Ridgeback Resources Corporate Presentation October 2019 Disclaimer - - PowerPoint PPT Presentation
Ridgeback Resources Corporate Presentation October 2019 Disclaimer - - PowerPoint PPT Presentation
Ridgeback Resources Corporate Presentation October 2019 Disclaimer Forward Looking Statements This presentation may contain "forward-looking statements" within the meaning of applicable securities legislation, including estimates
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Disclaimer – Forward Looking Statements
This presentation may contain "forward-looking statements" within the meaning of applicable securities legislation, including estimates of future production, cash flows and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results “may", "could", "would", "might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining, to the following: estimates of infrastructure processing capacity, well costs, payout and IRR estimates. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and the future cash flow attributed to such reserves. The reserve and associated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future
- perating expenses, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. Unless otherwise noted, reserves
referenced herein are given as at December 31, 2016. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates and future net revenue for all properties due to the effect of aggregation. All forward-looking statements are based on Ridgeback’s beliefs and assumptions based on information available at the time the assumption was made. Ridgeback believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. Risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations; pipeline restrictions; infrastructure construction schedule delays and cost overruns; blowouts; the risk of carrying
- ut operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations
and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These risks and uncertainties could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent. Ridgeback assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party sources. The information provided herein has not been independently audited or verified by the Company.
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AB SK
Corporate Snapshot
Operating & Financial 2017(1) 2018 2019e
Production (boe/d) 21,000 22,808 23,000 Oil & NGL Weighting (%) 71% 75% 74% Exit December (boe/d) 21,050 25,725 25,700 Net Debt Year-End ($MM) $267 $251 $181(2) Year End Debt to Adjusted Funds Flow 1.9x 1.2x 0.8x Operating Netback ($/boe) $24.12 $30.61 $29.65 Adjusted Funds Flow from Operations ($MM) $142 $211 $218(2) Capital Expenditure ($MM)(4) $111 $175 $148 Free Cash Flow ($MM) $31 $36 $70 1P Reserves(3) (MMBoe) 75 80 2P Reserves(3) (MMBoe) 114 118 Average Corporate Decline Rate ~27%
- Large oil-in-place assets with exploitation and
- ptimization opportunities
- ~88% operated + ~70% WI in focused
core areas
- Repeatable, low-risk growth complemented by
higher-impact drilling opportunities Light oil weighted asset base
Kaybob Montney West Pembina Cardium SE Sask Bakken & Mississippian Deer Mountain Swan Hills
1 2017 operations reflect only 6 months of new management and strategic direction 2 Based on 2019 strip pricing , as of August 13, 2019, of WTI $56.98/bbl, US$5.15/bbl Light Oil Differential, AECO $1.53/GJ, and $0.754 CAD/US F/X 3 Sproule year-end 4 Includes ARO spending
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Strategic Priorities
1) Focus on Value Creation and Capital Efficiency
- Spend within cash flow to grow production, reserves, inventory and ideas
- Execute on identified, high graded inventory with focus on returns and capital efficiencies
- Manage all costs (capital, operating and G&A) and focus on attention to detail
2) Protect the Balance Sheet
- Respond quickly to changes in commodity prices
- Continue to reduce debt
3) Continue to Grow Ridgeback
- Develop current assets
- Consolidate interests in core areas and opportunistically acquire assets
- Pursue consolidation and other opportunities for liquidity
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2018 Highlights
- Average annual production of 22,808 boe/d (75% crude and NGLs); +8% increase year-over-year
- 2018 year-over-year exit growth of 22%
- Crude oil and liquids volumes +19% year-over-year
- Achieved production growth spending 83% of cash flow and reducing debt, supporting 2018
production per debt-adjusted share growth of 13%
- Adjusted funds flow from operations of $211MM or $2.09/share (basic & diluted); +48% over 2017
- Production expenses of $13.61/boe was down 4% year-over-year
- 2018 G&A reduced to $2.04/boe vs $3.06/boe in 2017, largely due to streamlining through
restructuring
- Capital expenditures totaled $193.2MM including ARO and $17.4mm of A&D spending
- Spud 66 (56.3 net) wells and made significant infrastructure investment at Kaybob
- Replaced 185% of production and added 4 mmboe total proved plus probable reserves
- Net debt reduced to ~$251MM, improving year-end D/CF to 1.2x, compared to 1.9x at year-end 2017
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1H 2019 Highlights
- Average production of 23,801 boe/d (74% crude and NGLs); 6% increase compared to 1H 2018
- Capital expenditures of only $21.2MM in first half
- Adjusted funds flow from operations of $122.5MM – 11% higher than 1H 2018 – despite lower
realized crude oil pricing
- Operating costs of $12.08/boe – a reduction of $1.75/boe relative to 1H 2018
- At June 30, 2019, net debt totalled $150.7MM – reduction of $100.7MM from $251.4MM at
December 31, 2018 – improving debt to cash flow to 0.6 times from 1.2 times at year end 2018
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1H19 2019 Operating Results
Six Months ended June 30
2019 2018 Production Crude oil (bbl/d) 15,225 14,491 NGL (bbl/d) 2,343 2,185 Natural gas (mcf/d) 37,395 34,359 Total (boe/d) 23,801 22,402 Liquids weighting 74% 74% Average prices (CDN $) WTI ($/bbl) 76.51 83.59 Crude oil ($/bbl) realized 69.43 76.12 Natural gas ($/mcf) 2.00 1.77 Natural gas liquids ($/bbl) 23.94 36.94 Combined ($/boe) 49.91 55.56 Total with hedging ($/boe) 49.35 52.48 Operating netback ($/boe)(ex hedging) 31.39 34.37 Operating cost ($/boe) 12.08 13.84 Net G&A ($/boe) 1.98 2.01
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1H 2019 Financial Results
Six Months ended June 30
2019
($MM)
2018
($MM)
Oil & Natural Gas Sales 215,021 225,290 Adjusted Funds Flow from Operations 122,543 110,125 Net Income (loss) 11,924 (6,034) Capital Expenditures 21,2013 61,863 Net Debt 150,715 220,763 Debt to Annualized Cash Flow 0.61 1.00
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Reserves – YE 2018
Category Oil & NGL mmbbl) Gas (bcf) Total (mmboe) BT NPV10 ($MM) Proved developed producing 31.3 77.3 44.2 850 Proved developed non-producing 1.2 2.9 1.7 26 Proved undeveloped 25.7 50.2 34.1 273 Total proved 58.2 130.5 80.0 1,149 Probable developed producing 9.3 19.0 12.5 192 Probable developed non-producing 0.6 1.4 0.8 12 Probable undeveloped 18.9 35.7 24.8 320 Total probable 28.8 56.1 38.1 525 Total proved plus probable 87.0 186.5 118.1 1,674
- 2018 development program consisted of 66 gross (56.3 net) wells
- PDP reserves = 37% of total P+P
- P+PDP reserves = 48% of total P+P
Quality reserve bookings underpin value creation strategy
*Sproule December 31, 2018 Numbers may not add due to rounding
Bakken 29% Mississippian 5% Kaybob 5% West Pembina 25% Brazeau 17% Other Alberta 19%
2P Reserves (mmboe)
Bakken 38% Mississippian 8% Kaybob 6% West Pembina 26% Brazeau 8% Other Alberta 14%
2P BT NPV10 ($mm)
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Drilling Inventory
Area Gross Booked Locations Net Booked Locations S.E. Saskatchewan – Bakken 298 233 S.E. Saskatchewan – Mississippian 33 26 Cardium 223 156 Deer Mountain – Swan Hills 32 29 Kaybob – Montney 23 23 Other 10 3 Total 619 470
Conventional & unconventional plays in four core areas:
- Southeast Saskatchewan:
- Bakken
- Mississippian
- Central Alberta
- Cardium and Mannville
- Kaybob
- Montney
- Deer Mountain
- Swan Hills
>600 Booked locations ~10 years of drilling inventory All locations reviewed and ranked by technical team
Unbooked inventory represents an additional ~480 gross (~360 net) locations
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Southeast Saskatchewan - Bakken
Light oil-weighted opportunities with low risk, repeatable, infill and delineation drilling
- Large Oil in Place:
4.5 mmbbls/sec
- Depth:
~1,600m
- Oil quality:
40 API sweet
- Well spacing:
4-8 wells/sec
- Drilling locations:
298 gross (233 net) booked 196 gross (149 net) unbooked
- 2019 DCET capex:
$38MM 32 gross (24.7 net) wells
Assumptions:
- Flat US$60/bbl WTI
- $1.56MM DCET cost
- IP 120bbl/d (150boe/d)
- EUR 60mbbl (70mboe)
- 2.2 yrs payout
37% IRR Single well, half-cycle economics
Downspacing offers significant long-term growth potential
SK
SE Sask Bakken
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Southeast Saskatchewan - Mississippian
- Large Oil in Place:
5-10 mmbbl/sec
- Depth:
~1,300m
- Oil quality:
35 API
- Well spacing:
150m inter well
- Drilling locations:
33 gross (26 net) booked Significant unbooked potential
- 2019 DCET capex: $6MM
6 gross (5.5 net) wells
Conventional openhole play offers low-risk development with exploration upside
Assumptions:
- Flat US$60/bbl WTI
- $1.0MM DCET cost
- IP 115bbl/d
- EUR 55mbbl
- 0.9 yr payout
135% IRR Single well, half-cycle economics
Existing company infrastructure allows for reserve base growth with minimal capital requirements
SK
SE Sask Mississippian
Ridgeback has gathered considerable data supporting Mississippian development while exploiting the underlying Bakken
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West Pembina – Cardium
Assumptions:
- Flat US$60/bbl WTI
- $3.56MM DCET cost
- IP 240bbl/d (275boe/d)
- EUR 160mbbl (230mboe)
- 1.9 yrs payout
46% IRR Single well, half cycle economics – 1.5 mile
Extended reach horizontal drilling using advanced well targeting & frac designs
AB
West Pembina Cardium
Well defined development fairway provides repeatable, low-risk growth
- Large Oil in Place:
~5 MMbbl/sec
- Depth:
~1,800m
- Oil quality:
40 API sweet
- Well spacing:
4 wells / sec
- Drilling locations:
110 gross (68 net) booked 62 gross (48 net) unbooked
- 2019 DCET capex: $44MM
15 gross (12.3 net) wells
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Kaybob - Montney
Significant, 100% working interest land position
- Large Oil in Place:
10 MMbbl/sec
- Depth:
1,850m
- Oil quality:
35-40 API, 1.5% sour
- Well spacing:
6 wells / sec
- Drilling locations:
23 gross (23 net) booked 6 unbooked
- 2019 DCET capex: $16MM
5 gross (5 net) wells
Assumptions:
- Flat US$60/bbl WTI
- $3.24MM DCET cost
- IP 560bbl/d (670boe/d)
- EUR 200mbbl (365mboe)
- 0.8 yrs payout
150% IRR Single well, half cycle economics – 1.5 mile
Geological mapping supports the
- ffsetting Triassic G (Montney) oil
pool extension onto Ridgeback’s lands
Kaybob Montney
AB
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Summary
- Capital spending within cash flow and managing costs in all aspects of the business
supports value creation and capital efficiencies
- Supported by sophisticated, patient, large shareholders
- High-quality, focused asset base with large oil-in-place
- Low corporate decline underpins production and provides stable cash flow while
executing on business plan
- Multi-year drilling inventory supports visibility towards 28,000-30,000 boe/d of
production
- Supplement organic growth through consolidation and potential liquidity opportunities
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Leadership Team
Board of Directors
- J. Paul Charron
Executive Chairman & CEO Jason Scheir Apollo Management Jonathan L. Shifke GSO Capital Partners Michael Tu Apollo Management
Management
- J. Paul Charron, B.Comm., C.A., C.P.A.
Executive Chairman & CEO CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim , Ketch David J. Broshko, B.Comm., C.A., C.P.A., C.Dir. President CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim, Paramount Paul L. Massé, P.Tech. (Eng.) Chief Operating Officer CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim Cory Dean, C.E.T. VP, Business Development CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim, Landover, Northrock Thomas J. Emerson, B.A. VP, Land CanEra Inc., CanEra Energy Corp., CanEra Resources, Cyries, Burlington, Canadian Hunter Sean Kinoshita, P.Eng. VP, Production CanEra Inc., CanEra Energy Corp., CanEra Resources, Peyto, Husky, Renaissance Frank Serpico, B.A. VP, Marketing SanLing Energy, Spyglass Resources, Pace Oil & Gas, Provident Energy David W. Sakal, B.Sc., P.Eng VP, Operations CanEra Inc., CanEra Energy Corp., CanEra Resources, Focus , Renaissance Jeffrey R. Wallace, B.Sc., P.Geol. VP, Exploration CanEra Inc., Legacy Oil + Gas, CanEra Resources, Canetic, Penn West, Trioil, Yangarra, Rider, Husky, Renaissance Annie Belecki, B.A., LL.B. General Counsel Lightstream, TCPL
- Seasoned management team
- Worked together in multiple successful
corporate iterations
- Strong buy-&-exploit value-creation
record
- Demonstrated ability to access quality
deal flow and transact
- Ability to opportunistically monetize
- Patient & strong private equity support in
current environment
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Private Equity Sponsors
Apollo Global Management New York, N.Y. A leading global alternative investment manager with over US$232 billion in investor commitments across its private equity, credit and real estate funds and other investment vehicles. GSO Capital Partners New York, N.Y. One of the largest credit-oriented alternative asset managers in the world with assets under management of US$139 billion. 525 – 8th Ave SW, Ste 2800 Calgary, AB T2P 1G1 Canada (403) 268-7800 www.ridgeback.com
Corporate Information
Independent Engineers Sproule & Associates, Ltd Auditors Deloitte LLP Legal Counsel Blakes, Cassels & Graydon LLP Banking Syndicate Toronto Dominion Bank, Royal Bank of Canada, Bank of Montreal, Bank of Nova Scotia, Canadian Imperial Bank of Commerce, National Bank of Canada, Alberta Treasury Branches , Executive Chairman & CEO T: (403) 218-8989 E: pcharron@ridgeback.com , President T: (403) 218-8985 E: dbroshko@ridgeback.com
APPENDIX
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Ridgeback Hedge Position(1)
1 Hedge position as at October 4, 2019 3 WTI hedges are transacted in both CAD and USD but are presented in US @ $0.7560
BOE (bbl/d) ($/bbl) (bbl/d) Long Put Short Call (bbl/d) Short Put Long Put Short Call (bbl/d) ($/bbl) (bbl/d) ($/bbl) (boe/d) 3Q19 0.00 4,000 45.24 70.12 3,500 44.29 50.08 60.84 7,500 47.50 4,000 10.19 7,500 4Q19 0.00 5,000 46.79 67.61 2,750 44.66 50.10 61.35 7,750 47.97 4,000 10.19 7,750 1Q20 2,500 54.44 5,500 55.13 61.93 0.00 0.00 0.00 8,000 54.92 500 10.45 8,000 2Q20 2,500 54.44 5,500 55.13 61.93 0.00 0.00 0.00 8,000 54.92 500 10.45 8,000 3Q20 1,000 53.59 1,000 53.08 58.46 0.00 0.00 0.00 2,000 53.34 500 10.45 2,000 4Q20 1,000 53.59 1,000 53.08 58.46 0.00 0.00 0.00 2,000 53.34 500 10.45 2,000 WTI Hedges (USD)3 MSW Diff. (USD) Swaps 3-Way Total WTI Basis Swaps Collars
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Track Record of Value Creation – CanEra
Entity Equity Commitment (C$MM) Acquisition Cost (C$MM) Equity Invested (C$MM) Exit (C$MM) Annualized Return on Equity (%) MOIC (x)
CanEra Resources Inc. (2008-10)
Private Equity Sponsors: Riverstone Holdings & Natural Gas Partners
$350 $300 $204 $603 160% 2.3x CanEra Energy Corp. (2010-14)
Private Equity Sponsors: Riverstone Holdings & Natural Gas Partners
$390 $766 $425 $1,100 35% 1.8x CanEra Inc. (2015-17)
Private Equity Sponsors: Riverstone Holdings & Natural Gas Partners
- Committed $450MM of equity
- ~$3B of potential transactions evaluated from Sept 2014 to Nov 2016
- No transactions completed; wound up in Feb 2017