MOUNTAIN RESOURCES March 2018 Forward-Looking and Cautionary - - PowerPoint PPT Presentation

BLUE RIDGE MOUNTAIN RESOURCES

March 2018

Forward-Looking and Cautionary Statements

2

In general. Blue Ridge Mountain Resources, Inc., together with its subsidiaries and affiliates, is referred to in this presentation (this “Presentation”) as “BRMR” or the “Company.” This Presentation has been prepared by the Company for BRMR’s stockholders and their potential transferees, solely for informational purposes. No offer to purchase or sell securities. This Presentation does not constitute an offer to sell, or a solicitation of an offer to buy, any security and may not be relied upon in connection with the purchase or sale of any security. You are cautioned against using this information as the basis for making a decision to purchase or sell any security. Forward-looking statements. This Presentation contains forward-looking statements regarding the Company, based on the Company’s current expectations, and includes statements regarding acquisitions and divestitures, estimates of future production, future results of operations, quality and nature of assets, the assumptions upon which estimates are based and other expectations, beliefs, plans, objectives, assumptions, strategies or statements about future events or performance (often, but not always, using words such as “expects”, “projects”, “anticipates”, “plans”, “estimates”, “believes”, “intends”, “potential”, “possible”, “probable”, “forecast”, “guidance”, “outlook”, or “target”, or stating that certain actions, events or results “may”, “will,” “should” or “could” be taken, occur or be achieved). Statements concerning oil and gas reserves also may be deemed to be forward-looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to: (i) inability to complete anticipated joint ventures, joint development transactions or acquisitions or to realize expected value from joint ventures, joint development transactions or acquisitions; (ii) inability of the Company to execute its plans to meet its goals; (iii) the risks of the oil and gas industry (for example, operational risks in exploring for, developing and producing natural gas, natural gas liquids and crude oil; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects, including unexpected cost increases or technical difficulties in connection with exploration or development activities; changes in plans with respect to capital expenditures; health, safety and environmental risks including potential liability for remedial actions under environmental laws; and risks related to weather such as hurricanes and other natural disasters); (iv) uncertainties as to the availability and cost of capital, including borrowings under the Company’s credit facility; (v) fluctuations in oil and gas prices; (vi) risks associated with derivative positions; (vii) inability to complete anticipated joint ventures, joint development transactions or acquisitions or to realize expected value from joint ventures, joint development transactions or acquisitions; (viii) inability of the Company to execute its plans to meet its goals; (ix) shortages of drilling equipment, oil and gas field personnel and oil and gas field services; (viii) unavailability of gathering systems, pipelines and processing facilities; and (x) potential liability resulting from pending or future litigation; and (xi) the possibility that government policies may change or governmental approvals may be delayed or withheld. You are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking

• statements. Forward-looking statements are based on the estimates and opinions of Company management at the time the statements are made. The

Company does not assume any obligation to update forward-looking statements should circumstances or management’s estimates or opinions change. No reliance, no update and use of information. You should not rely on this Presentation as the basis upon which to make any investment decision concerning BRMR’s common stock. To the extent that you rely on this Presentation in connection with any such investment decision, you do so at your own risk. This Presentation does not purport to be complete on any topic addressed and the information contained in this Presentation may not provide, and is not intended to provide, all information that may be relevant to an investment decision with respect to BRMR’s common stock. The information contained in this Presentation is provided to you as of the dates indicated and circumstances may have changed since those dates. The Company undertakes no duty to update the information contained in this Presentation, even in the event that the information becomes materially inaccurate.

Forward-Looking and Cautionary Statements

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Additional information; investor website. In accordance with the requirements of BRMR’s stockholders agreement (the “Stockholders Agreement”), BRMR makes certain information available to its stockholders and their prospective transferees on a password protected investor website. The information available on BRMR’s investor website includes the Company’s quarterly and year-end financial results. In order to access BRMR’s investor website, you must confirm to BRMR that you are a stockholder, or a prospective transferee of a BRMR stockholder, and agree to abide by the terms of the Stockholders Agreement regarding confidentiality. If you are a BRMR stockholder, or a prospective transferee of a BRMR stockholder, and desire to access BRMR’s investor website, please contact ir@brmresources.com by email for assistance. Non-reporting issuer. BRMR’s common stock is not registered under Section 12 or subject to Section 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Company is not subject to the periodic and current reporting requirements of Section 13 or Section 15(d) of the Exchange Act. The periodic financial and other information provided on the Company’s investor website does not contain all of the information that would be required to be filed with the U.S. Securities and Exchange Commission by an issuer pursuant to Form 10-K, Form 10-Q or Form 8-K under the Exchange Act or in any registration statement under the Securities Act of 1933, as amended. Restrictions on transfer. BRMR’s common stock is subject to certain restrictions on transfer set forth in the Stockholders Agreement and under applicable law. Non-GAAP financial measures. This Presentation may contain certain financial measurements not recognized under accounting principles generally accepted in the United States, or “GAAP.” You are advised that this Presentation does not contain reconciliations of non-GAAP financial measures to financial measures of performance prepared in accordance with GAAP. These non-GAAP financial measures should not be considered substitutes for their directly comparable GAAP financial measures. You are strongly encouraged to review the Company’s consolidated financial statements in their entirety and not to rely on any single financial measure. Reserve estimates. This Presentation contains information concerning the Company’s proved reserves, which are those quantities of natural gas and oil that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. In this Presentation, the Company also provides information concerning “Resources,” which includes “probable reserves,” “possible reserves” and “contingent resources,” which represent the Company’s internal estimates of volumes of natural gas and oil that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. The term “contingent resources” is a broader description of potentially recoverable volumes than probable and possible reserves. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the Company. Such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. Knowledge and experience. You acknowledge that you are knowledgeable and experienced with respect to the financial, tax and business aspects of the information contained in this Presentation and that you will conduct your own independent financial, business, regulatory, accounting, legal, and tax investigations with respect to the accuracy, completeness and suitability of the information contained in this Presentation should you choose to use or rely

• n such information, at your own risk, for any purpose.

No tax, legal, accounting or investment advice. This Presentation is not intended to provide, and should not be relied upon for, tax, legal, accounting or investment advice. Any statements of federal tax consequences contained in this Presentation were not intended to be used and cannot be used to avoid penalties under the Internal Revenue Code or to promote, market or recommend to another party any tax related matters addressed herein.

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Pure play Utica and Marcellus Exploration & Production Company Production 60 mmscfe/d

79% Natural Gas

Proved reserves 377 bcfe Resource 5.3 tcfe Net Undeveloped Acres 89,000

88% HBP’d

Net Effective Acres 119,000

53% Utica

Remaining Locations > 700 Gross Debt $25 million

$25 million undrawn

Cash $110 million OTC Ticker BRMR Corporate Office Irving, TX

Blue Ridge Mountain Resources

Activity (Dec 31st) 2 Operated Rigs 2 Non-operated Rigs

Notes: All figures as of Dec 31, 2017 Pro-forma for discontinued operations, 2018/2019 net lease expiries and the Ohio AMI transaction described on page 9 herein. Cash excludes cash from the Ohio AMI transaction. Resource based on BRMR internal assessment.

Marcellus/Utica Experience (yrs)

John Reinhart

11 President & CEO

Michael Koy

7 EVP & CFO

Paul Johnston

8 SVP & General Counsel

Matt Rucker

11 VP Resource Development

Mike Horan

12 Mgr - Operations (Legacy)

Daren Rader

11 Mgr - Operations (Unconventional)

Chris Hutchison

8 Director - Midstream & Marketing

Darrel Overgaard

6 Director - Drilling & Completions

Brittany Doversberger

4 Corporate Controller 7 yrs. of experience in energy marketing, including contract administration, gas scheduling, strategic commercial and financial evaluation. Former lead marketing representative at Chesapeake Energy focusing on Utica Shale. 26 yrs. oil & gas experience with Chesapeake, Shell and Unocal both domestic and international in drilling and completions. Over 400 wells drilled in the Utica and Marcellus. 8 yrs. experience in North American Oil & Gas accounting, financial reporting and corporate controllership. Former Audit In-Charge at Deloitte & Touche. 25 yrs. of experience in the oil and gas industry, with the last 10 yrs. focused on the Marcellus & Utica shales. Former EVP & COO of Ascent Resources and SVP Operations & Technical Services at Chesapeake Energy. 25 yrs. oil & gas experience in strategy & planning, budgeting, M&A, midstream, finance and operations. Held various roles at EdgeMarc Energy and formally was VP Commercial North America at Talisman Energy. Over 35 yrs. of experience in general corporate, finance, securities and regulatory-related legal matters. Former partner with the Dallas-based law firm, Thompson & Knight and former counsel with Centex Corporation. Former Production Superintendent for Chesapeake Energy's Utica Shale

• production. Held several engineering positions within Chesapeake’s Utica &

Marcellus Shale teams, focused on joint ventures, A&D, and resource planning. 17 yrs. experience in upstream oil & gas drilling and operations with Energy Acquisition Corp. and Pennzoil. Over 10 yrs. oil & gas experience with Ascent Resources as Manager of Operations, Production Manager at Antero and various production and engineering positions at Chesapeake Energy.

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Leadership Team

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Strategy

2 Operated Rigs 1-2 Non-operated Rig Add Acreage & Inventory Maximize Growth Trajectory Evaluate Strategic Options

1H18

1.5 Operated Rig 1 Non-operated Rig Secured line of credit Add acreage & inventory Evaluate Strategic Options

2H18

Blue Ridge Mountain Resources is positioned to become a leading operator in the Appalachia Basin that performs in the top quartile of EHS, operational and financial performance

• Utica and Marcellus pure play
• 2.5-4 rig development program concentrated on highest return Marcellus and Utica core acreage and

delineation of core fringe acreage

• Land strategy that further consolidates and extends/renews high value core acreage for future

development

• Enhance core acreage position via bolt-on acquisitions that facilitate accelerated development, longer

laterals, increased wells per pad and other operational synergies

• Selectively partner to accelerate development of core acreage
• Evaluate strategic options to maximize value from concentrated position with clean balance sheet,

material production balanced between rich & dry gas exposure, minimal FT commitments and a low risk, ready to drill, well inventory close to advantaged gathering infrastructure

7

BRMR Value Proposition

Advantaged Asset Base Top Tier Operator Growth Potential Strong Financial Position Experienced Management Team

• 119,000 net effective acres across the Utica and Marcellus in WV and OH
• 700+ gross well locations = 20+ year inventory with a 2 rig program
• Close to gathering infrastructure with access to numerous marketing hubs
• Optimized development program that prioritizes highest return projects
• Unlocking operational efficiencies to improve economics and lower unit costs
• Creating opportunities to prove up development
• Ready-to-develop inventory with strong economics
• Achievable upside from stacked pay zones
• Regional aggregator with significant opportunities to increase footprint
• Clean balance sheet with access to additional capital and liquidity
• Capital efficiency via use of existing pads, new and existing infrastructure
• Positioned to self-fund growth
• Drilled over 1,200 Utica / Marcellus wells
• Operated over 2.5 bcfe of production in the Utica / Marcellus
• Over $10 billion in oil & gas transactions closed

2017 Corporate Accomplishments

8

Divestments of $95 million

17 transactions

Replaced Letters of Credit totaling $21 million

Released $22.5 million in cash Lowered interest rate from 3.5% to 1.8%

Secured 1st Lien Term Loan

$25million initial draw with $25 million delayed draw Lowered interest rate from 16.6% to 8.3%

Reduced debt by $34 million Increased cash from $28 to $110 million Reduced cash G&A from $22 to $18 million Reduced HP gathering fees by over 30% Settled numerous predecessor disputes Eliminated 15 corporate entities Reduced Gross A/R from $17 to $3 million Finalized JV with offset operator Initiated Development Drilling Program No Recordable EH&S Incidents/LTI’s

Summary

• Buyer to acquire 40% working interest

in 21,000 net acres

• 3 year JDA / AMI
• BRMR operator
• Purchase price = $56 million ($6,000

primary term- $7,500 secondary term, per acre)

• Rights to participate in future acreage

acquisitions within AMI boundary (red)

• Utilizes BRMR gathering agreement

for all production Benefits

• Maintains same development footprint
• Buyer to fund proportional share of

acreage renewal costs (through JDA)

• Reduces 2018 capital and land costs by

~$35 million with limited impact to 2018 production

• Significantly increases liquidity and
• ptionality

Timeline

• Expected close in Apr, 2018
• Subject to closing conditions and

customary closing adjustments 9

Transaction Update – OH AMI

Dilution of 40% working interest in 21,000 net acres $6,000 primary term- $7,500 secondary term, per acre Increases 2018 liquidity by over $90 million No reduction in volumes committed to gathering

4Q17 Results – Continuing Operations

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61.7

Production mmscfe/d

3.45

Average Realized Price $/mscfe

19.6

Revenue $millions

2.8

Production Costs $millions

0.50

Production Costs $/mscfe

Relative to 3Q17 Production decreased 4.7% primarily due to natural production decline Average Realized Price increased 6.8% primarily due to higher NGL prices Revenue increased 2% due to higher prices partially offset by lower production Production Costs decreased 15% due to production decline and field optimization Unit Production Costs decreased 9% due to production decline and field optimization

Note: Continuing Operations excludes MHP results

Category Locations Oil Natural Gas NGLs Total NPV kbbls mmcf kbbls mmcfe $ millions PDP 307 386 174,073 7,416 220,885 $98.2 PNP 3 83 9,811 571 13,735 $13.6 PUD 21 947 110,985 4,231 142,051 $43.6 Total 331 1,417 294,868 12,217 376,671 $155.4

Proved Reserves

11

Notes:

• As of 12/31/17
• All figures based on continuing operations only
• All figures calculated based on SEC assumptions with NYMEX natural gas prices
• For figures calculated on a net present value basis, the discount rate = 10%

Oil Gas NGL

by Commodity

PDP PNP PUD

by Reserve Category

PDP PNP PUD

by NPV

Proved Reserves Waterfall – 2Q17 to 4Q17

12 $155

$119 $15 $24

• $3
• $12

$25 $0 $0

• $13

$0 $20 $40 $60 $80 $100 $120 $140 $160 $180

2Q17 Pricing Technical Revisions P&A Costs Reclassification

• f Proved to

Unproved Extensions, discoveries, and

• ther additions

Purchase of properties Sales of properties Production 4Q17

PV10 ($MM)

NPV Reconciliation

377

328 11 9

• 22

52

• 2

100 200 300 400 500 600

2Q17 Pricing Technical Revisions P&A Costs Reclassification

• f Proved to

Unproved Extensions, discoveries, and

• ther additions

Purchase of properties Sales of properties Production 4Q17

Net Equiv. Reserves (Bcfe)

Reserves Reconciliation

Notes:

• All figures based on continuing operations only
• All figures calculated based on SEC assumptions with NYMEX natural gas prices

Wells Oil Natural Gas NGLs Total NPV kbbls mmscf kbbls mmcfe $ millions Proved 331 1,417 294,868 12,217 376,671 $213.6 PDP 307 386 174,073 7,416 220,885 $135.3 PDNP 3 83 9,811 571 13,735 $16.5 PUD 21 947 110,985 4,231 142,051 $61.9 Probable 65 1,155 469,145 3,368 496,284 $101.2 Possible 630 33,537 3,600,204 98,122 4,390,156 $343.6 Total 1,026 36,109 4,364,217 113,707 5,263,110 $658.4 Developed 310 470 183,884 7,986 234,620 $151.8 Undeveloped 716 35,639 4,180,334 105,720 5,028,491 $506.6

3P Reserves

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Notes:

• As of 12/31/17
• All figures based on continuing operations only
• All figures calculated at NYMEX natural gas prices and internal assumptions for future operating costs and natural gas basis
• Development based on a 2 rig operated development program which began in Sep. 17 on a portion of the company’s existing acreage
• For figures calculated on a net present value basis, the discount rate = 10%

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Commodity Hedging Summary

Note: As of Jan 1, 2018

Natural Gas Propane

Natural Gas (2018)

• >60% of expected natural

gas production hedged

• 85% hedged as collars
• Average floor price of

$3.03 mmbtu Natural Gas Liquids (2018)

• >25% of expected

propane production hedged

• Average swap price of

$0.84/gal

0.40 0.50 0.60 0.70 0.80 0.90 1.00

• 100

200 300 400 500 600 1Q18 2Q18 3Q18 4Q18 1Q19 Propane Prices (Mt. Belvieu, $/gallon) Hedged Volume (bbls/d) Collar Swap Floor Ceiling Swap 2.00 2.50 3.00 3.50 4.00

• 20

40 60 80 1Q18 2Q18 3Q18 4Q18 1Q19 Natural Gas Price (NYMEX, $/mmbtu) Hedged Volume (mmbtu/d) Collar Swap Floor Ceiling Swap

Update: Operations

15

Development: Operated

Upper Ormet (Utica)

• Finished composite frac plug drillouts (post frac) and started production facility commissioning 2/29
• Begin flowback operations on 3/11
• Production ramp during flowback moderated due to realized water rates; full rate achieved 3/19
• Monitoring water rates and pressure drawdown to maximize productivity (flowing ~19 mmcf/d per well @ 7,200 psi)

Lower Ormet (Utica)

• Batch Drilling 4 top-holes in progress
• Ormet 4-9UH rig released on 2/26
• Ormet 5-9UH rig released on 3/12
• Ormet 6-9UH rig released on 3/25
• Ormet 7-9UH in progress
• Drill laterals
• Rig release 4/7 (est.)

Wells Meckley Pad Wells Meckley (Marcellus)

• Zipper frac operations began 2/24 on 1401,

1402, and 1403 wells

• Completed 136 stages averaging 7.8 stages

per day (150’ stages @ 1,800 #/ft)

• Switched over to frac the 1404, 1405, and

1406 wells on 3/13

• Estimated frac completion date 4/5
• Estimated May TIL

Update: Operations

16

Development: Operated

Pool (Utica)

• Well pad build complete 3/15;

approved by ODNR 3/19

• Conductors set and cemented on 3/22
• Rig mobilization in progress
• Spud on 3/27

Lower Ormet Pad

Development – Non-Operated

Isaly (Statoil) (Utica)

• Completions on-going
• Anticipating June TIL

Hannibal Unit (Eclipse Resources) (Utica)

• Proposals received week of 3/12
• Well pad build to be completed 4/1
• Rig mobilization to begin 4/20

Update: Utica Retrograde 0-40 Area

17 Summary Locator Map Single Well Economics(1) Type Curve Rate Comparison (1)

10% 31% 0% 5% 10% 15% 20% 25% 30% 35%

IRR

Previous Updated

BRMR recently completed & turned-in-line 2 wells averaging 5,600’ utilizing latest generation frac design

• Flat IP per well averaging 5.5 mmcf/d; 60 bbl/MM condensate

yield on restricted choke management Initial results are very strong, outperforming the existing type curve rate by as much as 25% on an equivalent basis

• Initial condensate yield of 60 bbl/MM compared to expected

20 bbl/MM places this area in a more liquids rich window BRMR expects to see similar well performance & economics in the 6,700 net acres immediately offsetting the Farley unit

• Acreage is largely contiguous with 1 pad location already built
• There are approximately 45 gross/40 net remaining locations
• Close proximity to existing gathering infrastructure

BRMR is continuing to evaluate the impact to the remaining 6,500 net acres in the lean condensate area

100 200 300 400 500 600 700 800 900 1,000 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 5 10 15 20 25 30

Oil Rate, Bbld Gas Rate, Mcfd Time Produced, Months

1) Prorated based on 10,000 lateral length Based on:

• Gas price = $3.0/mmbtu
• Oil price = $60/bbl
• BRMR internal cost and

basis assumptions

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2018 Plan

Focus

• Core asset Development
• Retrograde 0 – 40 (rich Utica) production

assessment January 2018

• Increase dry gas production and Marcellus

rich gas production

• Strong delivery…within technical limits
• Continue adding developable acres to core
• Maintain:
• Value creation flexibility
• Liquidity – live within means
• Egress flexibility
• Position for growth
• Acquire acreage and accelerate

Activity

• 1 operated rig continuous drilling program
• 2nd operated rig scheduled for 2018 (1Q-2Q, 4Q )
• 1-2 effective non – operated rigs
• Development within core area:
• Rich gas Marcellus wells
• Dry gas Utica wells
• Production assessment
• Rich gas Utica wells
• Gathering, processing and transportation

agreements in place for 100% of 2018 production

• Position for secured credit facility in 2H18
• Divest remaining non-core assets

Production of 110 – 135 mmscfe/d

Notes: EBIDTAX based on forward curves as of Jan 2, 2018

2018 Activity & Development

19

Gathering, Processing & Transportation

20

Rich Gas

• Gathered via Eureka Midstream and

delivered to Markwest Mobley facility

• Retrograde 0-40 (Farley well pad)

transported via Blue Racer and delivered to Natrium facility Residual gas – Markwest Mobley Point

• 50,000 mmbtu/d delivered via

Equitrans Ohio Valley Connector to M2, Clarington, REX, Others

• Balance delivered to TCO

Residual gas – Ohio Points

• Gathered via Eureka Midstream and

delivered to M2, Clarington, REX, Others

• 50,000 mmbtu/d delivered via Rex to

Lebanon (OH) and Shelby (IN)

• Assessing firm transportation options

for an additional 50,000 mmbtu/d

• Balance marketed in basin

NGLs

• Marketed at fixed differentials

relative to Mt Belvieu

Production Total mmscfe/d 110

• 135

2.0

• 2.5

3.0

• 4.0

Natural Gas mmscf/d 90

• 110

1.8

• 2.0

NGLs bbls/d 3,000

• 4,000
• Condensate/Oil

bbls/d 350

• 400

30

• 40

Price Natural Gas Basis $/mmbtu (0.25)

• (0.35)

(0.50)

• (0.60)

Condensate Differential $/bbl (8.00)

• (8.25)
• NGL Prices as a % of WTI

% 65%

• 70%
• NGL Basis

$/bbl (4.00)

• (4.50)
• Operating Costs

Production Costs $/mcsfe 0.25

• 0.30

4.25

• 4.50

Severance Tax % of Revenue 2%

• 3%

2%

• 3%

Gathering, Processing & Transportation $/mcsfe 1.40

• 1.50

0.35

• 0.40

Expense G&A $ millions 13.5

• 14.5

Capital Costs Development $ millions 175

• 200

Activity Gross Wells - Spudded number 30

• 35

Gross Wells - TIL number 25

• 30

Divestments Total $ millions 60

• 70

Corporate Unconventional Legacy

• Disc. Ops

2018 Full Year Guidance

21

Notes: NGL prices as a % of WTI and NGL basis assume ethane rejection for 85% of NGL production Prices based on forward curves as of Jan 2, 2018 Expense G&A excludes non-cash items and G&A for Discontinued Ops Finance G&A (with non-cash) guidance for 2018 is $16.0 – $17.0 million Gross wells includes operated and non-operated activity Pro-forma for discontinued operations divestment timing, Ohio AMI transaction described on page 9 herein, and contemplated strategic acquisitions of working interest in Marcellus/Utica properties

50 100 4Q17 1Q18 2Q18 3Q18 4Q18 PDP Dev - Op Dev - Non-Op 100 200 4Q17 1Q18 2Q18 3Q18 4Q18 PDP Dev - Op Dev - Non-Op

22

2018 by Quarter

Production (mmscfe/d) Capital Cost ($ millions)

Well Pads 4% Drilling 42% Completions 48% Facilities 4% Other 2%

2018: 110 - 135 mmscfe/d 2018: $175 - 200 million

Notes: 4Q estimate as of Jan 1, 2018 based on BRMR assessment Pro-forma for discontinued ops, Ohio AMI transaction described on page 9 herein, and contemplated strategic acquisitions of working interest in Marcellus/Utica properties

1 2

23

2018 Sources & Uses of Cash

Sources Uses

Add’l Debt Capacity (3Q) Undrawn Debt Capacity Other Non-Revenue Divestments Operations Cash Optionality Development Capital Maintained Cash Balance

110 25 50-60 60-70 10-15 40 175-200

All figures in $ millions

Notes: Oil (WTI), natural gas (NYMEX) and NGLs (Mt Belvieu) prices based on the respective forward curves as of Jan 2, 2018 Pro-forma for discontinued ops, Ohio AMI transaction described on page 9 herein, and contemplated strategic acquisitions of working interest in Marcellus/Utica properties Add’l debt capacity based on BRMR internal assessment.

2017 2018 2019 2020 2017 2018 2019 2020

Where are we Heading

24

Production (mmscfe/d) EBITDAX ($ millions)

Well Inventory and liquidity to underpin 50-70% Y-o-Y production growth

Notes: Prices: Gas = $3.00/mmbtu, Oil = $60/bbl, NGLs = 55% of WTI Pro-forma for discontinued ops, Ohio AMI transaction described on page 9 herein, and contemplated strategic acquisitions of working interest in Marcellus/Utica properties Add’l debt capacity based on BRMR internal assessment. 2019/20 based on 2 operated rigs and 1-2 non-operated rig program 2017-2020 based on BRMR internal assessment

25

Throughout 2018 we expect to…

• Consolidate asset base around the Utica/Marcellus core acreage
• 4Q17 to 4Q18
• +200% increase in production
• ~25%-30% reduction in forecasted operating costs
• Delineate Retrograde 0-40 area, technically assess Ritchie County WV area, and

begin production from the Dry Gas Central core acreage

• Develop track record based to source incremental capital
• 5 quarters of operating activity
• 3 quarters of drilling activity and acreage delineation
• Create a company that is proportional in terms of
• Material, but sustainable, production
• Remaining well inventory of 700+ wells
• Reasonable scale of upside areas
• Leveraged and balanced midstream/financial commitments
• Positioned for growth: Acquisition and increased development pace

Supplemental Information

26

Type Curves

27

Notes: Based on BRMR internal assessment

Dry Gas East Dry Gas Cen tral Dry Gas West Wet Gas Retrograd e 0- 40 Retrograd e 40- 200 Volatile Oil Retro M

• n

roe Retro Tyler Retro Wetzel Retro West Ritchie Lateral Spacing ft 1,0 1,0 1,0 1,0 8 50 750 750 750 750 750 750 750 Lateral Length ft 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 10 ,0 IP - Wellhead m m scf/d, bbl/d 14 .0 11.0 10 .0 10 .0 8 .0 4 .7 4 6 .7 9 .3 7.7 4 .7 6 .5 EUR - Wellhead bcf 21.5 16 .1 12.9 12.9 7.9 6 .5 4 .8 9 .7 12.8 16 .1 7.4 14 .2 EUR - Total bcfe 21.5 16 .1 12.9 12.9 9 .6 8 .5 6 .4 14 .1 15.8 17.7 10 .3 15.6 Condensate Yield, GOR bbls/m m scf, scf/bbl 20 120 3,333 10 4 10 10 4 Residual Heating Value btu/scf 1,0 30 1,0 30 1,0 4 1,0 6 1,10 1,10 1,10 1,10 1,10 1,10 1,10 1,10 Well Cost $ m m 8 .8 8 .8 8 .8 8 .8 8 .2 8 .2 8 .2 7.8 7.8 7.8 7.8 7.8 Well Cost $ /ft. 8 76 8 76 8 76 8 76 8 16 8 16 8 16 777 777 777 777 777

Marcellus Type Curve Areas

28

• Rich gas window in West Virginia and

Ohio

• Extensive inventory of low-risk

development drilling locations

• Primarily Operated
• 63,000 net acres
• 61 producing wells
• Ohio = 4
• West Virginia = 57
• Remaining gross well locations > 340
• Close to existing infrastructure with

limited buildout required

• Access to numerous egress options

Note: Producing wells as of Dec 31, 2017

Utica Type Curve Areas

• Dry and rich gas windows in Ohio and

West Virginia

• Significant exploration potential in

the wet/dry gas window

• Primarily Operated
• 56,000 net acres
• 6 producing wells
• Ohio = 5
• West Virginia = 1
• Remaining gross well locations > 360
• Close to existing infrastructure with

limited buildout required

• Access to numerous egress options

29

Note: Producing wells as of Dec 31, 2017

Retro West Retro Tyler Retro Monroe Retrograde 0-40 Dry Gas Central Dry Gas East 59 35 20 62 38 25 73 44 23 67 45 31

Gas $3.25 (HH) Gas $3.50 (HH)

Single Well Economics

30

Utica Marcellus IRR (%)

Notes: Lateral length = 10,000 ft Discount rate = 10% Working Interest = 100%, NRI = 80% Prices: Oil = $60/bbl, NGLs = 63% of WTI (Marcellus), 45% of WTI (Utica)

Upper Ormet

2 Utica

Lower Ormet

4 Utica

Stewart Winland

1 Utica

Jackson 10

5 Utica

Forni S

6 Utica

Farley

3 Utica

Wells Meckley

6 Marcellus

Pool

4 Utica

Upper Ormet

5 Marcellus

3Q19 4Q19 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19

31

Drilling Schedule - Operated