Attached files
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| 8-K - 8-K - PIONEER ENERGY SERVICES CORP | a8kinvpres01142015.htm |
GHS SoCal Energy Day January 14th, 2015
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 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 any future acquisition, 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 and the Company’s quarterly report on Form 10-Q for the quarter ended March 31, 2014. 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 September 30, 2014 (2) Market Capitalization as of January 12, 2015; debt and cash as of September 30, 2014 TICKER SYMBOL: PES (NYSE) TTM REVENUE1: $1.0 BILLION MARKET CAPITALIZATION2: $292 MILLION ENTERPRISE VALUE2: $730 MILLION SERVICE LINES: LAND DRILLING, WELL SERVICING, WIRELINE, COILED TUBING EMPLOYEES: 3,900 3
Diversified Services % of TTM REVENUE1 (1) Revenue breakdown based on trailing twelve month revenue as of September 30, 2014 of $1,010 million DRILLING SERVICES Drilling Services - US 54 Rigs Drilling Services – Colombia 8 Rigs Total Drilling 62 Rigs PRODUCTION SERVICES Well Servicing 116 Rigs Wireline 124 Units Coiled Tubing 17 Units Production Services 51% Drilling - Colombia 9% Drilling - US 40% 4
Fleet Composition • Adding nine well servicing rigs, eight wireline units, and one coiled tubing unit in 2015 • Executed five new-build drilling rig contracts for delivery in 2015 DRILLING SERVICES WELL SERVICING WIRELINE COILED TUBING 3 6 10 13 13 17 18 2009 2010 2011 2012 2013 2014 2015E 71 71 64 69 62 62 67 2009 2010 2011 2012 2013 2014 2015E 74 74 89 108 109 116 125 2009 2010 2011 2012 2013 2014 2015E 63 84 105 120 119 124 132 2009 2010 2011 2012 2013 2014 2015E 5
Recent Updates Drilling • Fourth quarter utilization is estimated to be 89% • Current utilization is 77% • Expect an additional ten rigs in the US to go idle by the end of the first quarter (primarily rigs drilling in South Texas and West Texas) • In addition, have received early termination notices effective in the first quarter related to seven rigs with termination payments expected to be approximately $22 million in aggregate • Term expirations: (3) in the first quarter, (1) in the second quarter, (1) in the third quarter, (1) in the fourth quarter, and (1) in the first quarter of 2016 • In Colombia, executed contracts for five rigs to be extended through mid-2015 at a slight discount to current dayrates • Remaining three rigs are expected to go idle in the first quarter Well Servicing • Fourth quarter utilization is estimated to be 90% Coiled Tubing • Fourth quarter utilization is estimated to be 47% 6
2015 Comments Capital Expenditures • Given market outlook, expect capital expenditures for 2015 to be reduced to a range of $195-$215 million, down from the original guidance of $250-$270 million Production Services • Expect production service activity levels to remain relatively high as operators focus spending on maintaining existing production • Pricing pressure will be in place throughout 2015 Drilling - US • All rig classes will experience some decreases in pricing and utilization, with the mechanical rig fleet most severely impacted • Continuing efforts to sell 60-Series and mechanical rigs Drilling - Colombia • Executed contracts for five rigs to be extended through mid-2015 at a slight discount to current dayrates • Actively marketing remaining rigs with multiple clients in Colombia to diversify client base 7
Investment Considerations Summary • Exposure to the full well life cycle including drilling, completions, workovers and on-going well maintenance • Approximately 60% of US revenue1 attributable to three key U.S. markets: Bakken shale, Eagle Ford shale and the Permian • Balance sheet well-positioned for long-term growth and for the 2015 reduction in customer spending • Industry-leading safety results continue to strengthen our activity levels and client base (1) Trailing twelve months as of September 30, 2014 8
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 9
Leverage to Three Key U.S. Markets (Approximately 60% of TTM US Revenue) Production Services 50% Drilling Services 50% Drilling Services 87% Production Services 13% Production Services 59% Drilling Services 41% EAGLE FORD1 PERMIAN1 BAKKEN1 (1) Breakdown based on trailing twelve month revenue as of September 30, 2014 10
Leverage and Debt Maturities • Restructured balance sheet in 2014 through multiple capital markets transactions • Completed $300 million 6.125% Senior Notes offering • Redeemed $425 million of 9.875% Senior Notes • Extended and upsized revolving credit facility capacity from $250 million to $350 million • Total Debt/LTM EBITDA is 1.9x Source: Public filings and non-GAAP reconciliations disclosed by each company for the twelve month period ended 9/30/2014; Capital IQ Note: EBITDA represents the adjusted EBITDA as reported by each individual company. PES ratio is as reported in the Q3 2014 10-Q related to the credit facility calculation. 0.1x 0.7x 1.9x 2.3x 2.3x 2.5x 3.1x 3.6x 4.6x HP PTEN PES PKD PD NBR BAS FES KEG Debt / LTM EBITDA $160 $300 $0 $100 $200 $300 $400 2015 2016 2017 2018 2019 2020 2021 2022 ($ m ill io n s) Debt Maturities Credit Facility 6.125% Senior Notes 11
Industry-Leading Safety • For many years, Pioneer has been a leader in U.S. land drilling safety. Our commitment to industry-leading safety helps us retain high-quality employees, broaden our client base, and reduce operating costs. 0 1 2 3 4 5 2008 2009 2010 2011 2012 2013 PES - US Land IADC - US Land without PES Total Recordable Incident Rate (injuries per 200,000 man-hours) 12
PRODUCTION SERVICES 13
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 • 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) • 100% of rigs are capable of working in the unconventional plays • Established in the Bakken, Eagle Ford, Fayetteville, and along the Texas/Louisiana Gulf Coast (1) Year-end rig count SERVICE OVERVIEW OPERATING LOCATIONS FLEET GROWTH1 74 74 89 108 109 116 125 2009 2010 2011 2012 2013 2014 2015E 14
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, Permian, Niobrara, Mississippian, and onshore/offshore Louisiana (1) Based on Q2 2014 revenue (2) Year-end unit count SERVICE OVERVIEW OPERATING LOCATIONS FLEET GROWTH2 DIVERSIFIED SERVICE OFFERINGS1 Cased Hole Logging Open Hole Logging Mechanical Services Plug/Shoot 63 84 105 120 119 124 132 2009 2010 2011 2012 2013 2014 2015E 15
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 2.375” coiled tubing • Established in the Eagle Ford, Haynesville 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 3 7 7 2 3/8" 2" < 2" Onshore Units 12 Offshore Units 5 3 6 10 13 13 17 18 2009 2010 2011 2012 2013 2014 2015E 16
DRILLING SERVICES 17
Drilling Services • Over 75% of US drilling revenue1 is generated in the Bakken, Eagle Ford, and Permian • 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 September 30, 2014 (2) Current rig count is 62 SERVICE OVERVIEW OPERATING LOCATIONS TTM DRILLING REVENUE1: $500 million TTM US DRILLING REVENUE1: $405 million US 81% Colombia 19% Vertical 28% Horizontal 72% Bakken 30% Eagle Ford/STX 27% Permian 26% Marcellus/ Utica 6% Uinta 11% 18
Pioneer Drilling Rig Class Comparison RIG FLEET CHARACTERISTICS Vertical Horizontal Mechanical/Electric Top Drive Mechanical Electric Number of Rigs 16 9 37 % of Fleet 26% 15% 60% AC/SCR 0/2 0/0 11/26 Drawworks 750-1,200HP 1,000-1,300HP 1,000-2,000HP Top Drive --- 250-500 Ton AC 250-500 Ton AC Mud Pumps 1,000-1,300HP 1,000-1,600HP 1,300-2,000HP Walking/Skidding – Installed --- 33% 81% Utilization % 88% 78% 97% Mechanical 37% Electric 63% Note: “Vertical” includes one 550HP rig and three 750HP rigs have 750-800HP mud pumps; Utilization as of earnings call on October 28, 2014 550-700HP 1% 750-950HP 10% 1,000HP 34% 1,200-2,000HP 55% Horizontal 74% Vertical 26% 19
Maintained High Level of Term-Contracted Cash Flow Note: Term contracted rig count is as of the earnings call for each respective quarter 44 44 46 43 44 43 38 41 40 43 44 62 66 68 70 71 70 62 62 62 62 62 - 10 20 30 40 50 60 70 80 Pi o n ee r R ig C o u n t Term Contracted Rigs Spot Market Rigs 20
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Historical Financial Results REVENUE / ADJUSTED EBITDA ($ millions) CAPEX SPEND ($ millions) *YTD as of September 30, 2014 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 24 $326 $487 $716 $919 $960 $1,029 $75 $103 $191 $249 $235 $281 $0 $125 $250 $375 $500 $625 $750 $875 $1,000 $1,125 2009 2010 2011 2012 2013 2014 Sept YTD Ann. Revenue Adjusted EBITDA $115 $131 $210 $364 $165 $121 $0 $50 $100 $150 $200 $250 $300 $350 $400 2009 2010 2011 2012 2013 2014 YTD* 22
Liquidity and Capital Structure September 30th, 2014 September 30th, 2014 ($ millions) Actual (As Adjusted for Senior Note Redemption) Cash $ 26.4 15.3 Senior Secured Revolving Credit Facility due 20191 40.0 160.0 9.875% Senior Unsecured Notes due 20182 123.6 0.0 6.125% Senior Unsecured Notes due 2022 300.0 300.0 Other 0.1 0.1 Total Debt $ 463.7 460.1 Shareholders' Equity3 540.9 532.1 Total Capitalization $ 1,004.5 992.2 Liquidity4 $ 322.4 191.2 Debt/LTM EBITDA5 1.9x 1.9x Debt/Total Book Capitalization 46.2% 46.4% (1) $120 million of proceeds under revolving credit facility plus cash on hand used to fund redemption of aggregate principal and redemption premium (2) Reflects the redemption of $125 million in aggregate principal amount of the 2010 and 2011 Senior Notes on October 23, 2014. The carrying value of these notes was $123.6 million at the redemption date, net of unamortized discount and premium. (3) Gives effect to the loss on extinguishment of existing senior notes, which includes redemption premium, unamortized debt issuance costs, and net unamortized discount; does not include effect of taxes (4) Defined as remaining credit facility capacity plus cash less LCs outstanding (5) Total consolidated leverage ratio as reported in Form 10-Q for Q3 2014 23
Reconciliation of Adjusted EBITDA to Net Income We define Adjusted EBITDA as earnings (loss) before interest income (expense), taxes, depreciation, amortization, impairments, and the Colombian Net Equity Tax. Although not prescribed under GAAP, we believe the presentation of Adjusted EBITDA is relevant and useful because it helps our investors understand our operating performance and makes it easier to compare our results with those of other companies that have different financing, capital or tax structures. Adjusted EBITDA should not be considered in isolation from or as a substitute for net earnings (loss) as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. A reconciliation of net earnings (loss) to Adjusted EBITDA is included in the table below. Adjusted EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, Adjusted EBITDA does not represent funds available for discretionary use. ($ in illi n ) 2009 2010 2011 2012 2013 Adjust 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 illions) Q4 2013 Q1 2014 Q2 2014 Q3 2014 TTM Adjusted EBITDA 55.8 63.3 69.7 78.1 266.9 Depreciation & Amortization (46.9) (45.5) (45.8) (46.1) (184.3) Net Interest (12.2) (12.4) (10.7) (9.0) (44.3) Impairment Expense - - - (0.7) (0.7) Loss on Extinguishment of Debt - (7.9) (14.6) - (22.5) Income Tax (Expense) Benefit 0.7 (0.0) 1.1 (9.9) (8.2) Net Income (Loss) (2.5) (2.6) (0.3) 12.5 7.0 24
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