April 2018 IPAA OGIS Conference. NYSE American: SRCI

Transcription

1 April 2018 IPAA OGIS Conference NYSE American: SRCI

2 Forward-looking Statements and Other Disclaimers 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 All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that 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. 2

3 Corporate Execution Contiguous acreage provides ability to drill longer laterals Well understood hydrocarbon system Net Daily Production (MBOE/D) (1) Est D&C Capex vs EBITDA ($MM) Locations / Wattenberg Acreage (2) Proved Reserves (MMBOE) (1) Capex EBITDA Q Annualized EBITDA Est. 1,800 1,600 1,400 1,200 1, ~41,000 ~600 Acreage Locations ~69,300 ~1000 ~90,000 ~1, (3) ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, PUD PDP 93 19% 81% % 62% 12/31/ /31/2017 (1) 2016 production data converted to 3-stream using 3.5 GPM wet gas yield and 25% gas volume shrink (2) Acreage and location counts based on values at the beginning of the period (3) Well counts in 2016 are normalized to ML equivalents 3

4 2018 Exploitation Program 2018 Guidance Total production of Mboe/d D&C Capex of $480-$540 MM 2018 operations funded by operating cash flow and existing liquidity Protect capital program by hedging 30%-50% of estimated production Plan to drill ~117 gross (100 net) wells and complete 116 gross (103 net) wells in 2018 D&C costs of ~$4.2 MM for 8,000 ML wells and ~$5 MM for 10,000 LL wells Attractive returns across the GOR spectrum 2,000<GOR<6,000: Initial oil cut >75% and 45% - 55% oil cut for life of well 6,000<GOR<12,000: Initial oil cut of 50%-60% and 40% - 45% oil cut for life of well GOR>12,000: Initial oil cut of 30%-50% and 15% - 20% oil cut for life of well 4

5 Midstream Infrastructure 5 DCP Midstream Mewbourne processing plant with 200 MMcf/d of expanded capacity is expected to be in service Q O Connor 2 with 200 MMcf/d of additional processing capacity is planned in the first half of 2019 NGL pipeline expansions out of the DJ Basin aligned with processing 2 Noble Midstream 1 3 Gathering oil and water in current development area Trunk line anticipated to extend south through acquired footprint providing access to multiple sales points Plant Operator In-Service Capacity MMCD Mewbourn 3 DCP Mid Q O'Connor 2 (Plant 11) DCP Late Q Latham I/II Western Gas Partners Q1/Q /200 Ft. Lupton Discovery Midstream Late 2018/ /200 Pierce Rimrock

6 Current D&C Operations Drilling 29 wells Boomerang Pad: 16 (~13 Net) 12 ML wells & 4 LL wells Donn Pad: 13 (~12 Net) LL wells Waiting on Stimulation 18 wells Falken Pad: 18 (~17 Net) 12 LL wells & 6 SL wells Completion in Progress 24 wells Goetzel Pad: 12 (~11 Net) ML wells Ag Pad: 12 (~10 Net) LL wells Early Flowback 24 wells Leffler Pad: 12 (~11 Net) LL wells Beebe Pad: 12 (~12 Net) ML wells Standard Completion Design Niobrara A & Codell Niobrara B & C Comments Average stage length stages in ML, 50 stages in LLs and 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 Surfactant designed for higher GOR reservoirs Frac Fluid Slickwater Hybrid Experimenting with fluid designs in some zones Other completion details: Utilize monobore, plug & perf designs with the added implementation of dissolvable plugs 7500 Utilizing a completion fleet with integrated noise reduction technology in an effort to further reduce environmental impact in urban areas 6

7 Delivering Long-Term Shareholder Value Full-Cycle NPV & IRR Per Well Economics NPV ($MM) Acreage Cost ~600 MBOE ~800 MBOE ~1 MMBOE $20k/acre $2.5 $3.5 $4.7 $15k/acre $2.7 $3.9 $4.9 IRR Acreage Cost ~600 MBOE ~800 MBOE ~1 MMBOE $20k/acre 45% 53% 57% $15k/acre 50% 59% 64% Full cycle, Wattenberg well economics are competitive with other major basins Note: Price Deck: Oil = $60 Flat, NGL = 30% of WTI, Natural Gas = $3.00 Flat Assumed differentials: oil = $6.50 / NGL = 17% / gas = $0.45 Full cycle NPV and IRR information assumes $4.2 MM ML lateral well costs and $5 MM LL lateral well cost. Rate of return and NPV estimates do not reflect corporate, general and administrative expenses. Estimated EURs may not correspond to estimates of reserves as defined under SEC rules. Production volumes reflect 3-stream equivalent 7

8 Operational and Financial Performance Commodity Mix (1) Cash Cost ($ / Boe) (1) (2) Oil NGLs Gas LOE Production Taxes Cash G&A 32% 29% 36% 35% 33% 31% $8.71 $ % 19% 47% 52% 21% 22% 20% 18% 43% 43% 47% 51% $5.27 $3.81 $2.39 $6.71 $6.54 $3.46 $1.66 $0.92 $3.19 $3.43 $3.69 $2.33 $1.69 $1.40 $1.54 $5.58 $1.47 $2.71 $6.56 $1.39 $3.63 3Q16A 4Q16A 1Q17A 2Q17A 3Q17A 4Q17A Cash Margin ($/Boe) 3Q16A 4Q16A 1Q17A 2Q17A 3Q17A 4Q17A Net Leverage (Net Debt / LTM EBITDAX) $26.79 $17.71 $21.81 $20.70 $18.74 $ x 0.9x 1.0x 1.1x 0.5x 0.3x 3Q16A 4Q16A 1Q17A 2Q17A 3Q17A 4Q17A 3Q16A 4Q16A 1Q17A 2Q17A 3Q17A 4Q17A (1) 2016 two-stream production adjusted to three-stream using 3.5 GPM wet gas yield and 25% gas volume shrink (2) 3Q16 production taxes were a net benefit to the Company 8

9 Reserves Report Summary Ryder Scott Reserves YE 2017 (1) Proved Reserves by Category Proved Reserves by Commodity Pre-tax PV-10 by Category (2) PUD 62% 227 MMBoe PDP 33% NGL 28% 227 MMBoe OIL 31% PUD 43% $1.8 B PDP 49% PDNP 5% GAS 41% PDNP 8% Reserves based on a 3-year development plan Represents development of approximately 15% of identified locations (1) Reserves per SEC price deck reserve report representing pricing of $51.34 WTI / $2.98 HH (2) Reserves split based on NYMEX pricing at 1/2/2018 9

10 Health, Safety and the Environment SRC s highest priority Engaged at multiple levels Front Range Emergency Response Committee COGA Operational Safety, Urban Operations, HSE Committees Rocky Mountain HSE Peer Group DJ Basin Safety Council and Operators Consortium Active vertical well plugging and reclamation program ~160 wells in 2017 with ~500 acres reclaimed Similar program underway in 2018 Focus on safety Incident Reporting & Tracking System Community & First Responder Engagement Stop Work Authority any worker, any time 10

11 Pure Play with Contiguous and Concentrated Acreage Position 2018 operations funded by cash flow and existing liquidity Multi-year inventory of high return wells Capital investment flexibility Expanding infrastructure Strong balance sheet with liquidity of over $450 million Active pursuit of environmental and social excellence 11

12 Appendix 12

13 Hedging Summary as of March 2018 Crude Oil, Natural Gas, and NGL Hedges Avg Monthly Collar Volumes Average Collar Prices (1) Oil Gas CIG Propane Oil Gas CIG Propane Month (Bbl) (MMBtu) (Gallons) (Bbl) (MMBtu) (Gallons) March 1 to December 31, , ,000 $ $61.29 $ $ Avg Monthly Swap Volumes Average Swap Prices (1) Oil Gas CIG Propane Oil Gas CIG Propane Month (Bbl) (MMBtu) (Gallons) (Bbl) (MMBtu) (Gallons) March 1 to December 31, ,285, $0.80 (1) Oil price is based on NYMEX WTI, gas price is based on NYMEX Henry Hub or CIG, and propane is based on Mont Belvieu Disclosure on Derivative Instruments The Compny 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. 13

14 Adjusted EBITDA Reconciliation SRC ENERGY INC. RECONCILIATION OF NON-GAAP FINANCIAL MEASURES (unaudited, in thousands) Three months ended Twelve months ended 12/31/ /31/ /31/ /31/2016 Adjusted EBITDA Net Income (loss) $ 50,818 $ 5,301 $ 142,482 $ (219,189) Add back: Depreciation, depletionand amortization 38,913 13, ,309 46,678 Full cost ceiling impairment ,223 Income tax expense (benefit) (99) 0 (99) 106 Stock based compensation 2,835 2,206 11,225 9,491 Mark to market of commodity derivatives contracts: Total (gain) loss on commodity derivatives contracts 6,550 4,133 4,226 7,750 Cash settlements on commodity derivatives contracts ,374 Cash premiums paid for commodity derivatives contracts Interest, net 11,256 (16) 11,479 (192) Adjusted EBITDA $ 110,437 $ 25,538 $ 282,564 $ 65,241 14

15 PV-10 Reconciliation SRC ENERGY INC. RECONCILIATION OF NON-GAAP FINANCIAL MEASURES (unaudited, in thousands) 12/31/ /31/ /31/2015 Standardized measure of discounted future net cash flows: Add: 10 percent annual discount, net of income taxes $ 1,600,675 $ 434,261 $ 390,953 Add: future undiscounted income taxes 1,267, , ,939 Future pre-tax net cash flows 285,349 90, ,172 Less: 10 percent annual discount, pre-tax 3,153, , ,064 (1,396,998) (475,695) (469,921) PV-10 $ 1,756,284 $ 476,348 $ 438,143 15