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MAY INVESTOR PRESENTATION
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MAY INVESTOR PRESENTATION M a y 2 0 1 8 1 Disclaimer: Forward - - PowerPoint PPT Presentation
MAY INVESTOR PRESENTATION M a y 2 0 1 8 1 Disclaimer: Forward Looking Statements This presentation contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of
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This presentation contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historical fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements may include projections and estimates concerning Bonanza Creek Energy, Inc.’s (the “Company”) capital expenditures, liquidity and capital resources, estimated revenues and losses, timing and success of specific projects, outcomes and effects of litigation, claims and disputes, business strategy and other statements concerning the Company’s operations, economic performance and financial condition. When used in this presentation, the words ‘‘could,’’ ‘‘believe,’’ ‘‘anticipate,’’ ‘‘intend,’’ ‘‘estimate,’’ ‘‘expect,’’ “forecast,” “may,’’ ‘‘continue,’’ ‘‘predict,’’ ‘‘potential,’’ ‘‘project’’ and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. The Company has based these forward-looking statements on certain assumptions and analyses it has made in light of its experiences and perceptions of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Company’s control, and may not be realized or, even if substantially realized, may not have the expected consequences. Factors that could cause actual results to differ materially include, but are not limited to, the following: the Company’s ability to replace oil and natural gas reserves; declines or volatility in prices it receives for its oil and natural gas, including any impact on the Company’s asset carrying values or reserves arising from the price declines; its financial position; its cash flow and liquidity; general economic conditions, whether internationally, nationally or in the regional and local market areas in which the Company does business; the recent economic slowdown that has and may continue to adversely affect consumption of oil and natural gas by businesses and consumers; the Company’s ability to generate sufficient cash flow from operations, borrowings or other sources to enable it to fully develop its undeveloped acreage positions; the presence or recoverability of estimated
possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulation); environmental risks; drilling and operating risks, including risks related to horizontal drilling; exploration and development risks; competition in the oil and natural gas industry; management’s ability to execute the Company’s plans to meet its goals, uncertainties of negotiations to result in an agreement or a completed transaction; the Company’s ability to retain key members of its senior management and key technical employees; infrastructure challenges; access to adequate gathering systems and pipeline take-away capacity to execute the Company’s drilling program; the Company’s ability to secure firm transportation for oil and natural gas it produces and to sell the oil and natural gas at market prices; costs associated with perfecting title for mineral rights in some of the Company’s properties; the Company’s ability to realize estimated well cost reductions; continued hostilities in the Middle East; other sustained military campaigns or acts of terrorism or sabotage; and other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact the Company’s businesses, operations
“SEC”). For further detail on these and other risks and uncertainties, the Company refers you to the information under the headings “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 and in comparable sections of our Quarterly Reports on Form 10-Q, as filed with the SEC. All of the forward-looking statements made in this presentation are qualified by these cautionary statements and are made only as of the date hereof. The Company does not undertake, and specifically declines, any obligation to update any such statements or to publicly announce the results of any revisions to any such statements to reflect future events or developments. Although the Company believes that its plans, intentions and expectations reflected in or suggested by the forward-looking statements it makes in this presentation are reasonable, the Company can give no assurance that these plans, intentions or expectations will be achieved. By attending or receiving this presentation you acknowledge that you will be solely responsible for your own assessment of the market and the market position of the Company and that you will conduct your own analysis and be solely responsible for forming your own view of the potential future performance of the Company’s business. This presentation does not constitute the solicitation of the purchase or sale of any securities. This presentation has been prepared for informational purposes only from information supplied by the Company and from third-party sources. Such third-party information has not been independently verified. The Company makes no representation or warranty, expressed or implied, as to the accuracy or completeness of such information. Trademarks that appear in this presentation belong to their respective owners.
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Market Cap(1): ~$650 million 1Q18 Production: 16.8 Mboe/d 1Q18 Production Mix: 59% Oil 2017 Proved Reserves: 102 MMBoe
Target Proved Reserves YE17 Niobrara/Codell ~90 MMBoe (47% PD) Acres Production 1Q18 ~67,000 Net 13.8 MBoe/d (60% oil)
Wattenberg Overview
Target Proved Reserves YE17 Cotton Valley ~12 MMBoe (100% PD) Acres Production 1Q18 ~11,500 Net 3.0 MBoe/d (55% oil)
Mid-Continent Overview
the rural portion of the Wattenberg
completions across Wattenberg position
~$180 million in liquidity
(1) Calculated as of May 1, 2018
FINANCIAL OVERVIEW OPERATIONAL OUTLOOK ASSET OVERVIEW STRATEGIC OVERVIEW
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growth
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gross wells
acreage to optimize well performance
midyear; positive results from these wells could unlock significant inventory
and 2019(2)
(1) Assumes 2018 guided program and 2-rig program in 2019. (2) Assumes 2018 guided program, 2-rig program in 2019, and strip pricing as of May 1, 2018.
FINANCIAL OVERVIEW OPERATIONAL OUTLOOK ASSET OVERVIEW STRATEGIC OVERVIEW
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~67,000 Contiguous net acres
development and field-level infrastructure
urban development risk
French Lake ~12,000 net acres Legacy Acreage ~34,000 net acres North Acreage ~21,000 net acres
Colorado
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capacity
expected 4Q18
CPFs to 2 third party disposal wells
volumes
reduce oil differentials further
Legacy
STRATEGIC ADVANTAGES OF RMI
and optimal production rates
better operating, capital, and surface use efficiency
field to the most favorable off-take points and provides access to additional third- party gathering/processing partners
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Line pressures on RMI system have remained low at ~75 PSI during a period when regional field systems have experienced significant increases Low line pressures provide enhanced production performance from PDP wells, resulting in lower PDP decline rates Addition of Sterling (4Q17) and Cureton (4Q18) offtake points to the RMI system provide access to additional third party processing capacity, which provide further flow assurance
50 100 150 200 250 300 350 400 450 Jun-16 Sep-16 Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 Mar-18 Line Pressure (PSI)
BCEI/RMI vs Prevailing Field Pressures
BCEI/RMI Field Pressure Prevailing Field Pressure
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cost, high IRR investment opportunities
wells and 5-acre down-spacing opportunities
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37.9 42.4 40.1 3.8 4.1 3.7 5.4 5.7 48.1 12.7 11.5
20 40 60 80 100 120 MMBoe
increased by 13% to ~102 MMBoe after commencing drilling and completion program in 2H17
value for proved reserves; $470 million for proved developed reserves(1)
pricing to $56 per barrel WTI, would result in PV-10 value of $760 million
excluding price revisions of 202%
Rockies Proved Developed Rockies Proved Undeveloped Mid-Con Proved Developed
(1) Year-end reserves were prepared by Netherland, Sewell & Associates, Inc. The 12-month average benchmark pricing used to estimate SEC proved reserves and PV-10 value for crude oil and natural gas was $51.34 per Bbl of WTI crude oil and $2.98 per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2017 benchmark prices for oil, and natural gas were both 20% higher from year-end 2016 SEC pricing. After differential adjustments, the Company's SEC pricing realizations for year-end 2017 were $46.76 per Bbl of oil, $19.57 per Bbl of NGLs, and $2.45 per Mcf of natural gas. Please refer to the Non-GAAP Disclosure on slide 26 of this presentation for information regarding PV-10.
90.7 102.0
FINANCIAL OVERVIEW OPERATIONAL OUTLOOK ASSET OVERVIEW STRATEGIC OVERVIEW
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turned-online in 2018
and ~$5.4 million per XRL, all utilizing enhanced completion designs Drilling and Completion Rockies Operated $ 225 – 255 Rockies Non-Operated 15 Total Drilling and Completion $ 240 – 270 Infrastructure/Other 40 – 50 Total Capital $ 280 – 320
2018 Program Objectives
prudent and profitable growth
ensure maximized well performance
performance across Wattenberg position
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2017 program proved concept of enhanced completions; 2018 program utilizes those enhanced completions throughout the Company’s Wattenberg position and further tests slick-water
Base Enhanced Completion Design: 2,000 lbs. proppant per lateral foot 130 foot stage spacing 40 bbls of fluid per lateral foot Crosslink gel 2018 Slick-water Tests: 2,000 – 2,500 lbs. proppant per lateral foot 130 foot stage spacing 80 bbls of fluid per lateral foot Slick-water
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Rig 1 1 – 1 XRL Expected First Production: 2Q18 2 – 5 SRLs (Slick-water test) Expected First Production: 2Q18 3 – 4 XRLs (Slick-water test) Expected First Production: 3Q18 4 – 6 SRLs, 2 MRLs, 6 XRLs Expected First Production: 4Q18 5 – 10 XRLs Expected First Production: 4Q18 6 – 14 SRLs Expected First Production: 1Q19 7 – 1 SRL, 5 MRLs, 1 XRL Expected First Production: 2Q19 Rig 2 1 – 1 XRL (Slick-water test) Expected First Production: 3Q18 2 – 9 SRLs, 7 XRLs Expected First Production: 1Q19 3 – 5 SRLs, 13 XRLs Expected First Production: 3Q19
French Lake Legacy Acreage North Acreage
Rig 1 Rig 2 (starting 2H18)
2 6 7 4 5 3 1 3 2
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cumulative data set of 114 operated wells utilizing enhanced completion design by mid 2019
4MM Lbs.
18
stages
60M Bbl
28
stages
25
stages
94M Bbl
stages
127-250M Bbl
4MM Lbs. 60M Bbl 4MM Lbs.
8-10 MM Lbs.
2013 2014 2015 2017/18
Completion design metrics for typical 4,100’ well
17 2 4 6 8 10 12 14 16 30 60 90 120 150 3-Stream Cumulative Production (MBoe/1,000') Time (Days)
Company’s central acreage is
legacy central SRL type curve
slick-water throughout the Company’s acreage; by YE18 Company expects to have slick-water results in West, Central, East, North, and French Lake acreage
the western acreage in 3Q18
Day 159: 14.3 MBoe (67% oil)
Central 80-Acre SRL TC (310 MBoe) Proppant Intensity: 1,000 #/ft. Fluid Intensity: 20 Bbls/ft. Stage Spacing: 225 ft. State Antelope 41-44-28HNB (345 MBoe) Proppant Intensity: ~1,500 #/ft. Fluid Intensity: ~ 60 Bbls/ft. slick-water Stage Spacing: ~130 ft. Antelope T34-P31-21HNC (385 Mboe) Proppant Intensity: ~1,500 #/ft. Fluid Intensity: ~25 Bbls/ft. Stage Spacing: ~100 ft.
Day 159: 11.5 MBoe (68% oil)
18 1 2 3 4 5 6 7 8 9 30 60 90 120 150 180 3-Stream Cumulative Production (MBoe/1,000') Time (Days)
enhanced completion XRL wells as part of its J21 and T21 pads, which included 3-XRLs and 2-SRLs in the second half of 2017
XRL wells are exhibiting significantly greater production performance compared to standard completions
enhanced completion wells are
completion type curve by approximately 35%
Day 156: 8.6 MBoe (76% oil)
Central 80-Acre XRL Type Curve (525 MBoe) Proppant Intensity: 1,000 #/ft. Fluid Intensity: 20 Bbls/ft. Stage Spacing: 225 ft. J21/T21 XRLs (680 MBoe) Proppant Intensity: ~1,500 – 2,000 #/ft. Fluid Intensity: ~ 30 Bbls/ft. Stage Spacing: ~100 – 130 ft.
19 5 10 15 20 25 30 30 60 90 120 150 180 210 240 270
3-Stream Cumulative Production (MBoe/1,000')
Time (Days)
eight-well SRL F-26 Pad in 1Q18
completion design
performance to the North Platte 44- 13 Pad, which incorporated a similar completion design
North Platte 44-13 Pad (475 Mboe) Proppant Intensity: ~2,000 #/ft. Fluid Intensity: ~40 Bbls/ft. Stage Spacing: ~100 ft. West 80-Acre SRL TC (375 MBoe) Proppant Intensity: 1,000 #/ft. Fluid Intensity: 20 Bbls/ft. Stage Spacing: 225 ft.
Day 78: 6.5 MBoe (76% oil)
F-26 Pad (8 SRL wells) Proppant Intensity: ~2,000 #/ft. Fluid Intensity: ~30 Bbls/ft. Stage Spacing: ~100 ft.
Day 285: 24.1 MBoe (60% oil)
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PROVIDES OPPORTUNITY TO ADD XRL LOCATIONS TO INVENTORY
to develop French Lake utilizing an integrated upstream and midstream development model
exclusively with XRLs (9,000’)
appraisal wells by end of 2Q18 and monitor results
development agreement Illustrative Joint Development Plan(1)
(1) French Lake joint development plan shown for illustrative purposes. Actual development may differ materially from illustration.
French Lake Acreage Bonanza Creek Leases Potential Wells 8 Initial Appraisal Wells
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forecasting 30% growth in December exit rate from ‘17 to ‘18 and greater than 50% annual growth in 2019
year over year
recently appointed CEO compensation expectations
Debt to EBITDAX by year-end 2018 and cash flow positive in 4Q19(2)
$6.00 per Bbl off WTI in 2018(3)
(1) Recurring cash G&A guidance is a non-GAAP measure that is defined as GAAP G&A expense less stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. (2) Assumes May 1, 2018 strip pricing. (3) Assumes actual differential for 1Q18 and strip pricing as of May 1, 2018 for remainder of year.
Production
2Q18 (Mboe/d) 18.0 – 18.6 FY18 (Mboe/d) 17.7 – 18.7
Operating Costs (FY18)
Lease Operating Expense ($/Boe) $5.00 – $6.00 Gas Plant and Midstream opex ($/Boe) $1.40 – $1.80 Severance Tax Ad/Valorem (as a % of revenue) 7 – 8% Recurring Cash G&A ($MM) (1) $33 – $35
FINANCIAL OVERVIEW OPERATIONAL OUTLOOK ASSET OVERVIEW STRATEGIC OVERVIEW
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~$180 MILLION OF LIQUIDITY
and swap contracts for both oil and natural gas
Committed to maintaining financial strength and flexibility to participate in growth opportunities
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PROGRESSING TOWARD STRATEGIC GOALS Strategic Goal Progress
Apply cutting-edge technologies to maximize well performance Enhanced completions and recent slick-water test are outperforming legacy completion designs Apply rigorous returns-based criteria to allocate development program capital Rigorous capital allocation for ~$300 million 2018 program resulting in fully-burdened risked returns well in excess of cost of capital Foster a culture of innovation and
Continued focus on iterating completion design to maximize well performance and reservoir recovery; proactively invested in midstream asset to enhance well performance and flow assurance Maintain financial strength and readiness to participate in growth opportunities ~$180 million in liquidity, no term-debt, $15 million drawn on credit facility at March 31, 2018; anticipating <1.0x debt/EBITDAX at YE18
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Company Contact
Scott Fenoglio - SVP Finance & Planning sfenoglio@bonanzacrk.com 720-225-6667
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*Updated as of 5/1/18
Crude Oil (NYMEX WTI) Natural Gas (NYMEX Henry Hub) Barrels/day Weighted Avg Price per Bbl MMBtu/day Weighted Avg Price per MMBtu 2Q18 Swaps 3,835 $55.03
2,000 $42.00 / $52.50 6,259 $2.75 / $3.38 3Q18 Swaps 5,000 $57.87
2,000 $43.00 / $53.50 7,600 $2.75 / $3.31 4Q18 Swaps 5,000 $58.07
2,000 $43.00 / $53.50 6,600 $2.75 / $3.37 1Q19 Swaps 4,000 $58.16
2,000 $43.00 / $54.53 7,600 $2.75 / $3.22 2Q19 Swaps 4,500 $58.32
1,330 $44.01 / $54.79 2,505 $2.75 / $3.22 3Q19 Swaps 3,000 $55.00
Swaps 3,000 $55.00
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(in thousands) PV-10 (1)
$ 598,498
Present value of future income taxes discounted at 10% (2)
–
Standardized Measure
$ 598,498
(1) The 12-month average benchmark pricing used to estimate SEC proved reserves and PV-10 value for crude oil and natural gas was $51.34 per Bbl of WTI crude oil and $2.98
per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2017 benchmark prices for oil, and natural gas were both 20% higher from year-end 2016 SEC
(2) The tax basis of the Company's oil and gas properties as of December 31, 2017 provides more tax deduction than income generation when reserve estimates were prepared
using 2017 SEC pricing.
PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value
the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our proved oil and natural gas reserves. The following table presents a reconciliation of GAAP Standardized Measure to the non-GAAP financial measure of PV-10.