June 2017 – RBC Global Energy & Power Executive ConferenceNYSE MKT: SRCI

Corporate Presentation

Forward looking Statements

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This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that Synergy Resources Corporation d/b/a SRC Energy Inc. (the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements contained in this presentation specifically include statements, estimates and projections regarding the Company's future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditure budget, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. The words “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements, which generally are not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. These statements are based on certain assumptions made by the Company based on management's experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Forward-looking statements are not guarantees of performance. Although the Company believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the risk factors discussed or referenced in the Company's most recent Form 10-K; risks relating to declines in the prices the Company receives, or sustained depressed prices the company receives, for its oil and natural gas; uncertainties about the estimated quantities of oil and natural gas reserves; drilling and operating risks; the adequacy of the Company’s capital resources and liquidity including, but not limited to, access to additional borrowing capacity under the Company’s credit facility; the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas; the impact of potential changes in the Company’s credit ratings; environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination; difficult and adverse conditions in the domestic and global capital and credit markets; risks related to the concentration of the Company’s operations in the DJ Basin of northeast Colorado; disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver the Company’s oil, natural gas liquids and natural gas and other processing and transportation considerations; the costs and availability of equipment, resources, services and personnel required to perform the Company’s drilling and operating activities; potential financial losses or earnings reductions from the Company’s commodity price risk-management program; risks and liabilities related to the integration of acquired properties or businesses; uncertainties about the Company’s ability to replace reserves and economically develop its current reserves; general economic and business conditions, either internationally or domestically; competition in the oil and natural gas industry; uncertainty concerning the Company’s assumed or possible future results of operations; and other important factors that could cause actual results to differ materially from those projected. Accordingly, you should not place undue reliance on any of the Company’s forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Company Overview

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~60,000 net acres in the greater Wattenberg area

Contiguous nature of acreage provides ability to drill longer laterals with enhanced economics

Net daily production of 17,743 BOE/D for the quarter ended 3/31/2017 (2)

Adjusted EBITDA of $32.5 mm for the quarter ended 3/31/2017

Market capitalization of $1.7 Bil. as of 3/31/2017

Net debt to total capital of 2% as of 3/31/2017

Net debt to trailing 12M EBITDA of <1x as of 3/31/2017

Proved Reserves SEC Pre tax PV-10 of $476 mm as of 12/31/2016

(1) Represents two stream commodity mix and is as of 12/31/2016.(2) Net daily production represents the average 3-stream for the three months ending 3/31/2017.(3) Based on 3-stream conversion using 3.5 GPM wet gas yield and 25% gas volume shrink(4) Based on mid-point of 2017 full year production

Proved Reserves (1)

48,288

75,489

17,868

17,863

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

12/31/2015 12/31/2016

PDP

PUD

66,156

93,352

Pro

ved

Res

erve

s M

Bo

e9,891

12,159

0

5,000

10,000

15,000

20,000

25,000

30,000

2015 2016 2017 Est

27,000

–

25,000

Net Daily Production (3)

Pro

du

ctio

n (

BO

E p

er D

ay)

2017 Outlook

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2017 Development Plan• Drill 36 (gross) LL laterals, 74 (gross) ML laterals

and 6 (gross) SL laterals• Complete 9 (gross) XL laterals, 13 (gross) LL, 78

(gross) ML laterals, and 4 (gross) SL laterals• D&C Capex of $320-$340 MM• Full-year production guidance ~25-27 MBOE/D

Mid Length LateralEffective length: 7,500’Drill & Complete*: $3.75 mmDrill Time RR-RR**: 6-8 days

Long Length LateralEffective length: 10,000’Drill & Complete*: $4.5 mmDrill Time RR-RR**: 7-10 days

*includes facilities**includes surface casing

Gas/Oil Ratio Map

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Fagerberg

Bestway

Evans

Greeley Crescent Development Area

SRC Energy Leases

1,200 gross ML and LL drilling locations identified

KawataWilliams

Orr & Orr State

WiedemanGoetzel

LefflerBeebe

Hood

Current D&C Operations

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Drilling

Leffler Pad: 12 (~10 Net) LL wells drilling

Beebe Pad: 12 (~9 Net) ML wells drilling

Waiting on Stimulation

Hood Pad: 12 (~8 Net) ML wells waiting on stimulation

Goetzel Pad: 12 (~6 Net) ML wells waiting on stimulation

Completion in Progress

Williams Pad: 9 (~9 net) ML wells milling out plugs

Orr State Pad: 12 (~11 Net) ML Stimulating

Orr Pad: 12 (~11 Net) ML wells stimulating

Early Flowback

Kawata Pad: 10 (~7 Net) ML wells

Niobrara A

Niobrara BNiobrara C

Codell

ML

ML

ML

ML

Standard 12 Well Pad Configuration

ML

ML

ML

ML

ML

ML

ML

Standard Completion Design

Niobrara A & Codell

NiobraraB & C

Comments

Average stage length 200’ 200’ 50 stages in LLs; 60 stages in XLs

Perf clusters/stage 4 4 Actively managing entry points to improve proppant distribution and stimulated reservoir volume

Average Proppant load 800#/ft 1,300#/ft Engineered completions will pinpoint proppant placement to optimize productivity

Surfactant yes yes Testing surfactant designed for higher GOR reservoirs

Frac Fluid Slickwater Hybrid Will be testing alternative fluids in some zones

Other completion details: • Actual proppant loading across the lateral may change from the 800#-1,300#/ft avg., depending on interpreted,

relative productive potential along the lateral• Continue to utilize monobore, perf & plug designs with the added implementation of dissolvable plugs in the toes of

long laterals• SRC has begun using a completion fleet with integrated noise reduction technology in an effort to further reduce

environmental impact in urban areas

ML

Greeley Crescent Development AreaBlended GC MRL Well Economics

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Note: Strip Price Deck: 2017 = $50.43 / 2018 = $50.37 / 2019 = $50.11 / $ 2020 = $50.37 / 50.11 flat starting 2021Assumed differentials: oil = $9.00 / gas = $0.25.

• Well Cost estimates include all drilling and completions costs, as well as all surface and production facilities, but do not include leasehold or corporate overhead.• Estimated EURs may not correspond to estimates of reserves as defined under SEC rules.• Rate of return and payout estimates do not reflect lease acquisition costs or corporate, general and administrative expenses. Payout estimates calculated from first month of production and utilize strip pricing.• Production volumes converted to 3-stream equivalent • Break-even analysis assumes a 15% IRR on a pre-tax basis• Basin comparable figures are based on J.P. Morgan E&P Shale Economics report disseminated March 17, 2017. SRC estimates are internally generated, all other figures are J.P. Morgan estimates.

Blended GC Mid-Length Type Curve vs Bestway & Fagerberg Pads

0.0

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0 50

Cu

mu

lati

ve P

rod

uct

ion

(M

BO

E)

Month

700 MBOE Type Curve

800 MBOE Type Curve

900 MBOE Type Curve

Bestway Pad (Avg./Well)

Fagerberg Pad (Avg./Well)

IRR Comparison

Break-Even Cost ($/bbl) Comparison

$2

8.1

7

$3

1.5

5

$3

3.1

0

$3

3.2

6

$3

3.5

7

$3

4.3

8

$3

7.0

7

$3

7.2

4

$-

$10

$20

$30

$40

53

%

44

%

38

%

38

%

35

%

32

%

32

%

31

%

0%

20%

40%

60%800 MBOE ML Well Economics

Well Cost $3.75mm

Months to Payout 17

NPV- 10 $3.9mm

Break-Even Cost $28.52/bbl

IRR 64%

Midstream & Marketing

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DCP Midstream Gas Gathering & Processing Investments

Phase 2 is in progress and aligns with SRC Energy’s development plan

Additional bypass, compression & processing capacity is under way

Noble Midstream (NBLX)

Developing oil gathering systems for the GC area for delivery to downstream pipelines

Implementation of water delivery and gathering systems

Other 3rd Party

Servicing most recent pads

Downstream Oil Pipeline Commitments of ~11,200 BPD (gross operated) in 2017

Fagerberg

Evans

Orr StateBestway

Kawata

Williams

Proposed Plant 10

WiedemanOrr

Goetzel

Hood Leffler

Beebe

Corporate Summary

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Pure play with concentrated acreage position

Maintaining a strong balance sheet

March 31, 2017 total liquidity of ~$243 million

Cash of ~$33 million

$210 million available on undrawn revolver

2017 development plan to be funded by existing cash and proceeds from divestitures + expected revolver availability

Flexibility to accelerate or decelerate activity based on commodity prices

Conservative leverage profile to preserve capital flexibility

March 31, 2017 net debt / capitalization of 2%

$80 million in outstanding long-term notes due 2021

Balancing upside from increasing activity with disciplined hedging strategy

Approximately 45% of forecasted 2017 production is hedged Primarily utilizing costless collars

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APPENDIX

Management Team

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Name Title Experience

Lynn A. Peterson Chairman, President & CEO Former co-founder, President and CEO of Kodiak Oil & Gas, he has over 30 years of experience in executive management of oil and gas companies

James P. Henderson EVP of Finance and CFO More than 25 years of industry finance and management experience including Kodiak Oil & Gas, Anadarko Petroleum Corp., and Western Gas Resources

Mike Eberhard COO - Operations Petroleum engineer with over 30 years of industry experience including management positions with Anadarko and Halliburton

Nick Spence COO - Development Petroleum engineer with 25 years of industry experience in operations, including the past 4 years with Anadarko in the Wattenberg Field

Cathleen Osborn VP and General Counsel 30 years of industry experience and most recently served as in house counsel for Whiting Petroleum and prior to that Kodiak Oil & Gas

Jared Grenzenbach VP Accounting and CAO CPA with 18 years of accounting experience including over 10 years in oil and gas and 4 years with Deloitte & Touche LLP

Craig Rasmuson VP – Business Development Joined SRC Energy at its inception in 2008 and has supervised all of its field operations. Formerly with PDC Energy and DCP Midstream

Brant DeMuth VP of Finance CFA with over 30 years of financial analysis, asset management, and derivative trading experience. Former CFO of DJ Resources

Matthew Miller VP of Land Landman with over 30 years experience in the industry, formerly with Anadarko

Tom Birmingham VP of Exploration Geologist with 35 years in the industry with focus on the Wattenberg Field withAnadarko, Kerr McGee and HS Resources

Hedging Summary as of May 2017

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Disclosure on Derivative Instruments

The Company has entered, or may enter in the future, into commodity derivative instruments utilizing, price swaps, collars, put or call options to reduce the effect of

price changes on a portion of future oil and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the

condensed balance sheet as derivative assets and liabilities.

All derivative positions are carried at their fair value on the condensed balance sheet and are marked-to-market at the end of each period. Both the unrealized and

realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain on derivatives line on the condensed statement of operations.

The Company has a master netting agreement on each of the individual oil and gas contracts and therefore the current asset and liability are netted on the

condensed balance sheet and the non-current asset and liability are netted on the condensed balance sheet.

Crude Oil and Natural Gas Hedges

Oil Gas HH Gas CIG Oil Gas HH Gas CIG

Month (Bbl) (MMBtu) (MMBtu) (Bbl) (MMBtu) (MMBtu)

May 1 to December 31, 2017 142,500 814,875 355,000 $41.78 - $64.64 $2.91 - $3.98 $2.53 - $3.22

Oil Gas HH Gas CIG Oil Gas HH Gas CIG

Month (Bbl) (MMBtu) (MMBtu) (Bbl) (MMBtu) (MMBtu)

May 1 to August 31, 2017 20,000 - - $55.00 - -

(1) Oil price is based on NYMEX WTI and gas price is based on NYMEX Henry Hub or CIG

Avg Monthly Collar Volumes Average Collar Prices (1)

Avg Monthly Put Volumes Average Option Put Prices (1)

Adjusted EBITDA Reconciliation

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SRC ENERGY INC.

RECONCILIATION OF NON-GAAP FINANCIAL MEASURES

(unaudited, in thousands)

3/31/2017 3/31/2016

Adjusted EBITDA

Net Income (loss) 19,880$ (51,401)$

Add back:

Depreciation, depletionand amortization 13,229 12,092

Full cost ceiling impairment 0 45,621

Income tax expense (benefit) 0 0

Stock based compensation 2,675 2,519

Mark to market of commodity derivatives contracts:

Total (gain) loss on commodity derivatives contracts (3,379) (1,680)

Cash settlements on commodity derivatives contracts 81 3,059

Cash premiums paid for commodity derivatives contracts 0 0

Interest, net (11) (8)

Adjusted EBITDA 32,475$ 10,202$

Three months ended