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| 8-K - 8-K - PIONEER ENERGY SERVICES CORP | form8k-invpres2x27x2014.htm |
SIMMONS & COMPANY 14TH ANNUAL ENERGY CONFERENCE February 27th, 2014
Forward-looking Statements 2 This presentation contains various forward-looking statements and information that are based on management’s current expectations and assumptions about future events. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” and other words that convey the uncertainty of future events and outcomes. Forward-looking information includes, among other matters, statements regarding the Company’s anticipated growth, quality of assets, rig utilization rate, capital spending by oil and gas companies, production rates, the Company's growth strategy, and the Company's international operations. Although the Company believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations and assumptions will prove to have been correct. Such statements are subject to certain risks, uncertainties and assumptions, including general economic and business conditions and industry trends, levels and volatility of oil and gas prices, decisions about exploration and development projects to be made by oil and gas exploration and production companies, risks associated with economic cycles and their impact on capital markets and liquidity, the continued demand for the drilling services or production services in the geographic areas where we operate, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility and our senior notes, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, changes in technology and improvements in our competitors’ equipment, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. Should one or more of these risks, contingencies or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those expected. Many of these factors have been discussed in more detail in the Company's annual report on Form 10- K for the fiscal year ended December 31, 2013. Unpredictable or unknown factors that the Company has not discussed in this presentation or in its filings with the Securities and Exchange Commission could also have material adverse effects on actual results of matters that are the subject of the forward-looking statements. All forward-looking statements speak only as the date on which they are made and the Company undertakes no duty to update or revise any forward-looking statements. We advise our shareholders to use caution and common sense when considering our forward-looking statements.
Pioneer Energy Services 3 (1) As of December 31, 2013 (2) Debt and cash as of December 31, 2013; Market Capitalization as of February 21, 2014 TICKER SYMBOL: PES (NYSE) TTM REVENUE(1): $960 MILLION MARKET CAPITALIZATION(2): $642 MILLION ENTERPRISE VALUE(2): $1.1 BILLION SERVICE LINES: LAND DRILLING, WELL SERVICING, WIRELINE, COILED TUBING EMPLOYEES: 3,650
Diversified Services 4 % of TTM REVENUE(1) (1) Revenue breakdown based on trailing twelve month revenue as of December 31, 2013 of $960MM DRILLING SERVICES Drilling Services - US 54 Rigs Drilling Services – Colombia 8 Rigs Total Drilling 62 Rigs PRODUCTION SERVICES Well Servicing 109 Rigs Wireline 120 Units Coiled Tubing 13 Units Production Services 45% Drilling - Colombia 12% Drilling - US 43%
Recent Updates 5 Drilling Services • Utilization in January was 82%. Current utilization is 87%(1). Colombia • Seven of eight rigs are currently working Production Services • Well servicing utilization in January was 89% • Coiled tubing utilization in January was 41% (1) As of February 24, 2014
Investment Considerations Summary 6 • Mix of service lines provides exposure to the full well life cycle including drilling, completions, workovers, and on-going well maintenance • Approximately 60% of US revenue(1) attributable to the Bakken shale, Eagle Ford shale, and Permian, all with long-term, robust activity outlooks • Industry-leading safety results continue to strengthen our activity levels and client base • Increased free cash flow generation allows us to de-lever through 2014 • Post de-levering, continued organic growth opportunities in all core service lines (1) Trailing twelve months as of December 31, 2013
Exposure to the Full Well Life Cycle 7 Plug and Perforate Toe Prep Drilling Maintenance until Plug and Abandon Drill Out Plugs Complete and Install Artificial Lift
Production Services 48% Drilling Services 52% Leverage to Premier Unconventional Plays 8 B AKKEN SHA LE EA G LE F ORD SHA LE (1) TTM revenue and unit locations as of December 31, 2013 % of TTM Revenue(1) PER M IA N Pioneer Fleet Exposure Production Services 52% Drilling Services 48% Drilling Services 93% Production Services 7% Drilling Well Servicing Wireline Coiled Tubing 18% 13% 15% 0% 11 RIGS 14 RIGS 18 UNITS Drilling Well Servicing Wireline Coiled Tubing 15% 19% 10% 31% 9 RIGS 12 UNITS 4 UNITS 21 RIGS Drilling Well Servicing Wireline Coiled Tubing 29% 0% 6% 0% 18 RIGS 7 UNITS
Top-tier Safety 9 • Among the 15 largest land contract drillers in the United States, Pioneer Energy Services was the safest in 2011, and 2nd safest in 2012 as reported through the IADC • For the Association of Energy Service Contractors (AESC) Annual Safety Awards, Pioneer Well Servicing was awarded 1st place in 2011 and 3rd place in 2012 for Division IV, and 1st place in 2013 for Division V (largest division) 0 1 2 3 4 5 6 7 PES 0 1 2 3 4 5 6 7 PES Total Recordable Incident Rate Drilling Contractors – US Land Top 15 busiest contractors by man-hours in 2012 Total Recordable Incident Rate Drilling Contractors – US Land Top 15 busiest contractors by man-hours in 2011
Note: All data points reflect information derived from 10-K and 10-Q filings. Please refer to Reconciliation of Adjusted EBITDA to Net Income on slide 22 Cash Flow Generation and Debt Reduction 10 • From June 2013 through December 2013, borrowings on the revolver were reduced by $60MM • Additional debt reduction is expected throughout 2014 $70 $63 $56 $60 $56 $64 $59 $56 $95 $99 $97 $73 $71 $41 $26 $27 $0 $20 $40 $60 $80 $100 $120 ($ m ill io n s) Adjusted EBITDA CAPEX Spend
Future Growth Opportunities (post de-levering) 11 Focus is on providing four core services in the significant unconventional plays in the U.S. CURRENT SERVICES BY PLAY Drilling Wireline Well Servicing Coiled Tubing Bakken Eagle Ford Permian Marcellus/Utica Niobrara Uinta
12 PRODUCTION SERVICES
Well Servicing 13 • Of the top-tier well servicing providers, Pioneer has the: • Highest utilization rate • Highest average hourly rate • Highest average horsepower fleet with all rigs either 550HP or 600HP • Highest percentage of taller mast rigs with all masts either 104’, 112’ or 116’ in height • 100% of rigs are capable of working in the unconventional plays • Established in the Bakken, Eagle Ford, Fayetteville, Haynesville and Tuscaloosa Marine Shale (1) Year-end rig count SERVICE OVERVIEW OPERATING LOCATIONS FLEET GROWTH(1) 74 74 89 108 109 112 2009 2010 2011 2012 2013 2014E
Wireline 14 • Leading market share position in a number of key geographic markets • Majority of revenue derived from cased-hole operations that include perforating, logging, and pipe recovery • Established in the Bakken, Eagle Ford, Permian, Niobrara, Mississippian, Haynesville, and Tuscaloosa Marine Shale (1) Based on Q4 2013 revenue (2) Year-end unit count SERVICE OVERVIEW OPERATING LOCATIONS FLEET GROWTH(2) DIVERSIFIED SERVICE OFFERINGS(1) 63 84 105 120 119 122 2009 2010 2011 2012 2013 2014E Cased Hole Logging Open Hole Logging Mechanical Services Plug/Shoot
Coiled Tubing 15 • Significant player in the offshore coiled tubing market • Fleet currently provides an array of services with coil capabilities ranging from 1.25” to 2.375” coiled tubing • Established in the Eagle Ford, Haynesville and offshore Gulf of Mexico 2 6 5 2 3/8" 2" < 2" SERVICE OVERVIEW OPERATING LOCATIONS UNIT COUNT(1): 13 FLEET GROWTH(2) Onshore Units 9 Offshore Units 4 (1) Coil unit size is based on most common configuration; all units are capable of running 2” and <2” coil (2) Year-end rig count 3 6 10 13 13 15 2009 2010 2011 2012 2013 2014E
16 DRILLING SERVICES
Drilling Services 17 • Over 70% of US drilling revenue(1) is generated in the Bakken, Eagle Ford, and West Texas • 74%(2) of rigs are capable of drilling horizontally in the unconventional plays • Pioneer Tier 1 drilling rigs are outfitted with industry- leading 2,000HP mud pumps and 7,500psi fluid ends for maximum penetration rates • Premier drilling contractor in Colombia, with several rigs awarded for top performance in 2012 (1) Based on trailing twelve months as of December 31, 2013 (2) Current rig count is 62 SERVICE OVERVIEW OPERATING LOCATIONS TTM DRILLING REVENUE(1): $528 MILLION US 78% Colombia 22% Bakken 30% Eagle Ford/STX 24% Permian 27% Marcellus/ Utica 8% East Texas 1% Uinta 10% Vertical 16% Horizontal 84% TTM US DRILLING REVENUE(1): $413 MILLION
Pioneer Drilling Rig Class Comparison 18 RIG FLEET CHARACTERISTICS Vertical Horizontal Mechanical/Electric Top Drive Mechanical Electric Number of Rigs 16 9 37 % of Fleet 26% 15% 60% AC/SCR 0/2 0/0 11/26 Drawworks 750-1,200HP 1,000-1,300HP 1,000-2,000HP Top Drive --- 250-500 Ton AC 250-500 Ton AC Mud Pumps 1,000-1,300HP 1,000-1,600HP 1,300-2,000HP Walking/Skidding – Installed --- 33% 76% Utilization % 69% 89% 92% Horizontal 74% Vertical 26% Mechanical 37% Electric 63% Note: “Vertical” includes one 550HP rig and three 750HP rigs have 750-800HP mud pumps; Utilization as of February 13, 2014 550-700HP 1% 750-950HP 10% 1,000HP 34% 1,200-2,000HP 55%
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Revenue and Cash Flow Development 20 REVENUE / ADJUSTED EBITDA ($ millions) CAPEX SPEND ($ millions) Note: All data points reflect calendar year and trailing twelve months information derived from 10-K and 10-Q filings. Please refer to Reconciliation of Adjusted EBITDA to Net Income on slide 22 $115 $131 $210 $364 $165 $0 $50 $100 $150 $200 $250 $300 $350 $400 2009 2010 2011 2012 2013 $326 $487 $716 $919 $960 $75 $103 $191 $249 $235 $0 $125 $250 $375 $500 $625 $750 $875 $1,000 $1,125 2009 2010 2011 2012 2013 Revenue Adjusted EBITDA
Liquidity and Capital Structure 21 December 31st, 2013 ($ millions) Actual Cash $ 27.4 Senior Secured Revolving Credit Facility due 2016 80.0 Senior Unsecured Notes due 2018(1) 419.6 Other 2.9 Total Debt $ 502.5 Shareholders' Equity 518.4 Total Capitalization $ 1,020.9 Liquidity(2) 183.4 Debt/TTM EBITDA(3) 2.0x Debt/Total Book Capitalization 49.2% (1) Reflects $250MM principal amount of initial notes net of $6.7MM unamortized discount as well as $175MM principal amount of add-on notes plus $1.3MM of unamortized bond premium. (2) Defined as remaining credit facility capacity plus cash less LCs outstanding. (3) Total consolidated leverage ratio as reported in Form 10-K for 2013.
Reconciliation of Adjusted EBITDA to Net Income 22 We define Adjusted EBITDA as earnings (loss) before interest income (expense), taxes, depreciation, amortization, impairments, and the Colombian Net Equity Tax. Although not prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors understand our operating performance and makes it easier to compare our results with those of other companies that have different financing, capital or tax structures. Adjusted EBITDA should not be considered in isolation from or as a substitute for net earnings (loss) as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. A reconciliation of net earnings (loss) to Adjusted EBITDA is included in the table below. Adjusted EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use. ($ in millions) 2009 2010 2011 2012 2013 Adjusted EBITDA 74.9 103.2 191.2 249.3 234.7 Colombian Net Equity Tax - - (7.3) - - Depreciation & Amortization (106.2) (120.8) (132.8) (164.7) (187.9) Net Interest (8.9) (26.6) (29.7) (37.0) (48.3) Impairment Expense - (3.3) (0.5) (1.1) (54.3) Income Tax (Expense) Benefit 17.0 14.3 (9.7) (16.4) 19.8 Net Income (Loss) (23.2) (33.3) 11.2 30.0 (35.9) Year-Ending December 31, ($ in illi n ) Q1 2013 Q2 2013 Q3 2013 Q4 2013 TTM Adjusted EBITDA 55.9 63.6 59.4 55.8 234.7 Depreciation & Amortization (46.3) (47.3) (47.4) (46.9) (187.9) Net Interest (11.5) (12.3) (12.3) (12.2) (48.3) Impairment Expense - (44.8) (9.5) - (54.3) Inco e Tax (Expense) Benefit 0.5 15.0 3.6 0.7 19.8 Net Income (Loss) (1.3) (25.9) (6. ) (2.5) ( 5.9)
