Ridgeback Resources Corporate Presentation · 2019-10-04 · in the future. There are numerous...
Transcript of Ridgeback Resources Corporate Presentation · 2019-10-04 · in the future. There are numerous...
Ridgeback ResourcesCorporate Presentation
October 2019
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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 andreserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and relatedsensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrasessuch 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 ofinfrastructure processing capacity, well costs, payout and IRR estimates. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the impliedassessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably producedin 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 andassociated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserverecovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and futureoperating expenses, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. Unless otherwise noted, reservesreferenced 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 asestimates 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 oninformation available at the time the assumption was made. Ridgeback believes that the expectations reflected in these forward-looking statements are reasonable but no assurancecan 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 fromthose anticipated, expressed or implied by such statements. Risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility inmarket prices for oil and natural gas; delays in business operations; pipeline restrictions; infrastructure construction schedule delays and cost overruns; blowouts; the risk of carryingout operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulationsand 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 areasonable cost; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel ormanagement; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processingproblems; availability of insurance; fluctuations in foreign exchange and interest rates; general economic, market and business conditions; uncertainties associated with regulatoryapprovals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crownroyalty 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 thoseanticipated, 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 certaintyas these are interdependent. Ridgeback assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certaininformation 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
optimization 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 MountainSwan Hills
1 2017 operations reflect only 6 months of new management and strategic direction2 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/X3 Sproule year-end4 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 302019 2018
ProductionCrude 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
CategoryOil & NGLmmbbl)
Gas(bcf)
Total(mmboe)
BT NPV10($MM)
Proved developed producing 31.3 77.3 44.2 850
Proved developed non-producing 1.2 2.9 1.7 26
Proved undeveloped 25.7 50.2 34.1 273
Total proved 58.2 130.5 80.0 1,149
Probable developed producing 9.3 19.0 12.5 192
Probable developed non-producing 0.6 1.4 0.8 12
Probable undeveloped 18.9 35.7 24.8 320
Total probable 28.8 56.1 38.1 525
Total proved plus probable 87.0 186.5 118.1 1,674
2018 development program consisted of 66 gross (56.3 net) wells
PDP reserves = 37% of total P+P
P+PDP reserves = 48% of total P+P
Quality reserve bookings underpin value creation strategy
*Sproule December 31, 2018Numbers may not add due to rounding
Bakken
29%
Mississippian5%Kaybob
5%West Pembina
25%
Brazeau17%
Other Alberta19%
2P Reserves (mmboe)
Bakken38%
Mississippian8%
Kaybob6%
West Pembina
26%
Brazeau8%
Other Alberta14%
2P BT NPV10 ($mm)
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Drilling Inventory
Area
Gross Booked
Locations
NetBooked
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) booked196 gross (149 net) unbooked
2019 DCET capex: $38MM32 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) bookedSignificant unbooked potential
2019 DCET capex: $6MM6 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) booked62 gross (48 net) unbooked
2019 DCET capex: $44MM15 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) booked6 unbooked
2019 DCET capex: $16MM5 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 offsetting Triassic G (Montney) oil
pool extension onto Ridgeback’s lands
KaybobMontney
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
ManagementJ. 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.EngVP, 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 ManagementNew 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 PartnersNew 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 2800Calgary, AB T2P 1G1 Canada(403) 268-7800www.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 & CEOT: (403) 218-8989E: [email protected]
, PresidentT: (403) 218-8985E: [email protected]
APPENDIX
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Ridgeback Hedge Position(1)
1 Hedge position as at October 4, 20193 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 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 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 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 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 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 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 SwapsCollars
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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