			$	16.0			281	%		$	12.1			476	%		$	15.8			1,405	%
Adjusted EBITDA Margin (Un-hedged)		%		24		%		38		%		14 points			39		%		15 points			41		%		17 points

a)		Includes the impact of settled hedges. See Note 12 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 for more information.
c)		2016 recurring G&A per BOE as presented above includes owner distributions of $0.88 per BOE which were recorded in equity under the Company's corporate structure prior to admission to AIM in February 2017. Corresponding expenses in 2017 are recorded as salaries and wages expense within recurring G&A. For more information on recurring G&A expenses see Note 4.
d)		Note that the calculation of % Change vs 2016FY for Adjusted EBITDA reflects an annualised Adjusted EBITDA for 2H17 and 1Q18PF.
e)		1Q18PF results reflect the current estimate of the Company's results for the first quarter as if the acquisitions of APC and CNX were completed with effect from 1 January 2018.

The Appalachian Basin opportunity 

The prevailing market conditions in our regional focus on the Appalachian Basin, both before and increasingly more so following our IPO, have created a compelling buyer's market for well-capitalised, credible, local operators wishing to expand their portfolio of mature, producing assets.  The Appalachian Basin, the oldest producing basin in the US with an abundance of existing infrastructure, has seen a rapid expansion of unconventional activity as large players focus their operations on the prolific Utica and Marcellus shale reservoirs located throughout the basin.  This industry shift towards unconventional assets, the rights to which are held by production ("HBP"), means the mature, often conventional producing assets which routinely retain the rights to the unconventional assets held in deeper zones within the same leasehold, have become non-core to the larger industry players.  As such, these parties are keen to offload these assets to buyers who can maintain the conventional production while allowing them to retain the rights to the unconventional reservoirs.  With the maintenance of production and rights to the undeveloped, unconventional reservoirs being the main priority for the seller, this market dynamic creates particularly attractive valuation metrics for the appropriate buyers as price is not always the seller's principal factor in completing transactions.  

Having operated in the Appalachian Basin since 2001 and having completed three of the largest conventional asset deals in the region in recent history, DGO has developed a strong network and regional reputation as a proven and credible operator, with a first-mover advantage in a small band of appropriate companies competing to capitalise on these unique buying opportunities.  Furthermore, our proven ability to raise capital through the debt and equity markets puts us in an even smaller peer group capable of executing the material transactions of larger asset packages being divested. 

Growing through acquisition 

Our successful placing and admission to AIM in February 2017, raising gross proceeds of $50m, enabled us to significantly strengthen our balance sheet and liquidity and positioned us to transact on the opportunities stated above. We were pleased to complete our first transaction only weeks after coming to market, as we acquired a package of 1,300 producing wells for $1.75m.  The acquisition added production of 3,800 mcfd and 110bopd. We completed field operation integration for these wells in May 2017, and more fully completed the integration of accounting operations in June 2017.

In March 2017, DGO identified the opportunity to acquire certain Appalachian Basin gas and oil assets from Titan Energy that were consistent with our acquisition criteria and that had the potential to significantly enhance the Company's scale and profile in the region. DGO successfully raised an additional $35m through a further placing and negotiated a new $110m senior secured credit facility to fund the $84.2m asset acquisition. The Company closed on a portion of the assets in June 2017 and the remaining assets in September 2017.  Inclusive of all Titan Energy assets, the Company's gross oil and gas production increased to approximately 10,400 boepd in the fourth quarter of 2017.

Reflective of the robust growth opportunity set in the Appalachian Basin, DGO closed on two additional and transformational acquisitions in the first quarter of 2018, which included the purchase of APC and the conventional Appalachian assets from CNX for a combined purchase price of $180 million. These acquisitions grew DGO's net daily production to over 28,000 boepd, making us the largest producer on AIM. Importantly, the wells we acquired from APC and CNX are immediately accretive to Adjusted EBITDA and increased PDP reserves to approximately 173 mmboe, providing a large inventory of future cash flows to fund our quarterly dividend.  The acquisitions were funded through a successful further placing that raised $189m, undertaken by our broker Mirabaud Securities, who have supported DGO since our flotation, and Stifel Nicolaus Europe who we have appointed as the Company's joint broker.

We continue to screen a pipeline of complementary and value accretive opportunities in the Appalachian Basin and other producing regions of the United States with similar long-life, low-decline wells, which DGO is built to operate efficiently. Inclusive of our recently executed, syndicated Credit Facility led by KeyBank NA, we possess the low-cost liquidity to execute on additional transactions should we find them to be compelling and in the best interest of the Company and its shareholders. 

Simplified, efficient integration process 

Integration risk is significantly reduced and the process simplified by our decision to retain the field-level personnel who manage the assets day-to-day for the seller. Maintaining these skilled employees allows us time to evaluate the assets while prudently implementing our more efficient asset management programmes. Where appropriate, we have restructured our field operations team to reflect our scale and geographical size. Our legacy employees combined with these new additions to our team are unified in their focus to ensure a smooth and effective integration of the new assets into our operations processes.  As part of this process, the enlarged team is working to enhance production and strive to generate cost savings.  The addition of many talented, experienced employees from each acquisition plays an important role in our strategy, and we are very pleased to report that we are already seeing tangible benefits from this process.

To further support the integration effort for each acquisition, we routinely enter into transitional services agreements ("TSA") for accounting and other administrative services. In addition to the TSAs, we engage, as necessary, consulting and other professional services to work with our teams on further integration strategies including accounting and technology needs. 

Organic opportunity 

Whilst our present growth efforts have focused on successfully achieving scale through carefully selected acquisitions, our expansive held-by-production acreage portfolio provides significant organic growth opportunities.  As we complete the full integration of the newly acquired assets, our field management team will focus on maximising production by enhancing operational techniques.  Our extensive leasehold, which now covers approximately 4 million acres, has been sparsely drilled to date and therefore provides material opportunity for infill drilling to increase the production throughout the portfolio.  Development wells are both low-risk and low-cost, ranging from $250k - $350k per well to drill and place on production.  Management intends to initiate a development programme when drilling economics become more favourable and offer the Company higher rates of return than are currently provided through the compelling acquisition opportunities available at present valuations from which we have recently benefitted. 

Enhancing the DGO team

An important aspect of successfully executing our strategy is ensuring we have leadership and management teams with the skills and experience necessary to oversee our rapid expansion. As such, we have placed a significant focus on adding depth to our team in the past year through the hire of several high quality professionals.  With the acquisition of the Titan Energy assets, we added Bob Cayton as our Senior Vice President of Operations and John "Jack" Crook as our Senior Vice President of Environmental, Health & Safety.  Both Bob and Jack each have over 30 years of experience operating in the Appalachian Basin and they are focused on delivering operational excellence with a substantial portion of our Appalachian operations.  With the APC acquisition, we added Dora Silvis as an Executive Vice President who will oversee the integration of the APC and CNX acquisitions into DGO's systems and processes and Timothy Altier as Senior Vice President of APC's operations who will work closely with Mr. Cayton to manage the day-to-day field operations. Each of these experienced professionals report directly to our Chief Operating Officer, Brad Gray, who is responsible for the overall operational execution of our business and for the successful integration of our acquisitions. 

We also extended our capital markets, accounting and financial reporting capabilities with the addition of Eric Williams as our new Chief Financial Officer, Michael Garrett as our Vice President of Accounting and Controller and Bryan Berry as Vice President of Finance. We were also pleased to enhance our middle management teams in both field operations and administrative functions.

Dividend

The Board paid a 2016 final dividend of 1.99 cents per share to shareholders on 31 July 2017 and a 2017 interim dividend of 1.99 cents per share on 20 December 2017. The Company announces a recommended 2017 final dividend of 3.45 cents per share which, if approved by shareholders at the Annual General Meeting, will be paid on 31 May 2018 to those shareholders on the register on 11 May 2018. One of DGO's core principals is to return earnings to shareholders through a regular dividend, and we were pleased to announce that our 2017 year-end dividend was 73% higher than our first two dividends. Additionally, we were pleased to announce on 3 April 2018 a move from semi-annual dividend payments to quarterly dividend payments.

Outlook

2018 promises to represent a step-change in DGO's financial and operational profile as we reap the benefits from the transactions that we completed in 2017 and our two additional acquisitions in the first quarter of 2018. Near term, we will remain highly focused on the successful integration of each asset with a particular emphasis on the work required to ensure we maximise production whilst lowering our per unit operating expenses. 

The sector backdrop continues to be challenging and we are in a highly fortunate position to be operating in a safe jurisdiction, benefit from a strong balance sheet and have an effective business model that provides significant downside protection against the variables of commodity prices.  Our low-cost operations ensure we are profitable in the current environment, and able to withstand a further decrease in commodity prices.  We also take a prudent approach to the way the business is run in terms of cash management by hedging our production to ensure visibility on predictable earnings.  Ironically, we are uniquely positioned to benefit from the challenging sector backdrop as it creates very compelling acquisition opportunities as distressed companies seek to rationalise their portfolio.  

Over the longer-term, we continue to work on our existing portfolio to seek in-fill opportunities and maximise the efficiency, production and longevity of our assets, activities that are a key aspect of company reputation and expertise.  Further, we continue to seek attractive acquisition opportunities arising out of current market conditions that have already resulted in a number of strategic purchases for DGO in the past 18 months. As our acquisitive momentum has increased over the years, we seek to continue to deliver valuable additions to our portfolio in the Appalachian Basin and other suitable mature, hydrocarbon basins in the US.

A financial and operational summary of our 2017 results is shown below.

Financial Review

		Year Ended
		31 December 2017				31 December 2016				$ Change				% Change
Net production
Natural gas (MMcf)		13,119				5,892				7,227				122.7	%
Oil (MBbls)		163				110				53				48.2	%
NGL (MBbls)		50				-				50				100.0	%
Total (MBOE)		2,400				1,092				1,308				119.8	%
Average daily production (BOE/d)		6,575				2,992				3,583				119.8	%
% gas (BOE basis)		91		%		90		%
Average realised sales price
(excluding impact of cash settled derivatives)
Natural gas (Mcf)		$	2.32			$	1.81			$	0.51			28.2	%
Oil (Bbl)		49.37				38.25				11.12				29.1	%
Total (BOE)		$	16.48			$	13.62			$	2.86			21.0	%
Average realised sales price
(including impact of cash settled derivatives)
Natural gas (Mcf)		$	2.44			$	1.84			$	0.60			32.6	%
Oil (Bbl)		49.07				38.25				10.82				28.3	%
Total (BOE)		$	17.12			$	13.76			$	3.36			24.4	%
Natural gas and oil revenue
(in thousands)
Natural gas		$	30,463			$	10,671			$	19,792			185.5	%
Oil		8,047				4,207				3,840				91.3	%
NGL		1,043				-				1,043				100.0	%
Total natural gas, oil and NGL revenue		39,553				14,878				24,675				165.8	%
Other revenue		2,224				2,210				14				0.6	%
Total revenue		$	41,777			$	17,088			$	24,689			144.5	%
Gains (losses) on derivative settlements
Natural gas		$	1,574			$	146			$	1,428			978.1	%
Oil		(49		)		-				(49		)		(100.0	)%
Net gains on derivative settlements		$	1,525			$	146			$	1,379			944.5	%
Per BOE metrics
Realised price (including impact of cash settled derivatives)		$	16.48			$	13.62			$	2.86			21.0	%
Other revenue		0.93				2.02				(1.09		)		(54.0	)%
Lease operating expenses		6.50				9.59				(3.09		)		(32.2	)%
Recurring administrative expenses (a)		2.03				2.37				(0.34		)		(14.3	)%
Production taxes		1.41				0.76				0.65				85.5	%
Gathering and transportation		0.80				-				0.80				100.0	%
Operating margin		$	6.67			$	2.92			$	3.75			128.4	%
% Operating margin		38.3		%		18.7		%

a)

2016 recurring G&A per BOE as presented above includes owner distributions of $0.88 per BOE which were recorded in equity under the Company's corporate structure prior to admission to AIM in February 2017. Corresponding expenses in 2017 are recorded as salaries and wages expense within recurring G&A.

Production, Revenue and Hedging

Total revenue in 2017 was $41.8m, a 144.5% increase over $17.1m for 2016. The increase in revenue was primarily attributable to a 119.8% increase in barrel of oil equivalent sales and an 21.0% increase in the average realised sales price. DGO ended 2017 with net MBOE sales of approximately 2,400 vs. the prior year sales of approximately 1,092. The increase in production was driven by the increase in producing wells from our acquisitions of assets from Titan Energy and EnerVest Energy in 2H17. 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
Revenue for the year ended 31 December 2016		$	10,671			4,207
Volume increase		13,081				2,027
Price increase		6,711				1,813
Net increase		19,792				3,840
Revenue for the year ended 31 December 2017		$	30,463			$	8,047

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 2017				Per BOE				31 December 2016				Per BOE				$				%			$				%
Lease operating expenses a		$	15,591			$	6.50			$	10,470			$	9.59			$	5,121			49	%		$	(3.09	)		(32	)%
Production taxes		3,392				1.41				833				0.76				2,559				307	%		0.65				86	%
Gathering and transportation		1,925				0.80				-				-				1,925				100	%		0.8				100	%
Total cost of sales		20,908				$	8.71			11,303				$	10.35			$	9,605			85	%		$	(1.64	)		(16	)%
Depreciation and depletion		7,013				2.92				4,039				3.70				2,974				74	%		(0.78		)		(21	)%
Administrative expenses		8,919				3.72				2,813				2.58				6,106				217	%		1.14				44	%
Total expenses		$	36,840			$	15.35			$	18,155			$	16.63			$	18,685			103	%		(1.28		)		(8	)%

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.

DGO's operating expenses in 2017 were $36.8m compared to $18.2m in 2016. The $18.7m increase reflects the following:

•        A $9.6m increase in costs of sales due to additional expenses related to newly acquired oil and gas properties from the Titan and EnerVest acquisitions in 2H17. On a per BOE basis, cost of sales decreased by 16% which was attributable to higher production volumes received from an increased number of producing wells from these acquired properties.

•       A $3.0m 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 acquisitions made in 2H17 as discussed above.

•       A $6.1m increase in administrative expenses reflecting costs of the Company's acquisition efforts in 2017 and the investment made in staff and systems to support the Company's growth.

Finance costs

		Year ended								Year over Year
		31 December 2017				31 December 2016				$ Change				% Change
Interest		$	3,776			$	2,418			$	1,358			56.2	%
Finance charge		140				48				92				191.7	%
Bond financing costs		675				825				(150		)		(18.2	)%
Loan standby fee		597				-				597				100.0	%
Loan management fee		37				-				37				100.0	%
Total finance costs		$	5,225			$	3,291			$	1,934			58.8	%
Loss (gain) on early retirement of debt		$	4,468			$	(14,149	)		$	18,617			131.6	%

DGO's finance costs include interest expense on borrowings and non-cash amortization of deferred financing costs. In June 2017 the Company closed a new $110.0m senior secured credit facility, of which, $64.0m was drawn at closing of the Titan acquisition on 30 June 2017 and a subsequent draw of $11.0m on 30 September 2017, to partially fund the purchase of oil and gas assets. Interest expense on borrowings of $3.8m in 2017 increased $1.4m compared to $2.4m in 2016 primarily due to the increase in borrowings. 

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 $3.8m charge for the accelerated amortization of the remaining deferred financing costs and $0.6m in premiums paid to redeem convertible bonds prior to DGO's admission to AIM.

Income before taxation, EPS and Adjusted EBITDA

DGO reported income before taxation of $4.7m in 2017 compared to $32.5m in 2016, a decrease of 85%, and reported statutory earnings for 2017 per diluted ordinary share of $0.07 compared to $0.42 per diluted ordinary share in 2016. However, when adjusted for certain non-cash items such as gains on bargain purchases and similar items, DGO reported adjusted EBITDA per diluted ordinary share of $0.15 per diluted ordinary share, a 50% increase over the prior year's $0.10 adjusted EBITDA per diluted ordinary share. DGO's adjusted EBITDA for 2017 was $17.5m, a 307.6% increase over $4.3m in 2016. Refer to Note 5 for additional information regarding DGO's adjusted EBITDA.

Conclusion

In summary, 2017 has been truly transformational for the Company.  We delivered on the strategic, corporate and operational objectives that we defined at the time of obtaining our admission to AIM in February 2017.  We entered 2018 in a strong position and I could not be more pleased with our strategic additions of Alliance Petroleum and conventional Appalachian assets from CNX. While we are pleased to become the largest producer on AIM, we remain ever mindful of the importance of successfully executing on our day-to-day commitment to efficiently operate our wells to generate dividends and equity returns for shareholders.  I wish to extend my gratitude to our shareholders who have demonstrated confidence in our defined strategy, management team and our focus on additional growth.  I would also like to thank my colleagues for their hard work and commitment, without which we would not have been able to deliver such impressive growth.  We are wholly focused on delivering value for all our stakeholders as we leverage the strong platform that we have created. 

Rusty Hutson Jr

Chief Executive Officer

Consolidated Statements of Profit or Loss and Other Comprehensive Income

(Amounts in thousands, except per-share amounts)

(Audited)

				Year ended
		Note		31 December 2017				31 December 2016
Revenue		3		$	41,777			$	17,088
Cost of sales		4		(20,908		)		(11,303		)
Depreciation and depletion		4		(7,013		)		(4,039		)
Gross profit				$	13,856			$	1,746
Administrative expenses		4		(8,919		)		(2,813		)
Gain on disposal of property and equipment				95				34
Loss on derivative financial instruments		12		(441		)		(810		)
Gain on bargain purchase		2		11,603				24,293
Operating profit				$	16,194			$	22,450
Finance costs		11		(5,225		)		(3,291		)
(Loss) gain on early retirement of debt		11		(4,468		)		14,149
Accretion of decommissioning provision		10		(1,764		)		(797		)
Income before taxation				$	4,737			$	32,511
Taxation on income		6		4,138				(14,829		)
Income after taxation available to ordinary shareholders				$	8,875			$	17,682
Other comprehensive income - gain on foreign currency conversion				355				901
Total comprehensive income for the year				$	9,230			$	18,583
Earnings per ordinary share - basic & diluted		7		$	0.07			$	0.42
Weighted average ordinary shares outstanding - basic		7		120,136				42,011
Weighted average ordinary shares outstanding - diluted		7		120,269				42,011

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

Consolidated Statements of Financial Position

(Amounts in thousands)

(Audited)

		Note		31 December 2017				31 December 2016
ASSETS
Non-current assets
Oil and gas properties, net		9		$	190,358			$	76,793
Property and equipment, net				6,947				3,348
Other non-current assets				1,036				998
Restricted cash				744				117
Total non-current assets				$	199,085			$	81,256
Current assets
Trade receivables				13,917				3,084
Other current assets				513				1,311
Cash and cash equivalents				15,168				224
Total current assets				$	29,598			$	4,619
Total Assets				$	228,683			$	85,875
EQUITY AND LIABILITIES
Shareholders' equity
Share capital				$	1,940			$	669
Share premium				76,026				313
Merger reserve				(478		)		(478		)
Share based payment reserve		8		59				-
Retained earnings				12,112				8,658
Total Equity				$	89,659			$	9,162
Non-current liabilities
Decommissioning liability		10		$	35,448			$	12,265
Capital lease				836				274
Borrowings		11		70,619				10,113
Deferred tax liability		6		11,011				15,148
Other non-current liabilities				5,764				414
Total non-current liabilities				$	123,678			$	38,214
Current liabilities
Trade and other payables				$	2,132			$	4,627
Borrowings		11		373				27,181
Capital lease				324				169
Other current liabilities				12,517				6,522
Total current liabilities				$	15,346			$	38,499
Total Liabilities				$	139,024			$	76,713
Total Equity and Liabilities				$	228,683			$	85,875

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

The consolidated financial statements were approved by the Board of Directors on 28 April 2018 and were signed on its behalf by:

Robert M. Post

Chairman

Consolidated Statements of Changes in Equity

(Amounts in thousands)

(Audited)

																Share
																Based
				Share				Share				Merger				Payment				Retained				Total
		Note		Capital				Premium				Reserve				Reserve				Earnings				Equity
Balance at 1 January 2017				$	669			$	313			$	(478	)		$	-			$	8,658			$	9,162
Income after taxation				-				-				-				-				8,875				8,875
Gain on foreign currency conversion				-				-				-				-				355				355
Total comprehensive income				-				-				-				-				9,230				9,230
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 authorized and declared		8		-				-				-				-				(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			$	12,112			$	89,659
																Share
																Based
				Share				Share				Merger				Payment				Retained				Total
				Capital				Premium				Reserve				Reserve				Earnings				Equity
Balance at 1 January 2016				$	630			$	-			$	(478	)		$	-			$	(8,969	)		$	(8,817	)
Income after taxation				-				-				-				-				17,682				17,682
Gain on foreign currency conversion				-				-				-				-				901				901
Total comprehensive income				-				-				-				-				18,583				18,583
Stockholder distributions pre-group reconstruction				-				-				-				-				(956		)		(956		)
Issuance of share capital				39				313				-				-				-				352
Transactions with shareholders				39				313				-				-				(956		)		(604		)
Balance at 31 December 2016				$	669			$	313			$	(478	)		$	-			$	8,658			$	9,162

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

Consolidated Statements of Cash Flow

(Amounts in thousands)

(Audited)

								Year ended
		Note		31 December 2017				31 December 2016
Cash flows from operating activities
Income after taxation				$	8,875			$	17,682
Cash flow from operations reconciliation:
Depreciation and depletion				7,013				4,039
Accretion of decommissioning provision		10		1,764				797
Deferred income taxes		6		(4,137		)		14,829
Provision for working interest owners receivable				632				-
Loss on derivative financial instruments		12		1,965				957
Gain on oil and gas program				(396		)		(84		)
Gain on bargain purchase		2		(11,603		)		(24,293		)
Gain on debt cancellation				-				(14,149		)
Deferred financing expense				4,510				3,291
Gain on disposal of property and equipment				95				(34		)
Non-cash equity compensation				59				340
Working capital adjustments:
Change in trade receivables				(11,465		)		(907		)
Change in other current assets				798				(269		)
Change in other assets				(38		)		(652		)
Change in trade and other payables				(2,495		)		2,662
Change in other liabilities				11,345				920
Net cash provided by operating activities				$	6,922			$	5,129
Cash flows from investing activities
Expenditures on oil and gas properties				$	(88,267	)		$	(7,838	)
Expenditures on property and equipment				(1,953		)		(862		)
Plugging and abandonment				(78		)		-
Increase in restricted cash				(627		)		(2		)
Proceeds on disposal of oil and gas properties				334				93
Net cash used in investing activities				$	(93,091	)		$	(9,209	)
Cash flows from financing activities
Proceeds from borrowings				$	75,000			$	14,915
Repayment of borrowings				(42,514		)		(6,794		)
Financing expense				(3,298		)		(3,222		)
Proceeds from capital lease				1,246				435
Repayment of capital lease				(529		)		(164		)
Proceeds from equity issuance, net				76,984				-
Dividends to shareholders				(5,776		)		(956		)
Net cash provided by financing activities				$	101,113			$	4,214
Net increase in cash and cash equivalents				14,944				134
Cash and cash equivalents - beginning of the period				224				90
Cash and cash equivalents - end of the period				$	15,168			$	224

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

NOTES (Amounts in thousands, except per-share amounts)

Note 1 - Significant Accounting Judgments, Estimates and Assumptions

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

Valuation of intangible oil and gas assets on acquisition 

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. An assessment of the value of these proved reserves on acquisition is produced, considering the discounted cash flows of production to a present value ("PV"). DGO uses a discount factor ranging between 10% and 35% for acquisitions of oil and gas assets, depending on the market conditions at the time of the transaction as well any additional risk factors arising in the specific transaction, to best obtain a fair value estimate of oil and gas properties. 

Impairment indicators for oil and gas properties 

Following a review by the Directors of ongoing operational performance of DGO's natural gas and crude oil properties for the year ended 31 December 2017, the Directors are 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 analyzing geological data, such as drilling samples. This process may require complex and difficult geological judgments and calculations to interpret the data. The Directors have engaged third-party engineers who are considered experts and have extensive experience in oil and gas engineering, with focus in the Appalachian Basin of the US. 

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. 

Decommissioning costs 

The ultimate decommissioning 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 decommissioning. See Note 10 for more information.

Note 2 - Acquisitions

The assets acquired in all acquisitions include the necessary permits, rights to production, royalties, contracts and agreements that support the production from the wells. The Company accounts for business acquisition under IFRS 3. 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.

2017 Acquisitions

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 totaling $1,750. Management considered the fair value of the reserves held in the assets acquired to be $5,629, which was the 30% cumulative cash flow 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:

Oil and gas properties		$	5,629
Oil and gas properties (Decommissioning provision, asset portion)		2,406
Decommissioning liability		(2,406		)
Gain on bargain purchase		(3,879		)
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 $84,200, excluding customary purchase price adjustments. The cash consideration for the purchase was funded by a new $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.

Management determined the fair value of the reserves held in the assets acquired on 30 June 2017 to be $85,392, which was approximately 25% cumulative cash flow 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:

Oil and gas properties		$	85,392
Oil and gas properties (Decommissioning provision, asset portion)		16,366
Other PPE		1,752
Decommissioning liability		(16,366		)
Other liabilities		(2,279		)
Gain on bargain purchase		(7,522		)
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 totaling $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 provisional estimated fair values of the assets and liabilities assumed were as follows:

Oil and gas properties		$	3,003
Oil and gas properties (Decommissioning provision, asset portion)		818
Other PPE		352
Decommissioning liability		(818		)
Other liabilities		(39		)
Gain on bargain purchase		(202		)
Purchase price		$	3,114

2016 Acquisitions

Eclipse Resources Acquisition

In April 2016, DGO acquired 1,300 conventional natural gas and oil wells in Ohio and equipment from Eclipse Resources. The Company paid consideration totaling $4,800, including cash of $1,300 and a short-term note payable of $3,500. Management determined the fair value of the reserves held in the assets acquired to be $11,774, which was approximately 30% cumulative cash flow 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:

Oil and gas properties		$	11,774
Oil and gas properties (Decommissioning provision, asset portion)		2,443
Equipment		757
Decommissioning liability		(2,443		)
Other liabilities		(89		)
Gain on bargain purchase		(7,642		)
Purchase price		$	4,800

Seneca Resources Corporation Acquisition

In June 2016, DGO acquired 2,200 conventional natural gas and oil wells in Pennsylvania from Seneca Resources Corporation. The Company paid consideration including cash financed by a short-term note payable of $3,500 and an interest free obligation to the seller of $3,550. Management determined the value of the reserves held in the assets acquired was $23,620, which was approximately 35% cumulative cash flow 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:

Oil and gas properties		$	23,620
Oil and gas properties (Decommissioning provision, asset portion)		4,249
Decommissioning liability		(4,249		)
Gain on bargain purchase		(16,570		)
Purchase price		$	7,050

Subsequent Events

In February 2018, DGO placed 166,400 new ordinary shares at $1.13 per share with certain existing and new institutional investors to raise net proceeds of $180,000 to fund the following 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 $95,000, excluding customary purchase price adjustments, including cash consideration of $70,000 and the assumption of $25,000 of outstanding debt (which was fully paid on the closing date). The Company funded the cash consideration for the purchase with the $180,000 net proceeds from its equity placing of DGO's stock in February 2018. The Company is evaluating the fair value of the assets acquired and liabilities assumed and any necessary pro forma financial information. 

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 $85,000, excluding customary purchase price adjustments. The Company funded the cash consideration for the purchase with the $180,000 net proceeds from its equity placing of DGO's stock in February 2018. The Company is evaluating the fair value of the assets acquired and liabilities assumed and any necessary pro forma financial information. 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 totalled $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.

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. The following table reconciles the Company's revenue for the periods presented: 

		Year ended
		31 December 2017				31 December 2016
Natural gas		$	30,463			$	10,671
Oil		8,047				4,207
Total natural gas, oil and NGL		39,553				14,878
Operator		936				18
Oil and gas program		705				1,573
Water disposal		565				619
Other		18				-
Total revenue		$	41,777			$	17,088

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

During the year ended 31 December 2017, two customers individually totaled more than 10% of total revenues, totaling 25% and 17% and for the year ended 31 December 2016, three customers individually totaled more than 10% of total revenues, totaling 21%, 18% and 10%. All revenue was generated in the United States of America. 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.

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

Note 4 - Expenses by Nature

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

				Year ended
		Explanation		31 December 2017				31 December 2016
Employees and benefits				$	8,539			$	3,844
Automobile				1,441				797
Insurance				491				162
Production taxes				3,392				833
Gathering and transportation				1,925				-
Well operating expenses, net				5,120				5,667
Total cost of sales		a		$	20,908			$	11,303
Depreciation				1,469				756
Depletion				5,544				3,283
Total depreciation and depletion				$	7,013			$	4,039
Employees and benefits				2,655				646
Other administrative				1,525				301
Professional fees				360				272
Auditors' remuneration
Fees payable to the Company's auditor for the audit of the group and Company's annual accounts				55				34
Fees payable to the Company's auditor and its associates for other services:
Audit of the accounts of subsidiaries				125				247
Corporate finance services					73				42
Total auditors' remuneration				$	253			$	323
Rent				86				93
Recurring administrative expenses				$	4,879			$	1,635
Non-recurring costs associated with acquisitions & contribution of assets				3,349				838
Provision for working interest owners receivable				632				-
Non-cash equity compensation		b		59				340
Non-recurring administrative expenses				$	4,040			$	1,178
Total administrative expenses		a		$	8,919			$	2,813
Total expenses		a		$	36,840			$	18,155
Aggregate remuneration (including Directors):
Wages and salaries				$	8,272			$	3,346
Payroll taxes				729				278
Benefits				2,252				1,206
Total employees and benefits expense		a		$	11,253			$	4,830
Monthly average number of employees				162				81

a)		The increase in expenses is primarily related to the oil and gas properties acquired during 2017. See Note 2 for more information about the Company's acquisitions.
b)		Non-cash equity issuance in 2017 reflects the expense recognition related to the issuance of restricted stock units to certain key managers. The expense for 2016 was a non-recurring expense related to the initial issuance of stock to a Company senior manager.

Details of the Directors' remuneration can be found in the Directors' Report in the Company's report and accounts. 

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 Directors, 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 2017				31 December 2016
Operating profit		$	16,194			$	22,450
Depreciation and depletion		7,013				4,039
Gain on bargain purchase		(11,603		)		(24,293		)
Gain on disposal of property and equipment		(95		)		(34		)
Loss on derivative financial instruments		1,965				957
Non-recurring costs associated with acquisitions & contribution of assets		3,349				838
Provision for working interest owners receivable		632				-
Non-cash equity issuance included in administrative expense		59				340
Total adjustments		1,320				(18,153		)
Adjusted EBITDA		$	17,514			$	4,297
Weighted average ordinary shares outstanding - basic		120,136				42,011
Weighted average ordinary shares outstanding - diluted		120,269				42,011
Adjusted EBITDA per share - basic and diluted		$	0.15			$	0.10

Note 6 - Taxation

For taxable year ending 31 December 2016, all DGO subsidiaries became subject to U.S. federal and state income tax and began filing consolidated U.S. federal and state income tax returns and several separate state income tax returns. Prior to this date, DGO subsidiaries had pass-through tax status. 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 the taxable years ending 31 December 2017 and 2016, DGO had tax benefits of $4,137 and tax expenses of $14,829, respectively. The effective tax rate was (81.2)% and 45.6%, respectively, for the same periods. The change in the effective tax rate was primarily related to a reduction in the U.S. rate applied to deferred tax liabilities, and was also impacted by recurring permanent differences including meals and entertainment, state taxes, and other deferred tax.  

The components of the provision for taxation on income included in the Statements of Profit or Loss and Other Comprehensive Income for the periods presented are summarized below:

						Year ended
		31 December 2017				31 December 2016
Current income tax expense
Federal		$	-			$	-
State		-				-
Total current income tax expense		$	-			$	-
Deferred income tax (benefit) expense
Federal		$	(4,365	)		$	13,168
State		228				1,661
Total deferred income tax (benefit) expense		$	(4,137	)		$	14,829

The differences between the statutory federal income tax rate and the effective tax rate for the year ended 31 December 2017 are summarized below:

Expected tax at U.S. statutory income tax rate		$	1,731			34.0	%
Increase (decrease) in tax resulting from:
State income taxes, net of federal tax benefit		(90		)		(1.8	)%
Federal and state rate changes due to TCJA		(5,463		)		(107.3	)%
Federal credits		(250		)		(4.9	)%
Other - net		(65		)		(1.3	)%
Total taxation on income		$	(4,137	)		(81.2	)%

On 22 December 2017, the President of the United States signed into law the Tax Credits and Jobs Act ("TCJA") tax reform legislation. The legislation, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The legislation reduces the U.S. corporate income tax rate from the current rate of 34% to 21% for the year ended 31 December 2018. As a result of the enacted law, the Company was required to revalue deferred tax assets and liabilities at 22 December 2017. The revaluation of deferred taxes for the rate reduction resulted in $5,463 of benefit to income tax expense. 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 Company had a net deferred tax liability of $11,011 and $15,148 at 31 December 2017 and 2016, respectively. The decrease of $5,463 primarily related to the reduction of the statutory U.S. tax rate from 34% to 21% following the enactment of the TCJA and 2017 acquisitions whereby bargain purchase gains were recorded for financial reporting purposes but not for tax purposes, which resulted in a deferred tax liability on acquired assets.

At 31 December 2017, DGO has unused net operating losses available of $5,026 and $3,615 for federal and states, respectively, that may be applied against future taxable income and that begin to expire in 2034.

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

		Year ended
		31 December 2017				31 December 2016
Deferred tax assets
Decommissioning provision asset		$	9,133			$	4,696
Derivative adjustment		742				360
Allowance for doubtful accounts		166				-
Net operating loss carryforward		1,272				1,677
Federal tax credits carryover		250				-
Other		83				-
Total deferred tax assets		$	11,646			$	6,733
Deferred tax liabilities
Depreciation		$	(22,657	)		$	(21,562	)
Foreign currency translation adjustment		-				(319		)
Total deferred tax liabilities		$	(22,657	)		$	(21,881	)
Net deferred tax liability		$	(11,011	)		$	(15,148	)

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 2017 and 2016, PLC did not incur any income tax liability in the United Kingdom.

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 last day of the reporting period. Basic and diluted income/(loss) per ordinary share is calculated as follows:

				Year ended
		Calculation		31 December 2017				31 December 2016
Income after taxation available to ordinary shareholders		A		$	8,875			$	17,682
Weighted average ordinary shares outstanding - basic		B		120,136				42,011
Weighted average ordinary shares outstanding - diluted		C		120,269				42,011
Earnings per ordinary share - basic		= A / B		$	0.07			$	0.42
Earnings per ordinary share - diluted		= A / C		$	0.07			$	0.42
Adjusted EBITDA per ordinary share - basic & diluted		Note 5		$	0.15			$	0.10

Note 8 - Dividends

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

		Dividend per Ordinary Share
Date Declared		USD				GBP				Record Date		Pay Date		Shares Outstanding			Gross Dividends Paid
15 June 2017		$	0.0199			£	0.0155			07 July 2017		31 July 2017		145,076			$	2,888
11 September 2017		0.0199				0.0149				17 November 2017		20 December 2017		145,076			2,888
																	$	5,776
3 April 2018		0.0345				Pending				11 May 2018		31 May 2018		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 a			Disposals			Ending Balance					Beginning Balance				Period Charges			Disposals			Ending Balance					Net Book Value
As at and for the year ended 31 December 2017		$	94,608			120,037			(321	)		$	214,324				$	(17,815	)		(6,151	)		-			$	(23,966	)			$	190,358
As at and for the year ended 31 December 2016		56,659				41,077			(3,128	)		94,608					(14,306		)		(3,553	)		44			(17,815		)			76,793

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

Note 10 - Decommissioning Liability

The Company records a liability for future cost of decommissioning production facilities and pipelines. The decommissioning liability represents the present value of decommissioning 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 2047 when the Company expects its producing oil and gas properties to reach the end of their economic lives. 

These liabilities represent the Directors' best estimates of the future obligation. Directors' assumptions are based on the current economic environment, and represent what they believe is a reasonable basis upon which to estimate the future liability. The Directors review these estimates regularly and adjust for any identified material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices at the time the decommissioning services are performed. Furthermore, the timing of decommissioning will vary depending on when the fields ceases to produce economically, which makes the determination dependent upon future oil and gas prices, which are inherently uncertain.  

The discount rate and the cost inflation rate used in the calculation of the decommissioning liability were 8.0% and 3.0%, respectively as at each of the periods presented. The table below summarizes the activity for the Company's decommissioning liability: 

		Year ended
		31 December 2017				31 December 2016
Balance at 1 January		$	12,265			$	8,869
Additions a		21,497				5,457
Accretion a		1,764				797
Disposals		(78		)		(4		)
Revisions to estimate		-				(2,854		)
Balance at 31 December		$	35,448			$	12,265

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

Note 11 - Borrowings

The Company used part of the equity proceeds raised through its IPO on AIM to repay much of the debt outstanding at 31 December 2016. DGO's borrowings consist of the following amounts for the periods presented: 

		31 December 2017				31 December 2016
Financial institution, with interest rate of 3.25%, secured by oil and gas properties		$	-			$	15,768
Financial institution, interest rate of 4.00%, secured by oil and gas properties		-				3,165
Financial institution, interest rate of WSJ Prime Rate plus 0.50%, secured by oil and gas properties		-				2,000
Financing companies, interest rates of 10%-12%, secured by oil and gas properties		-				4,750
Individuals and institutional investor bonds, interest rate of 8.50%, maturing June 2020, unsecured		81				13,928
Financial institution, interest rate of 8.25% plus LIBOR, maturing July 2020, secured by oil and gas properties (a)		73,249				-
Miscellaneous notes, primarily for equipment, real estate and operational cash flow		495				1,728
Total borrowings		$	73,825			$	41,339
Less current portion of long-term debt		(373		)		(27,181		)
Less deferred financing costs (b)		(2,833		)		(4,045		)
Total non-current borrowings, net		$	70,619			$	10,113

  a)    In June 2017 the Company closed a new $110,000 senior secured credit facility, of which, $64,000 was drawn at closing on 30 June 2017. On 

         30 September 2017, an additional $11,000 was drawn to close on the remaining purchase of oil and gas assets discussed in Note 2.

  b)    Deferred financing costs outstanding at 31 December 2017 were incurred with the financing of the senior secured term loan. 

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

		31 December 2017				31 December 2016
Not later than one year		$	373			$	27,181
Later than one year and not later than five years		73,452				14,158
Later than five years		-				-
Total borrowings		$	73,825			$	41,339

Reconciliation of borrowings arising from financing activities: 

		31 December 2016				Net Cash Flows				31 December 2017
Total borrowings		$	41,339			$	32,486			$	73,825

Gain/Loss on Debt Extinguishment

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 amortization of the remaining deferred financing costs and $633 in premiums paid to redeem convertible bonds.

In March 2016, outstanding borrowings of $14,800 and accrued finance charges of $925 were settled in exchanged for an immediate payment of $950. The remaining balance, net of expenses, is recognized as a gain on early retirement of debt totaling $14,149.

Subsequent Event 

In March 2018, the Company closed a new $500,000 five-year senior secured revolving credit facility, initially subject to a borrowing limit of $140,000.  Following the closing of the acquisition of certain assets of CNX Resources LLC in March 2018, as discussed in Note 2, the borrowing limit increased to $200,000. The facility has an initial interest rate of 2.50% plus LIBOR and is subject to a grid that fluctuates based upon utilisation with a pricing of 2.25% - 3.25% plus LIBOR. At 16 April 2018, the Company had an outstanding balance of $88,000. 

Note 12 - Derivatives

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

(Liabilities)/Assets		31 December 2017				31 December 2016
Natural gas
Swaps		$	28			$	(99	)
Collars		311				(685		)
Basis swaps		(965		)		-
Total natural gas financial derivative contracts		$	(626	)		$	(784	)
Oil
Swaps		$	(56	)		$	-
Collars		(2,222		)		(155		)
Total oil financial derivative contracts		$	(2,278	)		$	(155	)
Total financial derivative contracts		$	(2,904	)		$	(939	)

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 2017				31 December 2016
Non-current assets				$	1,348			$	-
Current assets				955				640
Total assets				$	2,303			$	640
Non-current liability				$	(3,291	)		$	-
Current liabilities				(1,916		)		(1,579		)
Total liabilities				$	(5,207	)		$	(1,579	)
Net liabilities - non-current		Other non-current liabilities		$	(1,943	)		$	-
Net liabilities - current		Other current liabilities		(961		)		(939		)
Net (liabilities)/assets				$	(2,904	)		$	(939	)

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 2017				31 December 2016
Net gain on settlements		$	1,524			$	147
Net loss on fair value adjustments on unsettled financial instruments		(1,965		)		(957		)
Total loss on derivative financial instruments		$	(441	)		$	(810	)

The Company's natural gas and oil derivative financial instruments outstanding at 31 December 2017 are listed below: 

Financial		Remaining		Ending		Swap				Floor				Short Put				Ceiling				Mark-to-Market
Instrument Type		Volumes		Month		Price				Price				Price				Price				31 December 2017
Natural gas
Swap		900,000 MMBTUs		Nov-18		$	2.84			$	-			$	-			$	-			$	13
Swap		6,000,000 MMBTUs		Mar-19		2.89				-				-				-				102
Swap		6,000,000 MMBTUs		Mar-20		2.81				-				-				-				62
Swap		207,000 MMBTUs		Dec-20		2.83				-				-				-				(6		)
Swap		6,000,000 MMBTUs		Mar-21		2.82				-				-				-				(85		)
Swap		1,470,000 MMBTUs		Mar-21		3.01				-				-				-				(58		)
Two-Way Collar		1,500,000 MMBTUs		Mar-18		-				3.00				-				3.55				311
Basis Swap: TCO		20,000 MMBTUs		Apr-18		(0.21		)		-				-				-				1
Basis Swap: TCO		320,000 MMBTUs		Oct-18		(0.34		)		-				-				-				(6		)
Basis Swap: Leidy		320,000 MMBTUs		Oct-18		(0.71		)		-				-				-				9
Basis Swap: Dominion SP		3,600,000 MMBTUs		Dec-18		(0.60		)		-				-				-				(316		)
Basis Swap: Dominion SP		305,000 MMBTUs		Dec-18		(0.53		)		-				-				-				(2		)
Basis Swap: TCO		65,000 MMBTUs		Feb-19		(0.32		)		-				-				-				(1		)
Basis Swap: Dominion SP		7,668,000 MMBTUs		Sep-20		(0.59		)		-				-				-				(532		)
Basis Swap: TCO		2,100,000 MMBTUs		Sep-20		(0.39		)		-				-				-				(4		)
Basis Swap: Dominion SP		124,000 MMBTUs		Oct-20		(0.70		)		-				-				-				17
Basis Swap: Dominion SP		397,500 MMBTUs		Nov-20		(0.60		)		-				-				-				5
Basis Swap: Dominion SP		387,500 MMBTUs		Dec-20		(0.54		)		-				-				-				(3		)
Basis Swap: TCO		207,000 MMBTUs		Dec-20		(0.43		)		-				-				-				(3		)
Basis Swap: Leidy		207,000 MMBTUs		Dec-20		(0.69		)		-				-				-				13
Basis Swap: Dominion SP		1,770,000 MMBTUs		Mar-21		(0.48		)		-				-				-				(90		)
Basis Swap: Tetco		810,000 MMBTUs		Mar-21		(0.46		)		-				-				-				(28		)
Basis Swap: Leidy		397,500 MMBTUs		Mar-21		(0.60		)		-				-				-				(25		)
Oil
Swap		33,000 BBLs		Mar-21		50.78				$	-			$	-			$	-			$	(56	)
Two-Way Collar		2,800 BBLs		Feb-18		-				39.00				-				53.35				(1,265		)
Two-Way Collar		146,000 BBLs		Dec-18		-				41.50				-				51.45				(20		)
Two-Way Collar		5,600 BBLs		Feb-19		-				40.00				-				56.05				(27		)
Two-Way Collar		146,000 BBLs		Dec-19		-				43.50				-				52.40				(854		)
Two-Way Collar		33,000 BBLs		Dec-20		-				42.50				-				57.40				(56		)
Total derivative financial instruments																						$	(2,904	)

Subsequent Event 

Listed in the table below are the natural gas and oil derivative financial instruments executed subsequent to 31 December 2017:  

		Remaining		Ending		Swap				Floor				Short Put				Ceiling
Financial Instrument Type		Volumes		Month		Price				Price				Price				Price
Natural Gas
Swap		5,220,000 MMBTUs		Dec-18		$	2.88			$	-			$	-			$	-
Swap		12,094,500 MMBTUs		Mar-19		2.35				-				-				-
Swap		6,000,000 MMBTUs		Dec-19		2.83				-				-				-
Swap		6,207,000 MMBTUs		Dec-20		2.81				-				-				-
Swap		2,970,000 MMBTUs		Mar-21		2.91				-				-				-
Basis Swap: Dominion SP		4,355,000 MMBTUs		Dec-18		(0.58		)		-				-				-
Basis Swap: Dominion SP		175,500 MMBTUs		Dec-18		(0.58		)		-				-				-
Basis Swap: TCO		523,000 MMBTUs		Dec-18		(0.35		)		-				-				-
Basis Swap: Dominion SP		6,180,000 MMBTUs		Dec-19		(0.58		)		-				-				-
Basis Swap: TCO		1,160,000 MMBTUs		Dec-19		(0.39		)		-				-				-
Basis Swap: Dominion SP		4,197,000 MMBTUs		Dec-20		(0.59		)		-				-				-
Basis Swap: TCO		1,029,000 MMBTUs		Dec-20		(0.40		)		-				-				-
Oil
Swap		15,000 BBLs		Dec-18		$	54.10			$	-			$	-			$	-
Swap		36,000 BBLs		Dec-18		63.65				-				-				-
Swap		48,000 BBLs		Dec-19		63.65				-				-				-
Two-Way Collar		7,500 BBLs		Jun-18		-				45.00				-				53.95
Two-Way Collar		108,000 BBLs		Sep-20		-				45.00				-				64.60
Two-Way Collar		36,000 BBLs		Dec-20		-				45.00				-				60.00

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.

 

END

 

 

FR SESEEUFASEEL