UBS GLOBAL OIL AND GAS CONFERENCE May 2016
Forward-looking Statements 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 performance, quality of assets, rig utilization rate, capital spending by oil and gas companies, 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, the continued demand for drilling services or production services in the geographic areas where we operate, decisions about exploration and development projects to be made by oil and gas exploration and production companies, the highly competitive nature of our business, technological advancements and trends in our industry and improvements in our competitors’ equipment, the loss of one or more of our major clients or a decrease in their demand for our services, future compliance with covenants under our senior secured revolving credit facility and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, 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, the political, economic, regulatory and other uncertainties encountered by our operations, 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, 2015. Other 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. 2
Pioneer Energy Services (1) As of March 31, 2016 (2) Market Capitalization as of May 19, 2016; debt and cash as of March 31, 2016 TICKER SYMBOL: PES (NYSE) TTM REVENUE1: $422 MILLION MARKET CAPITALIZATION2: $179 MILLION ENTERPRISE VALUE2: $555 MILLION SERVICE LINES: LAND DRILLING, WELL SERVICING, WIRELINE, COILED TUBING EMPLOYEES: 1,400 3
Diversified Services % of TTM REVENUE1 (1) Revenue breakdown based on trailing twelve month revenue as of March 31, 2016 of $422 million DRILLING SERVICES Drilling Services - US 23 Rigs Drilling Services – Colombia 8 Rigs Total Drilling 31 Rigs PRODUCTION SERVICES Well Servicing 125 Rigs Wireline 125 Units Coiled Tubing 17 Units 4 Production Services 56% Drilling - Colombia 6% Drilling - US 38%
Fleet Composition DRILLING SERVICES1 WELL SERVICING WIRELINE COILED TUBING 5 (1) Since year-end 2011, added 15 AC rigs and disposed of 48 non-AC rigs Note: all counts are as of year-end 71 64 69 62 53 31 2010 2011 2012 2013 2014 2015 6 10 13 13 17 17 2010 2011 2012 2013 2014 2015 74 89 108 109 116 125 2010 2011 2012 2013 2014 2015 84 105 120 119 120 125 2010 2011 2012 2013 2014 2015
Recent Updates Drilling • April month-to-date utilization was 40%; current utilization is 42% based on a total fleet of 31 rigs • All rigs in Colombia are currently idle Well Servicing • April month-to-date utilization was 37% as compared to 44% in the first quarter • May month-to-date utilization is approximately 40% Coiled Tubing • April month-to-date utilization was 18% as compared to 24% in the prior quarter 6
Company Highlights • Exposure to the full well life cycle including drilling, completions, workovers and on-going well maintenance • Premium shale-oriented assets in all business lines with balanced exposure to completion and maintenance activity • Drilling - 94% of current fleet is pad-capable • Well Servicing - 100% of fleet 550-600hp and tall-masted • Wireline – Well-positioned in the Eagle Ford, Bakken and Niobrara • Coiled Tubing - 75% of on-shore units offer larger diameter coil • Conservative approach to cash flow and balance sheet management with continued focus on delevering • Industry-leading safety results 7
Exposure to the Full Well Life Cycle Plug and Perforate Toe Prep Drilling Maintenance until Plug and Abandon Drill Out Plugs Complete and Install Artificial Lift 8
Premium Shale-Oriented Assets 9 US DRILLING SERVICES PRODUCTION SERVICES • One of the most versatile and competitive 1,500 horsepower AC drilling rigs on the market • 2,000hp mud pumps and 7,500psi mud systems with bi-fuel capability • Moves in less than three days from release to acceptance by the operator on new pad • Walks 150’ x 50’ while racking over 24,000’ of 5” drill pipe • Premium shale-capable equipment • 100% of well servicing fleet is 550-600hp with 104’, 112’ or 116’ masts • Full suite of coiled tubing offerings from 1.25” to 2.625” coil • Balanced exposure to completion and production-oriented activity in major shale plays 91% 70% Pad-capable - US AC Rigs - US
Balance Sheet and Cash Flow Management • Amended the credit facility covenants in the fourth quarter of 2015 to allow for enhanced liquidity through maturity in 2019 • Eliminated Total Debt to EBITDA covenant through maturity • Senior Debt to EBITDA covenant steps up through 2016 and 2017 to a maximum of 4.75x (ratio excludes unsecured debt) • Interest Coverage covenant steps down in 2016 and 2017 to a minimum of 1.25x • Paid down $60 million on the revolving credit facility in 2015 and reduced total debt approximately $170 million since the first quarter of 2013 • Current revolver balance is $95 million • Sold 32 drilling rigs for net proceeds of approximately $53 million in 2015 10 $95 $300 $0 $100 $200 $300 $400 2016 2017 2018 2019 2020 2021 2022 ($ m ill io n s) Debt Maturities Credit Facility 6.125% Senior Notes
Industry-Leading Safety • For many years, Pioneer has been a leader safety. Our commitment to industry-leading safety helps us retain high-quality employees, broaden our client base, and reduce operating costs. • Pioneer recognized by IADC as the safest land contract driller in 2015 of the top 15 busiest contractors 0 1 2 3 4 5 2010 2011 2012 2013 2014 2015 PES - US Land IADC - US Land without PES Total Recordable Incident Rate (injuries per 200,000 man-hours) 11 Source: IADC Well Servicing (Annual AESC Safety Awards) 2011 1st place (Division IV) 2012 3rd place (Division IV) 2013 1st place (Division V) 2014 2nd place (Division V) 2015 3rd place (Division IV) Wireline (Annual AESC Safety Awards) 2015 1st place
PRODUCTION SERVICES 12
Well Servicing • 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, Niobrara, Fayetteville, and along the Texas/Louisiana Gulf Coast (1) Year-end rig count SERVICE OVERVIEW OPERATING LOCATIONS FLEET GROWTH1 13 74 89 108 109 116 125 2010 2011 2012 2013 2014 2015
Wireline • 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, Niobrara, Mississippian, and onshore/offshore Louisiana (1) Based on Q1 2016 revenue (2) Year-end unit count SERVICE OVERVIEW OPERATING LOCATIONS FLEET GROWTH2 DIVERSIFIED SERVICE OFFERINGS1 14 84 105 120 119 120 125 2010 2011 2012 2013 2014 2015 Open/Cased Hole Logging Mechanical Services Plug/Shoot
Coiled Tubing • Significant player in the offshore coiled tubing market • Fleet currently provides an array of services with coil capabilities ranging from 1.25” to 2.625” coiled tubing • Established in the Eagle Ford and onshore/offshore Louisiana SERVICE OVERVIEW OPERATING LOCATIONS UNIT COUNT1: 17 FLEET GROWTH2 (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 Onshore Units 12 Offshore Units 5 15 6 10 13 13 17 17 2010 2011 2012 2013 2014 2015 1 2 7 7 2 5/8" 2 3/8" 2" < 2"
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Drilling Services (1) Based on trailing twelve months as of March 31, 2016 1,500HP AC NEW-BUILD TECHNOLOGY OPERATING LOCATIONS TTM DRILLING REVENUE1: $184 million CURRENT RIG COUNT: 31 17 • Walks 150’ in X-direction and 50’ in Y-direction while racking over 24,000’ of 5” drill pipe • 2,000hp mud pumps and 7,500psi mud system • Moves in less than three days from release to acceptance by operator on a new pad • Bi-fuel capable 7 6 6 8 4 US 86% Colombia 14%
Pioneer Drilling Rig Class Comparison RIG FLEET CHARACTERISTICS AC SCR Number of Rigs 16 15 Drawworks 1,200-2,000HP 1,000-1,500HP Pad-Capable 100% 87% Utilization %1 81% 0% (1) Revenue utilization as of earnings call on April 29, 2016 18 94% 52% Pad-capable - Total AC Rigs - Total 1,000HP 6% 1,200-2,000HP 94%
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Historical Financial Results REVENUE / ADJUSTED EBITDA ($ 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 20 $716 $919 $960 $1,055 $541 $191 $249 $235 $277 $111 $0 $125 $250 $375 $500 $625 $750 $875 $1,000 $1,125 2011 2012 2013 2014 2015 Revenue Adjusted EBITDA $364 $165 $175 $160 $6 $0 $50 $100 $150 $200 $250 $300 $350 $400 2012 2013 2014 2015 2016 Mar YTD
Liquidity and Capital Structure March 31st, 2016 ($ millions) Actual Cash $ 18.7 Senior Secured Revolving Credit Facility due 2019 95.0 6.125% Senior Unsecured Notes due 2022 300.0 Other (7.4) Total Debt $ 387.6 Shareholders' Equity 315.1 Total Capitalization $ 702.7 Senior Consolidated Leverage Ratio1 (excludes unsecured debt) 1.3x Interest Coverage Ratio1 3.9x Debt/Total Book Capitalization 55.6% (1) Senior consolidated leverage ratio and interest coverage ratio as reported in Form 10-Q for the quarter ending March 31, 2016. 21
Reconciliation of Adjusted EBITDA to Net Income We define Adjusted EBITDA as earnings (loss) before interest income (expense), taxes, depreciation, amortization, loss on extinguishment of debt, impairments, and the Colombian Net Equity Tax. We use this non-GAAP measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies. A reconciliation of adjusted EBITDA to net income (loss) as reported is included in the tables below: 22 ($ in millions) 2011 2012 2013 2014 2015 Adjust d EBITDA 191.2 249.3 234.7 277.1 110.8 Colombian N t Equity Tax (7.3) - - - - Depreciation & Amortization (132.8) (164.7) (187.9) (183.4) (150.9) Net Interest (29.7) (37.0) (48.3) (38.8) (21.2) Loss on Extinguishment of Debt - - - (31.2) (2.2) Impairment Expense (0.5) (1.1) (54.3) (73.0) (129.2) Income Tax (Expense) Benefit (9.7) (16.4) 19.8 11.3 37.6 Net Income (Loss) 11.2 30.0 (35.9) (38.0) (155.1) Year-Ending December 31, ($ in millions) Q2 2015 Q3 2015 Q4 2015 Q1 2016 TTM Adjusted EBITDA 35.2 18.8 20.0 6.4 80.4 Depreciation & Amortization (38.5) ( 5.3) ( .4) (29.8) ( 39.0) Net Interest (5.2) (5.5) (5.1) (6.3) (22.0) Impairment Expense (71.3) (2.3) (49.5) - (123.2) Loss on Extinguishment of Debt - - (2.2) - (2.2) Income Tax (Expense) Benefit 2.6 6.7 23.9 2.0 35.1 Net Income (Loss) (77.3) (17.5) (48.3) (27.7) (170.8)
