Expanding the Runway
Investor Presentation March 2013 Expanding the Runway Disclaimer - - PowerPoint PPT Presentation
Investor Presentation March 2013 Expanding the Runway Disclaimer - - PowerPoint PPT Presentation
Investor Presentation March 2013 Expanding the Runway Disclaimer 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
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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,’’ ‘‘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. Forward-looking statements may include statements about: the Company’s ability to replace oil and natural gas reserves; declines or volatility in prices it receives for its oil and natural gas; 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
- f estimated oil and natural gas reserves and the actual future production rates and associated costs; uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and
possible resources; the 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; the Company’s ability to retain key members of its senior management and key technical employees; 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; 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 or pricing; and other important factors that could cause actual results to differ materially from those projected in this presentation and in the Company’s filings with the U.S. Securities and Exchange Commission (the “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, 2011 and in comparable sections of our Quarterly Reports on Form 10-Q, filed with the SEC, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Current Report on Form 8-K filed with the SEC on January 28, 2013. 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. In this presentation the term “EUR” (estimated ultimate recovery) is used to provide estimates. Factors affecting ultimate recovery include the scope of the Company’s actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. These estimates are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of not being actually realized by the Company. For a further discussion of the Company’s proved reserves, as calculated under current SEC rules, the Company refers you to the Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Report on Form 8-K filed on January 28, 2013, each referenced above, which are available on the Company’s website at www.bonanzacrk.com and at the SEC’s website at www.sec.gov. The information on the Company’s website is not deemed part of this presentation. 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.
Disclaimer
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Bonanza Creek Overview
(1) Stock price and market capitalization as of 2/26/2013. (2) Common shares outstanding as of 9/30/2012. (3) Public float as of 2/28/2013. (4) Proved reserves as of 12/31/2011; engineered by Cawley, Gillespie & Associates.
North Park Basin (Niobrara)
Wattenberg Field
(Niobrara & Codell)
Rapidly growing Oil weighted Wattenberg Niobrara flagship asset Arkansas low risk infill development
Market Cap(1): $1.3 billion Share Price(1): $32.56 Shares Outstanding(2): ~40 million Public Float(3): 73%
21.6 MMBoe 1P(4) 67% Liquids
Mid-Continent
(Cotton Valley & Brown Dense)
0.6 MMBoe 1P(4) 100% Oil
20.8 MMBoe 1P(4) 59% Oil
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10,000 20,000 30,000 40,000 50,000 2007 2008 2009 2010 2011
- 2,000
4,000 6,000 8,000 10,000 12,000 14,000 16,000
2007 2008 2009 2010 2011 2012 Est. 2013 Est.
Impressive Growth Track Record
Proved Reserves(1) (MBoe) Production(1) (Boe/d)
(1) Presentation is pro forma for the December 23, 2010 Holmes Eastern Company acquisition, as if it were completed on May 1, 2009. (2) Production CAGR calculated to the mid-point of the 2013 guidance range. (3) Based on midpoint of guidance of 9.1 – 10.1 Mboe/d. (4) Based on midpoint of guidance of 14.5 – 16.0 Mboe/d.
Oil & NGLs Natural Gas Oil & NGLs Natural Gas Guidance range
+59%(4) +119%(3)
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Dramatic Year-Over-Year Increases
117% Increase in Production
9,545 Boe/d(1)
527% Increase in Adj. Net Income(2)
$14.6 million ($0.37/sh)
148% Increase in EBITDAX(2)
$39.6 million ($1.00/sh)
86% of Revenue from Crude Oil
8% from natural gas 6% from natural gas liquids
3Q12 as compared to 3Q11
(1) See reconciliation to discontinued operations in Appendix. (2) See reconciliation in Appendix.
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Oil Weighted Assets Drive Strong Margins
3Q 2012 Revenue Unhedged Cash Margin / Boe(1)
13% Cash G&A 8%
- Nat. Gas
92% Oil & Liquids 5% Prod. Taxes 67% Cash Margin ($45.14) 15% LOE
(1) Unhedged cash margin per Boe represents oil & natural gas revenues, less lease operating expenses, oil and natural gas taxes, cash G&A expense (excludes stock-based compensation), divided by production. (2) Average sales price for a barrel of oil equivalent before the effects of hedging for third quarter 2012.
$59.6 Million $67.70
(2)
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Strong Organic Growth Inventory
Wattenberg Niobrara “B” Arkansas Brown Dense Wattenberg Niobrara 40-acre spacing Arkansas Cotton Valley 5-acre spacing Wattenberg Niobrara “C” Wattenberg Niobrara “A”
Full Development Evaluating Testing
North Park Niobrara Wattenberg Codell
(1) Resource potential based on internal estimates; not included in proved reserves or reviewed by third party and subject to ongoing technical
- review. Please see the forward looking statement disclosure on page 2 of this presentation and review associated risk factors.
250 MMBoe of resource potential(1) 9 primary opportunities in various stages of development and evaluation Wattenberg Greenhorn
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2013 Capex Plan(1) – Wattenberg Activity Doubles
82% 18% 2013 Capex: $394 million
Wattenberg Field: $324 million
Niobrara “B” (4,000’): 56 wells
Niobrara “B” (9,000’): 2 wells
Niobrara “B” (40-acre test): 6 wells
Niobrara “C”: 4 wells
Codell: 4 wells
Other: non-operated activity, seismic, SWD
Arkansas: $70 million
Cotton Valley: 33 wells Cotton Valley (5-acre test): 3 wells Cotton Valley: 114 recompletions Other: gas plant, SWD 4 Hz rigs in Wattenberg by 2Q 2 vertical rigs in Arkansas
Operated Rig Count
(1) Actual capital expenditures are subject to a number of factors, including economic conditions and commodity prices; the Company has flexibility to reduce or augment the budget as appropriate.
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Wattenberg Niobrara a Premier Oil Resource Play
Source: Credit Suisse Equity Research “SMID-Cap E&Ps Basin Economics Update” – December 4, 2012.
55% 55% 54% 53% 46% 43% 39% 39% 36% 36% 34% 33% 33% 30% 26% 23% 23% 20% 19% 19% 17% 17% 16% 14% 13% 13% 11% 9% 9% 9% 5% 3% 0% 10% 20% 30% 40% 50% 60% Year: 1 2 3 4 5 6 7 8+ WTI Oil: $94.92 $90.76 $91.23 $89.38 $87.67 $86.46 $86.46 $86.46 NYMEX Gas: $2.79 $3.68 $4.07 $4.26 $4.41 $4.60 $4.60 $4.60 Futures Strip as of 12/4/2012
Basin IRR’s – Futures Strip as of 12/4/2012
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Wattenberg Horizontal Niobrara – Oil Focused
Niobrara B: 31 wells
- Avg. 30-day Rate: 503 Boe/d
76% oil Niobrara B: 25 wells
- Avg. 60-day Rate: 394 Boe/d
74% oil
N
BCEI HZ Wells Drilled in 2011-2012
Niobrara “B” Bench Niobrara “C” Bench Codell Extended Reach Lateral
Note: Not intended to reflect offset operators’ actual acreage positions.
Wells Ranch
40-acre downspacing pilots “A” bench / “C” bench / Codell pilots Extended reach laterals NBL cites OOIP / section of 74 MMBoe at Wells Ranch
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Focused on Continual Improvement
BCEI Reported Average IP30 Rates BCEI Reported(1) Average IP60 Rates
(1) IP60 rates were first reported in August 2012 using an 11-well average.
350 355 360 365 370 375 380 385 390 395 5 Wells 11 Wells 20 Wells 25 Wells 430 440 450 460 470 480 490 500 510 4 Wells 16 Wells 24 Wells 31 Wells
Increased frac stages from 16 stages to 18 stages − Increases reservoir wellbore communication Controlled flowback − Limits sand production; allows frac to heal Early wellbore cleanout − Higher flow-back pressure leads to more efficient post-frac cleanout Setting liner hanger in horizontal section − Allows for deeper and more efficient installation of artificial lift Early installation of gas lift equipment − More efficient form of artificial lift
Technical improvements
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Wattenberg – Expanding Resource Recovery
“C” Bench present on all Wattenberg acreage
Expected economics similar to Niobrara “B” 4,000 ft. laterals
BCEI completed its first “C” Bench well in
December 2012
Niobrara “C” Bench Horizontal
Codell prospective on ~15,000 net acres
Expected economics similar to Niobrara “B” 4,000 ft. laterals BCEI completed its first Codell well in October 2012 IP30 rate: 370 Boe/d (81% crude oil) under controlled flow-back
Codell Horizontal Development
Well cost: ~$8.0 million Expected EUR: 750 MBoe BCEI completed its first ERL in December 2012
Extended Reach Laterals
Successful tests by neighboring operators BCEI plans 6-well 40-acre test in 1H 2013
Downspacing to 40-acres
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Wattenberg – Productive Acreage Breakdown
Multi-zone potential equivalent to ~107,400 acres
Niobrara B – 30,800 Acres Niobrara C – 30,800 Acres Codell – 15,000 Acres Niobrara A – 30,800 Acres
Developing on planned 80-acre spacing (56 wells) Testing ERL (2 wells) Testing 40-acre downspacing (6 wells) 4 wells Locations spread across east and west blocks
2013E Capex Plan
4 wells None BCEI – 38 horizontal wells through year end 2012, includes 1 extended reach lateral NBL / PDCE – Testing 40-acre downspacing APC – Full development BCEI – 1 well in 2012 NBL – Testing 40-acre downspacing PDCE – Initial testing APC – Successful testing
Recent BCEI & Offset Operator Activity
Industry tests during 2012 Development starting in 2013 BCEI – 1 well in 2012 NBL – Testing 40-acre downspacing PDCE – 8 wells drilled APC – Successful testing
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25% 50% 75% 100% 125% $70 $80 $90 $100
Wattenberg Hz Niobrara “B” Bench Economics
(1) EUR based on internal Company estimates derived from drilling results and may differ from the EURs used by our independent reserve engineer in connection with their 2013 audit of our reserves. (2) Represents estimated locations as of year end 2012 and is subject to ongoing technical review. (3) Natural gas reflected at 18:1 to crude oil for price; 6:1 for rate.
EUR 312,000 Boe; 65% crude oil(1) Initial 30-day Rate 469 Boe/d Cost per Well $4.2 MM NPV-10 at $80/BO $4.1 MM NPV-10 at $100/BO $6.1 MM Risked Locations 321(2) net 4,000 ft “B” Bench
BTAX IRR % at $/BO WTI(3)
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Louann TERTIARY Werner Schuler Eagle Mills Louann Salt Norphlet Smackover Buckner Haynesville Bossier Louark MIDDLE JUR. TRIASSIC (?) PALEOZOIC Hosston Sligo Travis Peak Pettet Pine Island James Bexar Rodessa Massive Anhydrite Upper Glen Rose Walnut Goodland Lime Paluxy Buda Del Rio Shale Georgetown Glen Rose Kiamichi Maness Shale Woodbine Eagle Ford Shale Austin Chalk Woodbine Eagle Ford Fredericksburg Austin Trinity Taylor Washita COMMANCHEAN (Lower Cretaceous) Midway Wilcox PALEOCENE Cotton
- V. Sa.
Cotton Valley UPPER JURASSIC JURASSIC Navarro GULFIAN (Upper Cretaceous) CRETACEOUS MESOZOIC Claiborne EOCENE CENOZOIC FORMATION GROUP SERIES SYSTEM ERA Louann TERTIARY Werner Schuler Eagle Mills Louann Salt Norphlet Smackover Buckner Haynesville Bossier Louark MIDDLE JUR. TRIASSIC (?) PALEOZOIC Hosston Sligo Travis Peak Pettet Pine Island James Bexar Rodessa Massive Anhydrite Upper Glen Rose Walnut Goodland Lime Paluxy Buda Del Rio Shale Georgetown Glen Rose Kiamichi Maness Shale Woodbine Eagle Ford Shale Austin Chalk Woodbine Eagle Ford Fredericksburg Austin Trinity Taylor Washita COMMANCHEAN (Lower Cretaceous) Midway Wilcox PALEOCENE Cotton
- V. Sa.
Cotton Valley UPPER JURASSIC JURASSIC Navarro GULFIAN (Upper Cretaceous) CRETACEOUS MESOZOIC Claiborne EOCENE CENOZOIC FORMATION GROUP SERIES SYSTEM ERA
Mid-Continent Operations (Arkansas)
Provides free cash flow; reallocated to Wattenberg Niobrara Primary Target: Cotton Valley: 4,000 – 7,000 feet Potential inventory upside catalysts: Dorcheat-Macedonia 5-acre infill testing McKamie-Patton CV development Brown Dense potential on ~ 6,000 acres 100% owned gas processing facilities; 40 MMcf/d capacity
Bonanza Creek Productive Formations Bonanza Creek Fields Bonanza Creek Gas Processing Facilities SWN Brown Dense Wells
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Dorcheat-Macedonia Economics
0% 25% 50% 75% 100% 125% $70 $80 $90 $100
EUR 152,000 Boe(1) Peak 30-day Rate 103 Boe/d % Oil & Liquids 70% Cost per Well $1.8MM NPV-10 at $80/BO $1.9 MM NPV-10 at $100/BO $2.8 MM Risked Locations 111(2)
Combined IRR (including Gas Facility) Standalone IRR (excluding Gas Facility)
BTAX IRR % at $/BO WTI(3)
(1) EUR based on internal Company estimates derived from drilling results, and may differ from the EURs used by our independent reserve engineer in connection with their 2013 audit of our reserves. (2) Locations as of YE 2012 at 10-acre spacing in Cotton Valley oil sands. (3) Natural gas reflected at 18:1 to crude oil for price; 6:1 for rate.
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Cotton Valley Lenticular Oil Sands
Pin-Point Fracture Technology
Focused completion technology Improved recovery of OOIP Highly repeatable
25-30 sand/shale sequences Each zone individually pressured Potential for downspacing inside 10-acres
Dorcheat Unit 37
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Financial Overview
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$13.18 $12.03 $9.45 $10.13 $4.18 $5.71 $3.43 $3.45 $7.90 $8.19 $7.76 $8.98 $- $5 $10 $15 $20 $25 $30 4Q11 1Q12 2Q12 3Q12 LOE Production Taxes Cash G&A $44.08 $50.74 $45.06 $45.14 $- $20 $40 $60 $80 4Q11 1Q12 2Q12 3Q12 Cash Margin Realized Price $69.34 $76.68 $65.70 $67.70
Improving Operating Cost Structure – High Margins
Cash Costs ($ per Boe) Realized Price & Cash Margins ($ per Boe)
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Financial Strategy & Capitalization
Cash and cash equivalents $5 Revolving Credit facility (1) $122 Total shareholders' equity 564 Total capitalization $687 Borrowing base $325 Liquidity(2) $110 Operating statistics: LTM EBITDAX $131 3Q12 annualized EBITDAX 158 Proved reserves (MMBOE) 44 Proved developed reserves (MMBOE) 17 Pre-Tax Proved PV-10% (12/31/11) $794 Credit statistics: Total debt / LTM EBITDAX 0.9x 3Q12 annualized EBITDAX 0.8x Proved reserves ($/BOE) $2.80 Proved developed reserves ($/BOE) $7.17 Pre-Tax Proved PV-10% / Total debt 6.5x Source: Company filings. (1) As of 9/30/12. Dollars in millions. (2) Based on 9/30/12 cash balance and $105.5 mm of revolver availability as of 1/15/2013.
Target leverage of <2x (Debt / EBITDAX) BCEI’s leverage is significantly lower than its peers(1)
(1) Peer group includes APC, CRZO, KOG, MHR, NBL, OAS and PDCE.
Debt / LTM EBITDAX
0.9x 1.5x 1.5x 2.8x 3.0x 3.0x 4.2x 5.4x – 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x BCEI 2 3 4 5 6 7 8
Median 2.9x
Capitalization
Low leverage at < 1.0x
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Hedge Positions and Strategy
Note: Hedge positions as of February 6, 2013. (1) Based on the mid-point of 2013 production guidance published on January 3, 2013, which is subject to numerous assumptions and risks. See the Disclaimer at the beginning of this presentation.
Approximately 2.2 MMboe hedged in 2013 and 1.5 MMboe hedged in 2014 Current volumes hedged in 2013 represent approximately 40% of estimated production(1) Comfortable hedging >50% of next twelve months production
(Bbls/d) (Bbls/d) (MMBtu/d)
Oil Swaps Oil Collars Gas Swaps
($/Bbl) ($/Bbl) ($/MMBtu) $6.40 $0 $1 $2 $3 $4 $5 $6 $7 – 50 100 150 200 250 300 350 400 450 2013 2014
Hedged volume (MMBtu/d) Price ($/MMBtu)
$88.51 $90.80 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 – 500 1,000 1,500 2,000 2,500 3,000 3,500 2013 2014
Hedged volume (Bbls/d) Weighted average price ($/Bbl)
$88.39 $86.74 $102.29 $95.46 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 – 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 2013 2014
Hedged volume (Bbls/d) Floor price ($/Bbl) Ceiling price ($/Bbl)
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Expanding the Runway
True crude oil / liquids producer in Wattenberg Niobrara Rapidly growing production Large inventory of high value, drill ready locations with upside potential Dorcheat-Macedonia provides cash flows to fund growth in Wattenberg Experienced management team with proven track record Low leverage and substantial liquidity
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Corporate Information
Company Headquarters 410 17th Street, Suite 1400 Denver, Colorado 80202 (720) 440-6100 Main (720) 305-0804 Fax Houston Office 1331 Lamar Street, Suite 1135 Houston, Texas 77010 (713) 337-1250 Main (713) 337-1255 Fax Bakersfield Office 5601 Truxtun Avenue, Suite 210 P.O. Box 21974 Bakersfield, California 93309 (661) 638-2730 Main (661) 638-2733 Fax Investor Relations James Masters Investor Relations Manager (720) 440-6121 jmasters@bonanzacrk.com Financial Auditor Hein & Associates LLP Reserve Auditor Cawley, Gillespie and Associates, Inc.
www.bonanzacrk.com
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Appendix
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Experienced Management Team
Gary Grove
EVP – Engineering & Planning Interim COO
Mike Starzer
President & CEO
Joined in 2003 and founder of predecessor company Prior: Managerial and Engineering roles at Unocal and Nuevo Energy B.S. in Petroleum Engineering, Marietta College Joined in 2001 and founder of predecessor company Prior: Managerial and Engineering roles at Dowell Schlumberger and Berry Petroleum B.S. in Petroleum Engineering, Texas A&M University Founder of predecessor companies Prior: Executive and Engineering roles at Unocal and Berry Petroleum B.S. in Petroleum Engineering, Colorado School of Mines; M.S. in Engineering Management, University of Alaska; Registered Petroleum Engineer
Pat Graham
EVP – Corporate Development
Wade Jaques
Chief Accounting Officer
Joined in 2010 as Controller; promoted to Chief Accounting Officer in 2011 Prior: Controller at Ellora Energy Inc. and Audit Manager at Deloitte & Touche B.S. in Accounting; M.S. in Accountancy, Utah State University
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Experienced Management Team
Lynn Boone
SVP – Reservoir Engineering
Joined in 2012 to supervise reservoir engineering activities Prior: Bill Barrett Corp., Cody Energy, HS Resources, and Unocal B.S. in Chemical and Petroleum Refining Engineering, Colorado School of Mines; M.S. in Petroleum Engineering, University of Oklahoma Joined in 2012 to manage engineering and geosciences in the Rocky Mountain region Prior: Noble Energy, Trend Exploration and Mobil E&P B.S. in Petroleum Engineering, Marietta College
Tony Buchanon
VP – Rocky Mountain Engineering
Chris Humber
SVP & General Counsel
Joined in 2011 bringing expertise in corporate law, administration, M&A, federal securities laws and stock exchange rules Prior: Kendall, Koenig and Oelsner; Hogan & Hartson; Arnold & Porter B.A. in Biology, University of Colorado; J.D., Emory University School of Law
Ryan Zorn
VP – Finance
Joined in 2012 to direct capital activities, finance and capital markets strategy Prior: Simmons & Co., Goldman Sachs, Saracen Energy Advisors and Bijou Capital B.S. in Economics, Colorado School of Mines
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Wattenberg Horizontal Niobrara Economics
(1) 100 200 300 400 500 1 8 15 22 29 36 43 50 57 64 71 78 85
(months)
312,000 Boe EUR
65% crude oil; 35% rich gas
356,000 Boe EUR
57% crude oil; 19% NGLs;
24% dry gas 85.6% WI / 69.1% NRI 321 net risked locations(3) at 80 acre
spacing (Boe/d)
Expected Type Curve(2) Field Development
(1) EUR and type curve based on internal Company estimates derived from drilling results, and may differ from the EURs and type curve used by our independent reserve engineer in connection with their 2013 audit of our reserves. (2) Natural gas reflected at 18:1 to crude oil for price; 6:1 for rate. (3) Represents estimated locations as of year end 2012 and is subject to ongoing technical review.
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DJ Basin Midstream Infrastructure
Gas Processing Capacity Existing Capacity (MMcf/d) 2013 Additions (MMcf/d) 2014 Additions (MMcf/d) Total (MMcf/d) Anadarko 359 40 300 699 Aka 20 20 DCP Midstream 410 195 230 835 Total 789 235 530 1,554 NGL Pipelines Operator Capacity (Bbl/d) Expanded Capacity (Bbl/d) Termination Hub Timing Overland Pass Pipeline Williams 140,000 Conway Existing Overland Pass Pipeline Williams 115,000 Conway Not Scheduled Enterprise NGL Rockies Enterprise 58,000 Conway Existing Wattenberg - Buckeye NGL Line DCP 22,000 Conway Existing Front Range Pipeline Enterprise 150,000
- Mt. Belvieu
Q4 - 2013 Front Range Pipeline Enterprise 80,000
- Mt. Belvieu
Not Scheduled Total 370,000 195,000 Crude Pipelines and Rail Projects Operator Capacity (Bbl/d) Origination Termination Hub Timing White Cliffs Pipeline SemGroup 70,000 Platteville, CO Cushing, OK Existing White Cliffs Expansion SemGroup 80,000 Platteville, CO Cushing, OK Q2 - 2014 Plains Rail Facility Plains 68,000 Tampa, CO Q3 – 2013 Niobrara Falls Pipeline Project NuStar Energy 75,000 Denver, CO McKee, TX Q1 – 2014 Pony Express Pipeline Kinder Morgan 230,000 Platteville, CO Cushing, OK Q3 - 2014 Total 523,000
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Easing High Line Pressures in Wattenberg
High line pressures caused by
constrained gas processing capacity
Legacy vertical wells impacted more
than newer horizontal wells
> 60% of BCEI production comes from
horizontal wells
BCEI achieving ~75% crude oil at the
wellhead in horizontal Niobrara wells
BCEI Considerations
110 MMcf/d additional capacity
(LaSalle Plant) expected online in August 2013
Additional compression being installed
1Q 2013
Planned infield pipelines decrease
system pressures
Additional Capacity
Temporary high line pressures not expected to materially impact BCEI production or growth plans in Wattenberg
Bottom Line
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North Park Basin Niobrara
(1)
50 100 150 200 250 300 350 1 8 15 22 29 36 43 50 57 64 71 78 85
(months)
(Boe/d)
EUR 211,000 Boe Initial 30-day Rate 304 Boe/d % Oil 90% Cost per Well $5.1 MM NPV-10 at $80/BO $2.1 MM NPV-10 at $100/BO $3.9 MM
Bonanza Creek acreage
(1) All performance and economic data based on EOG Resources horizontal well results. (2) Natural gas reflected at 18:1 to crude oil for price; 6:1 for rate.
2014-2015 development opportunity – EVALUATING No natural gas takeaway capacity
Type Curve(2)
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Dorcheat-Macedonia Field
(1)
(months)
152,000 Boe EUR Initial 30-day rate: 67 Boe/d Peak 30-day rate: 103 Boe/d Include subsequent recompletions 80.7 WI / 66.4% NRI 111 locations at 10 acre spacing(3) $1.7 million CapEx, including two
recompletions
12 days to drill; 3 days to complete
(Boe/d) 20 40 60 80 100 120 1 8 15 22 29 36 43 50 57 64 71 78 85 Recompletions opening additional Cotton Valley oil pay zones up hole
Type Curve(2) Field Development
(1) EUR and type curve based on internal Company estimates derived from drilling results, and may differ from the EURs and type curve used by our independent reserve engineer in connection with their 2013 audit of our reserves. (2) Natural gas reflected at 18:1 to crude oil for price; 6:1 for rate. (3) Locations as of YE 2012 at 10-acre spacing in Cotton Valley oil sands.
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Mid-Continent Gas Processing Facilities
Nevada Columbia Lafayette
Dorcheat-Macedonia McKamie-Patton
Dorcheat Gas Facilities McKamie Gas Facility
BCEI Fields BCEI Pipeline Centerpoint Gas Duke Energy Texas Eas tern
Lewisville
General Overview
Approximately 150 miles of gathering lines Processes minor quantities of third party natural gas Facilities interconnect into the CenterPoint Energy pipeline system NGL pricing historically averages approximately 66% of WTI (ethane sold in gas stream)
Dorcheat Gas Processing Facility
12.5 MMcf/d of natural gas (28,000 gallons per day of natural gas liquids) processing capacity Additional 12.5 MMcf/d of capacity to be online in Q1
- 2013. Expansion at current Dorcheat site
McKamie Gas Processing Facility
15 MMcf/d of natural gas (30,000 gallons per day of natural gas liquids) processing capacity
Gas Facilities Enhance Total Returns
The facility significantly increases EBITDAX margins for the asset over the life of the well Sole ownership and control of facilities allows Company to capture the additional high margin liquids value of the assets, not a third party
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Reconciliation to Adjusted Net Income
This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which exclude (1) unrealized gain or loss on commodity derivatives, (2) non-cash stock compensation expense, (3) impairment of proved properties and (4) exploratory well abandonment. The amounts included in the calculation of adjusted net income and adjusted net income per diluted share, below, were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following tables provide a reconciliation of adjusted net income for the three and nine months ended September 30, 2012 and 2011, respectively.
Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 Net Income $ 3,421 $ 4,833 $ 33,473 $ 12,868 Unrealized (gain) loss in fair value of derivatives 9,007 (8,268) (2,985) (7,096) Stock-based compensation 1,446 133 2,912 133 Impairment 1,917 4,067 1,917 4,067 Exploration 5,846
- 7,379
- Total adjustments before tax
18,216 (4,068) 9,223 (2,896) Adjusted for income tax effects 11,203 (2,502) 5,672 (1,781) Adjusted net income $ 14,624 $ 2,331 $ 39,145 $ 11,087 Adjusted net income per diluted share $ 0.37 $ 0.08 $ 0.97 $ 0.38
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Reconciliation to EBITDAX
We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) stock-based compensation expense, (4) interest expense, (5) unrealized loss (gain) on commodity derivatives, and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a Company’s ability to internally fund development and exploration activities. This measure is provided in addition to, not as an alternative for and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following table provides a reconciliation of EBITDAX to net income for the three and nine months ended September 30, 2012 and 2011, respectively.
Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 Net Income $ 3,421 $ 4,833 $ 33,473 $ 12,868 Exploration 6,365 19 9,581 573 Depletion, depreciation, and amortization 18,286 7,304 43,901 21,083 Impairment of proved properties 1,917 4,067 1,917 4,067 Stock-based compensation 1,446 133 2,912 133 Gain on sale of oil and gas properties (4,280)
- (4,280)
- Interest expense
1,126 1,122 2,342 2,687 Unrealized loss (gain) on commodity derivatives 9,007 (8,268) (2,985) (7,096) Income taxes (benefit) 2,315 6,771 21,129 11,464 EBITDAX $ 39,603 $ 15,981 $ 107,990 $ 45,779 EBITDAX per diluted share $ 1.00 $ 0.55 $ 2.74 $ 1.57
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Reconciliation to Discontinued Operations
3Q 2012 Sales Volumes Continuing Operations 9,402 Boe/d Discontinued Operations 143 Boe/d Total 9,545 Boe/d
Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 NET REVENUES Oil and gas sales $ 58,328 $ 25,915 $ 157,613 $ 70,609 OPERATING EXPENSES: Lease operating 8,444 4,686 22,506 12,041 Severance and ad valorem taxes 3,022 1,343 9,387 3,779 Exploration 6,359 19 9,564 566 Depreciation, depletion and amortization 17,716 6,330 41,751 18,472 Impairment of proved properties 269 623 269 623 General and administrative 9,335 4,179 22,410 9,116 Total operating expenses 45,145 17,180 105,887 44,597 INCOME FROM OPERATIONS 13,183 8,735 51,726 26,012 OTHER INCOME (EXPENSE): Other income (loss) (91) (3) (83) (101) Interest expense (1,125) (1,122) (2,342) (2,687) Unrealized (loss) in fair value of commodity derivatives (9,007) 8,268 2,985 7,096 Realized (loss) in fair value of commodity derivatives (93) (519) (1,173) (2,353) Total other income (loss) (10,316) 6,624 (613) 1,955 INCOME FROM CONTINUING OPERATIONS BEFORE TAXES $ 2,867 $ 15,359 $ 51,113 $ 27,967 Income tax expense (1,223) (8,528) (19,797) (13,176) INCOME FROM CONTINUING OPERATIONS 1,644 6,831 31,316 14,791 DISCONTINUED OPERATIONS Income (loss) from operations associated with oil and gas properties held for sale (1,410) (3,755) (792) (3,635) Gain on sale of oil and gas properties 4,280
- 4,280
- Income tax (expense) benefit
(1,093) 1,757 (1,331) 1,713 Income associated with oil and gas properties held for sale 1,777 (1,998) 2,157 (1,922) NET INCOME $ 3,421 $ 4,833 $ 33,473 $ 12,869 BASIC AND DILUTED INCOME PER SHARE Income from continuing operations $ 0.04 $ 0.23 $ 0.79 $ 0.51 Income (loss) from discontinued operations $ 0.05 $ (0.06) $ 0.06 $ (0.07) WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED 39,477 29,123 39,476 29,123