TSX:CFW CALFRAC WELL SERVICES LTD. Investor Presentation – Q3 2017
Forward Looking Statement Certain information contained within this presentation and statements made in conjunction with this presentation constitute forward-looking statements. These statements relate to future events or the future performance of the Company. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate,” “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, “forecast”, “can” and similar expressions. In particular, forward -looking statements in this presentation include, but are not limited to, statements with respect to future capital expenditures, future financial resources, anticipated equipment utilization levels, future oil and gas well activity, projections of market prices and costs, outcomes of specific events and trends in the oil and gas industry. The forward-looking statements within this presentation and made in conjunction with this presentation are derived from certain assumptions and analyses made by the Company based on its experience and perception of historical trends, current conditions, expected future developments and other factors that it believes are appropriate in the circumstances, including assumptions and analyses relating to: the economic and political environment in which the Company operates; the Company’s expectations for its customers’ capital budge ts and geographical areas of focus; the effect unconventional oil and gas projects have had on supply and demand fundamentals for oil and natural gas; the Company’s existing contracts and the status of current negotiations with key customers and suppliers; the effectiven ess of cost reduction measures instituted by the Company; and the likelihood that the current tax and regulatory regime will remain substantially unchanged. Forward-looking statements are subject to a number of known and unknown risks and uncertainties that could cause actual results to differ materially from the Company’s expectations. Such risks and uncertainties include the items discussed under the heading “Business Risks” in the Company’s 2016 Annual Report and under the heading “Risk Factors” in the Company’s most recently filed Annual Information Form. Consequently, all of the forward-looking statements contained within this presentation and made in conjunction with this presentation are qualified by these cautionary statements and there can be no assurance that actual results or events anticipated by the Company will be realized or that they will have the expected consequences or effects on the Company or its business or operations. Other than as required by applicable securities laws, the Company assumes no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.
Global Pressure Pumping Presence As at June 30, 2017 Canada Fleet: 407,000 HHP – 250,000 HHP Active 13 Coiled Tubing Units – 9 Active Units U.S. Fleet: Russia Fleet: 718,000 HHP – 432,000 HHP Active 70,000 HHP 11 Cementing Units – 11 Units Idle 7 Coiled Tubing Units – 6 Active Units 5 Coiled Tubing Units – 5 Units Idle Latin America Fleet: 122,000 HHP 14 Cementing Units Active 7 Coiled Tubing Units Active
Active Rig Counts: North America 2,000 700 Number of Active WCSB Land Rigs 1,800 600 1,600 500 1,400 Number of Rigs 1,200 400 1,000 300 800 200 600 400 100 200 0 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 2013 2014 2015 2016 2017 Lower 48 Active Land Rig Count - U.S. land rig count up ~150% from trough, still ~50% below 2014 - WCSB YTD rig count in line with 2015, up ~80% from 2016 - E&P spending plans to be higher by ~40% in 2017 - Capital spending in 2018 is forecast to be relatively consistent with 2017 Source: Baker Hughes
Pumping Intensity Could Sell Out Lower 48 Market 2017 2014 - 1,800 rigs - ~900 rigs ~4,000 tons/well ~6,000 tons/well - Per well metrics growing - 3 rigs / spread - ~2-2.5 rigs / spread - Sand & Fluid - 600 spreads required - 400 - 450 spreads required - Fracture design evolving - Higher Rates - Spreads typically - Average spread 45,000 HHP+ - Higher Pressure 30,000 HHP - ~12MM active HHP - Improved Productivity - More Redundancy - Fully booked fracturing - Demand for full reactivation to market 15MM+ HHP - 18MM HHP in Lower 48 - >2MM HHP Exited US Market
U.S. Intensity Continues To Increase Proppant Tonnage per Well (U.S. Land) 18 Eagle Ford Bakken 16 Haynesville Permian Niobrara Total U.S. 14 12 Sand/Well (MMlbs) 10 8 6 4 2 0 2011 2012 2013 2014 2015 2016 2017 Source: Evercore ISI
Canadian Intensity Following US Trends 2.5 Proppant use per well more than double 2013 level 2.0 1.5 Well count recovery (2016 +40%) implies fracturing demand in line with 2014 WCSB Fleet 10% smaller than 2014 1.0 Well count down 43% 0.5 from 2014 peak 0.0 2013 2014 2015 2016 2017F Well Count Proppant per Well Total Demand Source: Frac Database, TD Securities
MANAGING THE RECOVERY
Margin Trend Reversal Underway CFW Q2 Result 2017? Source: Company Reports, Morgan Stanley
Our License to Operate HSE Plan ▪ Do ▪ Assess ▪ Adjust QUALITY Monitor ▪ Refine ▪ Execute ▪ Improve TECHNOLOGY Research ▪ Develop ▪ Test ▪ Refine SUPPLY CHAIN Evaluate ▪ Negotiate ▪ Finalize ▪ Implement Calfrac employee on a Canadian hydraulic fracturing job . Calfrac Well Services Photo Calfrac sand terminal in Whitecourt, Alberta . Calfrac Well Services Photo
Managing The Recovery – People Field Staff Recruiting – Added over 600 field personnel across North America – WCSB local market essentially at full employment – Safety and operating competency focus for new hires Increased Field Pay and Salaries – Fulfills a promise made to employees Rotational Employee Program Reactivated Biggest Challenge to Growth in North America
Managing The Recovery - Equipment Equipment reactivations progressing ► Costs meeting expectations (~$2 million per spread) ► Coil Tubing reactivations in Canada to support increased fracturing demand Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Increase Active Fleets - US 4 5 5 6 8 12 200% Active Fleets - Canada 4 4 4 6 6 7 75% Active HHP - North America 381,400 443,900 459,000 526,200 587,750 682,000 79% In discussions in all areas of North America for further reactivations ► Re-establish operations in TX in Q3 Will not sacrifice profitability or safety/flawless execution culture ► Seek to use reactivation discussions as pricing catalyst ► Selectively align with key customers
Managing The Recovery – Technology Maintain investment in technology – Have generated 47 new products in 2015-2017 – Research continues in all applications Increasing focus on equipment – Intensity increases continue across North America – Move to stainless steel fluid ends – API Q2 framework generates significant operating data for analysis/action
Managing The Recovery – Finance Reactivation costs are consistent with forecasts – Costs driven by previous decisions ► Park in working condition or park at failure – Less than $2 million for a small (~20,000 HHP) fracturing fleet – Up to $3 million for a larger (~40,000 HHP) fracturing fleet Increased capital spend to support larger active fleets – Typical maintenance capital items – No surprises to date on life-cycle spending (fluid ends, etc.) Looking at balance sheet in the longer term – Mid-cycle cash flow – Capital expansion plans – Interest payments – Maturity of term debt – Currency mix
Canadian Sand Logistics Advantage Exclusive Sand Terminal Locations: • Taylor, BC • Whitecourt, AB • Kuusamo, AB • Glidden, SK Merchant Terminal Location: • Grande Prairie
FINANCIAL INFORMATION
The Balance Sheet Term Debt US$600 million with an interest rate of 7.5% Matures in 2020 Second Lien Term Loan $200 million with an interest rate of 9.0% Matures in 2020 Credit Facilities Loan facility $300 million (largely undrawn) Matures in 2018 Recent Equity Financing Raised $60 million, proceeds used to fund second equity cure ($25 million) and provide additional liquidity 1 st equity cure elected in Q2 – Capital Program 2017 capital budget set at $65 million Neuquén, Argentina Frac Operation (2014). Calfrac Well Services Photo
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