Investor Presentation December 2018 DISCLOSURE The information - - PowerPoint PPT Presentation

Investor Presentation

December 2018

DISCLOSURE

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• The information contained in this document has been prepared by Diversified Gas & Oil PLC (the “Company”). This document is being made available for information purposes only and

does not constitute an offer or invitation for the sale or purchase of securities or any of the assets described in it nor shall they, nor any part of them, form the basis of or be relied on in connection with, or act as any inducement to enter into, any contract or commitment whatsoever or otherwise engage in any investment activity (including within the meaning specified in section 21 of the Financial Services and Markets Act 2000).

• The information in this document does not purport to be comprehensive. While this information has been prepared in good faith, no representation or warranty, express or implied, is or will

be made and no responsibility or liability is or will be accepted by the Company or any of its officers, employees, agents or advisers as to, or in relation to, the accuracy or completeness of this document, and any such liability is expressly disclaimed. In particular, but without prejudice to the generality of the foregoing, no representation or warranty is given as to the achievement or reasonableness of any future projections, management estimates or prospects contained in this document. Such forward-looking statements, estimates and forecasts reflect various assumptions made by the management of the Company and their current beliefs, which may or may not prove to be correct. A number of factors could cause actual results to differ materially from the potential results discussed in such forward-looking statements, estimates and forecasts including: changes in general economic and market conditions, changes in the regulatory environment, business and operational risks and other risk factors. Past performance is not a guide to future performance.

• The document is not a prospectus nor has it been approved by the London Stock Exchange plc or by any authority which could be a competent authority for the purposes of

the Prospectus Directive (Directive 2003/71/EC). This document has not been approved by an authorised person for the purposes of section 21 of the Financial Services and Markets Act 2000.

• The information contained in this document is subject to change, completion or amendment without notice. However, the Company gives no undertaking to provide the recipient with access

to any additional information, or to update this document or any additional information, or to correct any inaccuracies in it or any omissions from it which may become apparent.

• Recipients of this document in jurisdictions outside the UK should inform themselves about and observe any applicable legal requirements. This document does not constitute an offer to

sell or an invitation to purchase securities in any jurisdiction.

• APPALACHIAN BASIN GAS AND OIL PRODUCER

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Highlights Current Net Daily Production (a) 70 Mboe/d PDP Reserves (b) ~493 MMboe PDP PV-10 (b) ~$1.6 Billion Number of Wells ~60,000 2018PF ADJ EBITDA (hedged)(c) ~$144 Million Net Debt / EBITDA(d) ~ 1.8x Market Capitalisation(e) ~$733 Million Enterprise Value(f) ~$1,239 Million

• E&P company focused on acquiring and managing oil and

gas producing assets in the Appalachian Basin

• Publicly traded on the AIM (LON:DGOC)
• Targets low-risk, low-cost, long-life assets

Overview 2018 Highlights

• Closed four significant acquisitions in 2018 for an aggregate

purchase price of $938 million. ― The acquisitions have increased DGOC’s daily net production 7x YTD from ~10 Mboe/d to ~70 Mboe/d and PV-10 from $225 mm to $1.6 billion.

• Raised $492 million of equity to fund growth

– $439 mm in two public equity offerings – $53 mm private placement acquisition consideration(g)

• Established a conforming facility with a syndicate of eleven

traditional bank lenders

• Achieved Net Leverage Ratio below ~ 2.0x to 2.5x target

Strong Outlook

• Realized benefits of enlarged scale

― Successful well management program ― Continued reduction in unit operating expense ― Pricing optionality from midstream expansion ― Enhanced organic growth opportunities

• Robust pipeline of growth opportunities remains robust

ABOUT DIVERSIFIED GAS & OIL

Footnotes: (a) Current Net Daily Production represents October 2018 volumes, inclusive of the recent Core acquisition effective 01Oct2018; b) PDP reserve volumes and PDP PV-10 value is inclusive of the Core acquisition; (c) YTD Actual Adj EBITDA through 30Sept2018 (~$73mm) plus 31Oct2018 Actual Adj EBITDA times 3 (~$23.6mm x 3 = $71mm) for a proforma 4Q18E that totals 2018PF Adj EBTIDA of ($73mm + $71mm =) ~$144mm, inclusive of settled hedges; (d) $507mm Net Debt at 30Nov2018 divided by annualized October 2018 Adjusted EBITDA (=23.6mm x 12 = $283.2mm); (e) Share price of 106p and an exchange rate of 1.2745 as

• f 30 Nov 2018; (f) Enterprise Value uses Market Capitalization as of 30 Nov 2018 with a stock price of 106p and an exchange rate of 1.2745; (g) Represents the 35 million shares issued to the sellers of Core Appalachia.

West Virginia Ohio Kentucky Pennsylvania Virginia Tennessee

Footnote:

BUSINESS MODEL: ACQUIRE, PRODUCE, DRILL

Create Value

Execute Low Risk, Low Cost Drilling Maximize Production; Minimize Costs Target PDP Acquisitions

Inorganic Ongoing Organic Result

Acquire and manage producing natural gas and oil properties to generate cash flow, providing stability and growth.

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COMPANY HIGHLIGHTS

• Focused on Low-Risk, Low-Cost, Long-Life Producing Assets; Current Adj EBITDA margins ~60%
• Reserves are 100% PDP with average estimated remaining lives of ~40 to 50+ years
• Tight geographical profile provides advantageous Economies of Scale
• Large Undeveloped HBP Acreage position provides a significant organic growth platform
• Established Consolidator of Choice in Appalachia; Track record of successful, accretive acquisitions
• Business model underpinned by a commitment to prudent Stewardship and Sustainability

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THE DIVERSIFIED ADVANTAGE

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• Built the organization to optimize production from mature, low-decline

wells

• Sellers are focused on high cost unconventional development

Built For Efficiency

• Organizationally built to maintain low unit-operating costs on existing stable, low-decline production that doesn’t require high IP rates from new

wells to remain low

• Typical E&Ps, including the sellers of these assets, typically have cost structures burdened with high cost fixed structures that include geologists,

petro-physicists, drilling engineers, chemical specialists & additional support required of drilling operators. DGOC is structured with a lower cost structure optimized to manage the type of assets owned.

• DGO’s combination of vertical integration and gas-rich assets that require minimal workover maintenance provide insulation from service cost

reflation to which typical E&Ps are exposed.

Cost Advantaged

• Significant free-cash generation provided by ~60% Adjusted

EBITDA margins that allow DGO to either:

• De-leverage quickly or
• Fund growth without increasing leverage
• Strong hedge portfolio protects cash flow during periods of volatility

Focus Financial Returns

$7.71 $19.36 $- $5.00 $10.00 $15.00 $20.00

Cash Costs Avg Realized Price

Per Boe (UnHedged)(a)

Operating G&A ~60% Margin $11.65

(a) Cost and Average Realized Price data reflects the month of October 2018

$1.29 $3.23 $- $1.00 $2.00 $3.00

Cash Costs Avg Realized Price

Per Mcfe (UnHedged)(a)

Operating G&A ~60% Margin $1.94

Mature Wells

Low-Risk political &

• perational

Low Decline Rates

Long Well Life Shallow Depth Significant Midstream Footprint

• DGOC operates a Large Portfolio of Producing Wells Driving Stable Cash Flows

ASSET HIGHLIGHTS

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U.S. Onshore producing gas and oil assets. (Average

production mix: 87% natural gas with recent growth increasing liquids production)

Provide stable and significant free cash flow. The majority

• f DGO wells, based on their

vintage, decline at ~5% per annum. Benefitting from: Low operating costs (Ongoing optimization) Low ongoing maintenance capex (~$5 mm annually) Averaging ~4,200 ft vertical wells into low permeability reservoirs sitting above the shale. >99% are conventional wells. Enhances the economics of upstream assets and provides meaningful additional revenue stream (low maintenance CapEx of

~$15 - $17mm annually)

Estimated from ~40 to 50+ years with significant well control.

One of DGOC’s fundamental objectives is to return previously unproductive wells to production.

MAXIMIZE PRODUCTION: REACTIVATING INACTIVE WELLS

CNX(a)

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Perform light well maintenance (“workover”) Swab the well to remove fluid Repair flow lines Sell production to home or land owner Increase pressure with compression

The Process:

~130

Wells Returned in last 90 days (a)

(a) These ~130 wells returned to production from 01Sep2018 to 30Nov2018 are incremental to the previously reported 524 wells returned to production from 01Jan2017 to 31Aug2018, increasing the total to over 650 wells.

Target Levels: 75% - 90%

Unhe nhedg dged Volum ume

Net PDP Reserves Hedging Overview (See Appendix for Hedge Portfolio Detail by Commodity)

Footnote: (a) Required by the Credit Facility agreement. Note that for acquisitions, for the minimum forecasted net PDP volume hedging requirements, 25% of the required volumes must be hedged within 30 days after closing the acquisition, 50% must be hedged within 60 days after closing, 75% must be hedged within 90 days after closing, and 100% of the 75% requirement must be hedged within 120 days after

• closing. (b) gas prices are for the NYMEX price only and does not include basis..

Period Ave Downside Protection(b) Average Volume (MMBtu/day) 4Q18 $2.98 151,682 1Q19 $2.89 194,077 2Q19 $2.75 239.218 3Q19 $2.75 247,101 4Q19 $2.74 230,518 See appendix for hedging details beyond 2019 Period Ave Downside Protection Average Volume (Bbls/day) 4Q18 $38.28 505,499 1Q19 $38.78 512,790 2Q19 $36.38 506,415 3Q19 $36.25 500,280 4Q19 $36.76 494,383 See appendix for hedging details beyond 2019 Period Ave Downside Protection Average Volume (Bbls/day) 4Q18 $50.73 730 1Q19 $49.77 715 2Q19 $51.60 701 3Q19 $51.18 688 4Q19 $50.89 675 See appendix for hedging details beyond 2019

OIL NGL NATURAL GAS

Hedging Strategy Hedge Portfolio Target Levels

75% - 90% of net PDP reserves

• n a volumetric basis(a)

1

Portfolio Duration

Opportunistically layer on hedges to achieve 12 rolling quarters of hedged production(a)

2

Preferred Structures

Only non-speculative and vanilla structures; costless collars; swaps; & puts

3

Fixed vs. Physical

Preference to have physical contracts but layer on financial contracts as physical market becomes illiquid

4

NYMEX + Basis

Primarily hedge at Henry Hub but use basis hedges when appropriate (Dom South & TETCO M2)

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HEDGED TO PROTECT CASH FLOW & DIVIDEND

29th

A TRANSFORMATIONAL YEAR; DISCIPLINED GROWTH

31st 7th 14th 20th 27th 17th

$189MM

Equity Offering

JOINS DGO

$500MM

CreditFacility

$200MM

Borrowing Base

$250MM

Equity Offering

FIRST HALF 2018 SECOND HALF 2018

Jan Feb Mar Apr May June July Aug Sep Oct

(SelectedAssets)

JOINS DGO

(SelectedAssets)

JOINS DGO

Capital Markets Transaction Acquisition

JOINS DGO

Pro Forma Net Leverage(a): ~0.8x Pro Forma Net Leverage(b): ~2.1x Pro Forma Net Leverage(c): ~1.8x

11th

$1.0BN

CreditFacility

$600MM

Borrowing Base

$53MM

Private Placement (d)

$720MM

Combined Borrowing Base

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(a) Net leverage is proforma for the APC/CNX acquisition (closed Mar2018) and assumes Net Debt of $58mm and Adj annualized EBITDA of ~75mm (b) Net Debt is proforma for the EQT acquisition that closed July 2018 and assumes net debt of $413mm and annualized Adj EBITDA of $216mm. (c) Net Debt as of 30Nov2018 ($507mm) over Annualized Oct 2018 Adj EBITDA (=$23.6 x 12 months = $283mm); (d) Represents the 35 million shares issued to the sellers of Core Appalachia

AN EXPERIENCED TEAM NEARLY 1,000 STRONG

Titan Employees

155+

APC Employees

180+

CORE Employees

250+

EQT Employees

245+

Legacy Employees

120+

EACH ACQUISITION ADDED EXPERIENCED TEAMS

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Rusty Hutson Jr

CEO and Co-Founder

Brad Gray

EVP & Chief Operating Officer

David Myers

Chief Information Officer

Bryan Berry

Vice President, Finance

Michael Garrett

Vice President, Accounting

Bill Smith

Vice President, HR

Maverick Bentley

SVP, Southern Ops

Bob Cayton

SVP, Northern Ops

Jack Crook

SVP, EHS

Bill Kurtz

SVP, Land & Resources

Dora Silvis

EVP, Integrations

Eric Williams

Chief Financial Officer

One Diversified

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DGOC Northern Basin DGOC Southern Basin

CONSOLIDATED APPALACHIAN FOOTPRINT

Ohio Pennsylvania West Virginia

A transformational story of building a high-quality, long life portfolio of assets

LEGEND: EQT Assets Core Assets

OVERVIEW OF SOUTHERN MIDSTREAM APPALACHIA

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• >10,500 Miles of Pipe
• Eliminates 3rd party

transport cost

• Supplemental revenue

stream provides access to value enhancing processing plant

• Market pricing optionality
• Significant NGL marketing

upside

• NGLs increase exposure to

crude oil prices.

• Provides access to strategic

NGL processing plants and

• wned processing facilities

that specifically enhance the economics of natural gas production.

Map of Midstream Operations Opportunity

Legend

Midstream Assets: Acquired from Core

Ohio Virginia

Kentucky West Virginia

2 Kermit (owned) Langley Plant (utilised) 3 1 KSP (owned) Smokehouse (owned) 1 2 3 Acquired from EQT Processing Plants:

• Substantial ~7.8 million net acres of land sparsely drilled and largely undeveloped
• Current development at >100 acre spacing
• Deemed full developed at ~20 acre spacing (i.e. 4 additional well locations per producing well)
• 150 wells drilled prior to IPO with no dry holes
• Approx. $350k/well to drill and hook up shallow gas wells
• Actively evaluating selective drilling opportunities

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ORGANIC GROWTH OPPORTUNITY

$1.6 Billion

~493 mmboe

PV-10 PDP Reserves

7x

Actual Year-to Date Daily Production Growth(a)

~70

Net Production

(~420 MMCF/D)

MBOE/D

Cash Flow Today Cash Flow Tomorrow

Note: Net Production, PDP PV-10 and PDP Reserves include Core acquisition (a) Beginning Daily Production for 2018 of 10.3 MBOEPD compared to current ~70 MBOEPD

PRODUCTION & RESERVES HIGHLIGHTS

NGL 12% Oil 1% Gas 87% PDP Commodity Mix

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Demonstrated Commitment to Low Leverage Liquidity

Feature Current Facility Facility size $1 Billion Borrowing Base(a) $720 Available Capacity $213 Interest Spread Libor + ~3% Commitment Fee 44 bps Maturity March 2023

Footnotes: (a) DGO $600mm borrowing base + Core’s $120mm borrowing base (b) Includes Cash ($18mm) less pending dividend payment ($15mm) scheduled in early December.

Debt Maturity Summary

$1 BILLION LOW-COST CREDIT FACILITY

$- $- $507 $213

$- $200 $400 $600 $800 2018 2019 2020 2021 2022 2023 Borrowings Available 30% Undrawn and Available to fund Non-Dilutive Growth

No Near-Term Maturities

Includes $93M from Core Appalachia

Available Net Cash(b) $3 Available on Credit Facility $213

Liquidity $216

Footnotes: Approximate values following the latest acquisition of Core Appalachia (a) Based on a share price of £1.06 and an exchange rate of 1.2745 as of 30 Nov 2018. Based on a share count of 542.6 million as of the 30 Nov 2018. (b) Current liquidity calculation is as of 30 Nov 2018 and exclude $1.75mm of Letters of Credit and $15mm reserved for the dividend payment scheduled for early December.

CAPITAL HIGHLIGHTS

~542M ~106M

£1.06 £0.65

~$733M ~$ 86M ~$216M ~$ 30M ~ 1.8X ~ 2.7X ~$1,239M ~$ 80M

TODAY IPO

Share Price (+63%) Market Cap(a) (~7.5x) Shares (~5.1x) Liquidity(b) (~6.2x) Leverage (~33%) Firm Value(a) (~14.5x)

TODAY IPO

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INVESTMENT HIGHLIGHTS

• Largest conventional operator in Appalachia
• ~493 MMBOE Proved Reserves
• ~$1.6BN PV-10
• Robust and expanding distribution network improving

efficiency and realized pricing

• Issued $492 million of equity
• Currently have $720 million of

combined commitments (DGOC and Core RBLs)

• 30 Nov 2018 liquidity of ~$216

million

• Broad base of wells provides

consistent, stable production and cash flows

• Long reserve life with ~40 – 50+

years remaining well life

• >99% shallow, conventional wells
• Geographically concentrated
• Demonstrated success integrating &
• ptimizing assets
• Low capital expenditures and
• perating costs
• Midstream enhanced price

realizations

• EBITDA Margins ~60%

INVESTMENT HIGHLIGHTS

FREE CASH FLOW POSITIVE STABLE, LONG-LIFE ASSET BASE STRONG BALANCE SHEET SIGNIFICANT SCALE DISCIPLINED GROWTH OPERATIONAL EFFICIENCIES

• Net production up ~15x from IPO(~70

MBoe/d)

• Seven accretive transactions since IPO
• Four equity offerings
• Net Debt/Adj. EBITDA below target

(~2-2.5x)

APPENDIX

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The Journey

Founded

‘01 ‘16 ‘10 ‘14 ‘15

‘18

~200% Gross Production CAGR from 2014

to 2018 Acquired assets

• f Diversified

Resources Inc. for$5.2mm Assets located in WestVirginia January: Raised $180mm net equity proceeds to fully fund two, transformative acquisitions in March, March: Acquired Alliance Petroleum ($95mm) and assets from CNX ($85mm). Reduced interest rate on borrowings by >50% through refinancing of existing debt while creating significant, low-cost access to add'l debt available to fund without add'l equity dilution acquisitions of ~$100mm

• f Adj EBITDA valued at

4x cashflow June: Increased borrowing baseto $600mm July: Acquired EQT conventional Appalachian assets for $575mm October: Acquired Core Appalachia for $130mm cash and 35m shares, a total market value of $183mm. EnteredOhio Acquired producing wells from AB Resourcesfor $14.5mm Acquired producing wells from Deep Resources, for $5.5mm Acquired producing wells from Operated Equity Investment (Fund 1)for $4.3mm Successfully listed bond on ISDX Growth Market, which raised £10.6mm Acquired producing wells from Broadstreet Energy for$2.6mm Acquired producing wells and equipment from Texas Keystone for $725m Acquired producing wells from Eclipse Resources for $4.8mm Acquired producing wells and pipeline assets from Seneca Resources for $7.0mm February: Floated on AIM raising $50mm – largest UK O&G IPO since April 2014 April: Acquired producing wells in Ohio and Pennsylvania for$1.75mm June: Acquired producing wells from Titan for $72.8mm; Raised additional $35mm through secondary offering onAIM September: Closed on the remaining Titan wells held within public partnership structures (incl. 29 Hz wells) for$11.4mm December: Acquired producing wellsfrom NG O for$3.1mm

544,000

Gross Mcfe/d

108,000

Gross Mcfe/d

26,000

Gross Mcfe/d

11,000

Gross Mcfe/d

‘17 6,000

Gross Mcfe/d

7,000

Gross Mcfe/d

HIGHLIGHTS OF RECENTLY COMPLETED ACQUISITIONS

21

APC ACQUISITION HIGHLIGHTS

22

$

Well Map – Alliance Petroleum

Administrative Office

~13,000 Number of Wells Net Daily Production of ~8,800 Boe/d (+86%) PDP Reserve Volumes of ~49 MMBoe (+90%) STATES: Ohio, Pennsylvania, West Virginia Increased QUALITY OF SKILLED LABOR Closed in MARCH 2018 Purchase Price $95.0 MILLION

Ohio Pennsylvania West Virginia

CNX (ASSETS) ACQUISITION HIGHLIGHTS

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Purchase Price $85.0 MILLION

$

Well Map – CNX Petroleum ~11,000 Number of Wells Net Daily Production of ~9,000 Boe/d (+87%) PDP Reserve Volumes of ~69 MMBoe (+127%) STATES: Pennsylvania, West Virginia Increased Scale Closed in MARCH 2018

Ohio Pennsylvania West Virginia

EQT (ASSETS) ACQUISITION HIGHLIGHTS

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Purchase Price $575.0 MILLION (~43% equity)

$

Well Map – EQT & DGO ~11,350 Number of Wells Net Daily Production of ~32,000 Boe/d (+114%) PDP Reserve Volumes ~233 MMBoe (+127%) STATES : Kentucky, West Virginia & Virginia Addition of Significant Midstream Assets ~ 6,400 Miles of Pipeline Closed in July 2018

Legend

DGO Assets EQT Assets Ohio Kentucky West Virginia Virginia Maryland Pennsylvania

Upstream Assets Overview

• Acquisition of approximately 2.5 million net, contiguous acres

and ~11,350 gross wellbores in Appalachia

• Acreage is ~100% HBP with both high working interests (~95%

for PDP wells) and favorable net revenue interest (~78% for PDP wells)

• High BTU gas meaningfully enhances economics of the

production stream

• Average well life of 50 years results in predictable production

profile

• Additional upside available through development rights in

shallow, conventional reservoirs

Midstream Assets Overview

• Wholly owned gathering system eliminates third party gathering

expenses

• Multiple interconnects provide access to several key markets

including TCO, TGP Zone 2, and DTI

• Enhanced margins through gathering ~40 MDth / day of third

party gas

• Significant fractionation and processing capacity supports future

development

Transaction Overview

• Adds significant scale to DGO’s existing asset base
• EQT assets generated ~$161 million of EBITDAX in 2017
• DGO acquires existing operating personnel and office space
• DGO acquires all field operations assets to support production

EQT Asset Acreage Ohio Kentucky West Virginia Virginia

Overview Map of Operations

EQT (ASSETS) DETAIL

25

Footnotes: Dekatherm (“DTH”) per day – Dekatherm equals one million British Thermal Unit (“BTU”); (b) Trillion Cubic Foot of equivalent

CORE ACQUISITION HIGHLIGHTS

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Purchase Price $183.0 MILLION (a) (~30% equity)

$

~5,000 Number of Wells Net Daily Production of ~11,000 Boe/d (+19%) PDP Reserve Volumes ~100 MMBoe (+25%) STATES : Kentucky, West Virginia & Virginia Enlarges EQT Midstream Assets ~4,100 Miles of pipeline Closed in October 2018 Well Map – CORE & DGO

BOLT ON

“EQT PART II”

(a) Purchase price of $183.0 million does not include hedge adjustment

Legend

DGOC Assets Core Assets

27

Overview Map of Operations

CORE ACQUISITION DETAIL

Upstream Assets Overview

• ~1.3MM net contiguous acres and ~5,000 gross producing wellbores in

Appalachia (across Kentucky, West Virginia, and Virginia)  Interlocks with recent EQT transaction

• Current production of ~11,000 Boe/d (~90% gas) exhibits low decline (4%)

per annum

• High BTU gas (1,230 BTU) is largely unprocessed which allows for

significant NGL marketing upside

• Nearly all gas sold on TCO which has historically traded at ~$0.30/MMBtu

improved differential over Dominion South

• Additional upside available through development rights in shallow,

conventional reservoirs

Midstream Assets Overview

• Wholly owned gathering system spans the entirety of the acreage position

and eliminates third party gathering expenses  ~4,100 miles of gathering pipeline  ~47,000 horsepower of compression

• ~26 MDthd of third party gathering volumes (Revenue of ~$9MM(a))
• Incremental ~14 MDthd of third party gas purchase volumes enhances

pipeline economics (Revenue of ~$5MM(a))

• Pro-forma for this transaction, DGO will control a vast majority of the

gathering assets in Kentucky and Southern West Virginia with over ~10,500 miles of pipeline

Transaction Overview

• Total transaction consideration of $183MM(b)

 $130MM in cash  35MM shares issued (subject to an 8-month lockup)

• Total PDP reserves of 600Bcfe(c) and $255MM PV10%(c)

 Reserve value includes assumed decommissioning PV10% ~$7MM(d)  Purchase price is ~72% of PDP PV10%

• Proposed acquisition generated ~$44MM(a) of field level cash flow

 ~$5 – 10MM of field level synergies in the immediate and near-term

• Significant SG&A cost reductions by eliminating redundancies

27

Ohio Virginia

Kentucky West Virginia

EQT Assets Core Assets

Footnotes: (a) Represents 1H18 annualized; (b) Excludes value of the acquired hedges; (c) Based on Management internal estimates prepared using Society of Petroleum Engineer standards. Reserves assume a 1 Oct 2018 effective date and strip prices as of 30 Sep 2018; (d) Assumes P&A liability of $30k per well in Kentucky and $22.5k per well in West Virginia and Virginia and 10 wells per year for years 1-5, 15 wells per year for years 6-15 then ramping in years 16-30 to a terminal rate of 92 wells per year until all wells are plugged.

Acquired As

CORE ACQ: ANTICIPATED SYNERGIES TO BE REALISED

Synergies Description Expected Results

NGL Uplift

• Redirect Core Warco volumes to Langley

Processing (connected and ready to move gas over – all facilities in place)

• Estimated 9,000 mcf/d of volumes

can be immediately redirected to Langley processing plant, producing an estimated ~$7.0 million of incremental NTM EBITDA

• Estimated headcount reduction

could reduce SG&A costs substantially ― Assuming ~$7.0 million in SG&A reduction

• Coupled with headcount reduction,

facility reduction, and potential sale of facilities could bolster revenue further

• Pro forma for this transaction,

DGOC will control a vast majority

• f the gathering assets in

Kentucky and Southern West Virginia with over >10,500 miles of pipe

Personnel Redundancy

• Meaningful headcount reduction at Core

due to overlapping job duties/processes with the recently acquired EQT Southern Appalachian assets

• Retirement age workforce will more than

likely accept severance packages versus changing companies or relocating

Facility Redundancy

• Over eight field offices that are within 20

miles of DGOC field office

Midstream Revenue

• Wholly owned gathering system spans the

entirety of the acreage position

• ~4,100 miles of gathering pipeline and

~47,000 horsepower of compression

• ~26MDthd of third party gathering volumes
• Incremental ~14Mdthd of third party

purchases enhances pipelines

✔ ✔ ✔ ✔ Total estimated synergies of $10 - $15 million

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LATEST REPORTED FINANCIALS

(HALF YEAR 2018 RESULTS)

29

~700%

Daily Production From YE-17 to Oct-18

0.6 1.8 3.5 10.6 3.5 9.9 19.3 58.6 70.0

• 10.0

20.0 30.0 40.0 50.0 60.0 70.0 80.0

• 2.0

4.0 6.0 8.0 10.0 12.0

1H17 2H17 1H18 1H18PF(a) Oct 2018

MBOEPD MMBOE Net Production Net Daily Production

Footnote: (a) 1H18PF results assumes APC, CNX, and EQT acquisition as of Jan 1, 2018;

~95%

Sequential Increase from 2H17 to 1H18

30

~27

MBOEPD Jun-18 Exit Rate

~70

MBOEPD Oct-18 Exit Rate

MULTIPLYING PRODUCTION

31

Recurring G&A(c) Commodity Revenue(b) (Unhedged; $MM)

$10.2 $29.4 $56.7 $180.4 $17.56 $16.14 $16.19 $18.46

$10.00 $15.00 $20.00 $- $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $140.0 $160.0 $180.0 $200.0

1H17 2H17 1H18 1H18PF(a)

MBOE

Commodity Revenue Realized Price per BOE(b)

$2.64 $1.84 $1.51 $1.19

$- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 1H17 2H17 1H18 1H18PF(a)

Lease Operating Expense(c)

$8.13 $6.62 $7.01 $4.52

$1.00 $2.00 $4.00 $8.00 1H17 2H17 1H18 1H18PF(a)

BOE

Footnotes: (a) 1H18PF results includes the APC, CNX and EQT acquisitions as if they closed on 01Jan2018; (b) Commodity revenue is unhedged and excludes other revenue. See appendix for Non-GAAP reconciliation. (c) LOE and Recurring G&A are presented on a Non-IFRS basis. LOE excludes gathering and transportation expenses and production taxes; G&A excludes certain non-recurring expenses. See Non-GAAP reconciliations in Appendix for calculations.

REVENUE AND EXPENSE HIGHLIGHTS

Higher Realized Price

21% 36% 14%

Lower G&A Pro Forma Lower LOE Pro Forma

Fueling Higher Margins

$3.9 $12.1 $23.3 $108.3 $0.04 $0.08 $0.09 $0.21 $- $0.05 $0.10 $0.15 $0.20 $0.25 1H17 2H17 1H18 1H18PF(a) $- $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $ Per Share $MM Adjusted EBITDA Per Share

32

a

Adj EBITDA(b) (Unhedged; in Millions) Strong Adj EBITDA Margins (Unhedged)

Footnotes: (a) Proforma results includes the APC, CNX and EQT acquisitions as if they closed on 01Jan2018; (b) See Non-GAAP reconciliations in Appendix for calculation of Adjusted EBITDA; (c) Revenue per BOE includes other revenue.

$12.03 $10.34 $9.93 $7.61 $19.03 $17.73 $16.46 $18.65

37% 42% 40%

59%

$0 $5 $10 $15 $20 1H17 2H17 1H18 1H18PF(a) Per Boe

G&A G&T Prod Tax LOE Revenue Margin

133%

Total Revenue(c) $19.03 $17.73 $16.46 $18.65 G & A $2.64 $1.84 $1.51 $1.19 G & T

• 1.53

1.21 1.52 Prod Taxes 1.25 0.34 0.20 0.37 LOE 8.13 6.62 7.01 4.52 Total OpEx $9.38 $8.49 $8.42 $6.40 Cash Costs 12.03 10.34 9.93 $7.60 Cash Margin $7.00 $7.39 $6.54 $11.05 Margin % 37% 42% 40% 59%

A B C C C D = C E = D + B F = A - E

=

/

A F

EARNINGS HIGHLIGHTS

Total

$23 $50 $15

$- $10 $20 $30 $40 $50 $60 Dividends Paid IPO Funds Raised In Millions Paid Dec-18 1.99¢ 1.99¢ 3.45¢ 1.73¢ 2.80¢ 3.98¢ 3.98¢ 6.90¢ 6.90¢ 11.20¢

4.8% 7.0% 5.9% 9.0%

0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 0.00¢ 2.00¢ 4.00¢ 6.00¢ 8.00¢ 10.00¢ 12.00¢ 2H16 1H17 2H17 1Q18 2Q18 Annualised Yield Dividend per Share Dividend Implied Annual Dividend Annualised Yield %

62%

33 Period Declare Ex-Div Pay

Q1 June September September Q2 September November December Q3 December March March Q4 March June June

75%

Higher Dividend Payouts(b)

Transitioned to Quarterly Dividends

Cumulative Dividend Payouts(a)

Footnote: (a) Includes the declared December 2018 dividend of ~$15 million; (b) 1H17 yield based on average price of 64.86 pence from 3 Feb 2017 (IPO date) to 30 Jun 2017, 2H17 yield based off average price of 74.77 pence from 1 Jul 2017 to 31 Dec 2017, 1Q18 yield based off average price of 84.76 pence from 1 Jan 2018 to 31 Mar 2018 and 2Q18 yield based on average price of 91.26 pence from 1 April 2018 to 30 June 2018.

ACCRETIVE ACQUISITIONS ENHANCING DIVIDENDS

2.1x 1.7x 1.8x $56 $136 $507 $- $100 $200 $300 $400 $500 $600

.0x .5x 1.0x 1.5x 2.0x 2.5x 31Dec17 30Jun18 30-Nov-18 $MM

Net Debt / Adj EBITDA

Leverage Multiple Net Borrowings

34

Gas and Oil Properties & Midstream Assets, net Cash and Liquidity (in Millions) Leverage; Borrowings Total Equity

$10 $3 $54 $213 30-Jun-18 30-Nov-18

Cash Credit Availability

$90 $302 $552

$- $100 $200 $300 $400 $500 $600

31Dec17 30Jun18 30Jun18PF(a)

$MM

30Jun18 PF(a) 30Jun18 31Dec17 30Jun17

$64 MM $216 MM

236% 82% 238% 118% 155%

Footnotes: 30Jun2018PF assumes that the APC, CNX and EQT acquisitions were completed on 01Jan2018; (b) 30Nov2018 liquidity reflects $18mm of cash reduced by $15mm for scheduled December dividend payment plus $213mm available on the current revolving credit facility; (c) Net Debt / Adj EBITDA for 30Jun2018 includes net debt less the $57.5MM deposit for the EQT acquisition that closed in July 2018 and 1H18 Adj EBITDA (Pre-EQT) annualized; 30Nov2018 Leverage of 1.8x is based on October 2018 adjusted EBITDA annualized ($23.6mm x 12 months = $283.2mm).

BALANCE SHEET HIGHLIGHTS

ADDITIONAL HEDGES DETAIL

35

Deferred Premium Puts

Footnote: (a) Hedge contracts as of mid November 2018; Overall weighted averages for both physical and financial natural gas basis hedges, basis hedges primarily couple with financial NYMEX hedges to establish a net realized price, many fixed physical contracts establish an ‘all-in’ price and therefore include the effect of a basis hedge. (b) FY21 values are for Jan21 – Jul21 only. There are no hedges in the portfolio beyond Jul21, though the Company is presently adding hedges through Dec21.

36

Hedge Contract Structure

Financial Hedges

~$2.80 Wtd. Avg. Floor (before Basis Differentials)

Utilize mix of financial hedges and fixed physical contracts to protect cash flow. Fixed Physical Contracts include basis differentials and represent the all-in price received. Financial Hedges fix the NYMEX price and will be reduced by basis differentials, which are hedged at an average of ~$0.50.

Natural Gas Basis Hedges(a) Natural Gas Financial Hedges(a) Physical Contracts

~$2.30 Wtd. Avg. Floor (All-in Price; incl. Basis) $2.98 $2.89 $2.75 $2.75 $2.74 $2.66 $2.67 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50

• 40,000

80,000 120,000 160,000 200,000 240,000 4Q18 1Q19 2Q19 3Q19 4Q19 FY20 FY21(b) NYMEX Hedge Volume (MMBtu/day) Wtd Avg Floor Price ($/MMBtu) ($0.36) ($0.40) ($0.43) ($0.56) ($0.56) ($0.56) ($0.47) ($0.75) ($0.50) ($0.25) $0.00

• 20,000

40,000 60,000 80,000 100,000 4Q18 1Q19 2Q19 3Q19 4Q19 FY20 FY21(b) Volumes (MMBtu/day) Wtd Avg Basis Price ($/MMBtu)

Fixed Physical Contracts(a)

$2.38 $2.51 $2.32 $2.35 $2.34 $2.33 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00

• 25,000

50,000 75,000 100,000 125,000 4Q18 1Q19 2Q19 3Q19 4Q19 FY20 FY21(b) Physical Sales Volume (MMBtu/day) Fixed Price ($/MMBtu)

52% 45% 3% Costless Collars Swaps

3%

HEDGED TO PROTECT CASH FLOW AND DIVIDEND

37

Financial Contracts Physical Contracts Combined Contracts

Footnote: Hedge Contracts as of Mid November 2018; (a) FY21 values are for Jan21 – Jul21 only. There are no hedges in the portfolio beyond Jul21, though the Company is presently adding hedges through Dec21.

NATURAL GAS HEDGE DETAIL(a)

38

Price Protection of ~$36.62/Bbl for ~36 months(b) Hedge Contract Structure

Footnote: Hedge Contracts as of Mid November 2018. The Company generally hedges NGLs for over an 18-month period vs. 36 months for natural gas and oil; (a) FY21 values are for Jan21 – Jul21 only. There are no hedges in the portfolio beyond Jul21; (b) Price protection per Bbl is presented as a simple average over 36 months.

$38.28 $38.78 $36.38 $36.25 $36.76 $35.95 $33.98

$0.00 $5.00 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00

• 1,000

2,000 3,000 4,000 5,000 6,000 4Q18 1Q19 2Q19 3Q19 4Q19 FY20 FY21

BBL per Day

NGL Hedges

NYMEX Hedge Volume (BBL/day) Wtd Avg Floor Price ($/bbl)

100% Swaps

NGL HEDGES (a)

39

Price Protection of ~$51.15/Bbl for ~36 months(b) Hedge Contract Structure

Footnote: Hedge Contracts as of Mid November 2018; (a) FY21 values are for Jan21 – Jul21 only. There are no hedges in the portfolio beyond Jul21, though the Company is presently adding hedges through Dec21; (b) Price protection per Bbl is stated as a simple average over 36 months.

$50.73 $49.77 $51.60 $51.18 $50.89 $48.43 $55.49

$0.00 $10.00 $20.00 $30.00 $40.00 $50.00 $60.00

• 100

200 300 400 500 600 700 800 4Q18 1Q19 2Q19 3Q19 4Q19 FY20 FY21

BBL Per Day

Crude Oil Hedges

NYMEX Hedge Volume (BBL/Day) Wtd Avg Floor Price ($/bbl)

19% 81% Swaps Costless Collars

OIL HEDGES (a)

PLUGGING & ABANDONMENT

40

3,150 1,846 4 18,357 17,460 8,027 8,811 5,398 2,125 Pennsylvania Coal West Virginia Ohio Kentucky Pennsylvania Non-Coal Misc.

41

Commentary Well Map(a) Well Count

(b)

DECOMMISSIONING PORTFOLIO CONSIDERATIONS

Location

Legend

Horizontal Wells Kentucky Misc. Ohio PA Coal PA Non-Coal Virginia West Virginia

Average Depth (ft)

3,621’ 4,284’ 4,173’ 4,188’ 3,621’ 5,321’

Average Cost ($k)

$25.0 $22.5 $20.0 $30.0 $20.0 $20.0-$30.0, $60.0(d)

Footnotes: (a) Map does not include wells acquired in Core acquisition; (b) lighter shaded areas represent increase in well count from the Core acquisition; (c) Includes deep vertical and horizontal wells; (d) Represents estimated P&A cost for ~600 deep vertical and horizontal wells

(c)

Newly acquired wells

• Over 80% of DGO’s well portfolio will cost less than $25,000 to

plug.  The higher cost, horizontal wellbores are among the younger wells that DGO possesses thus will be plugged towards the end of its program (beyond 2090).  DGO has plugged 41 wells to date through 30Nov18 at an average plugging cost of ~$23,800/well plugged in 2018.

42

ESTIMATED PLUG PROGRAM

• DGO has or is negotiating

firm multi-year plugging agreements with the states in which it operates. ― Years 1-5 assume 90 wells plugged per year ― Years 6-15 assume 130 wells plugged per

year

• These agreements eliminate

variability and the risk of the liability being pulled forward. ― ~33% of DGO’s P&A PV10% capture in years 1 – 15

• For modeling purposes,

DGO assumes a linear increase in wells plugged per year between years 15 – 30 ― Thereafter, the company anticipates plugging ~1,100 per year

Cumulative PV10% Graph Commentary

15 year plugging program

DGO expects to negotiate long term, ~15 years plugging agreements with the states in which it operates.

PV-10% = $53MM >16% wells remain productive

43

ACCOUNTING DECOMMISSIONING LIABILITY

Footnote: (a) The Livingston Survey June 2018.

$53 $151 $36 $62

Reserve Report at PV10% Inflation factor

• f 2.2%

Discount Rate

• f 8.0%

Balance Sheet Entry

PV Bridge

• DGOs plugging program

used in the reserve report was adjusted for the balance sheet, as recommended in accounting guidance ASC 410-20 & IAS 37.

• ASC 410-20 / IAS 37

require the ARO liability to be risked and discounted using a credit-adjusted risk- free rate. The credit- adjusted risk-free rate is calculated using observable rates of interest of other

• liabilities. Furthermore, an

inflation factor should be considered.

• DGO estimated their credit-

adjusted risk-free rate to be 8.0% (which is set when the ARO is valued and left unchanged), and used a 2.2%(a) inflation factor.

Commentary