INVESTOR PRESENTATION OCTOBER 2015

Transcription

1 INVESTOR PRESENTATION OCTOBER 2015

2 ASSUMPTIONS AND FORWARD-LOOKING STATEMENTS This presentation contains certain statements and information that may constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words anticipate, believe, ensure, expect, if, intend, plan, estimate, project, forecasts, predict, outlook, aim, will, could, should, potential, would, may, probable, likely, and similar expressions, and the negative thereof, are intended to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include statements, estimates and projections regarding our business outlook and plans, future financial position, liquidity and capital resources, operations, performance, acquisitions, returns, capital expenditure budgets, costs and other guidance regarding future developments. Forward-looking statements are not assurances of future performance. These forward-looking statements are based on management s current expectations and beliefs, forecasts for our existing operations, experience, and perception of historical trends, current conditions, anticipated future developments and their effect on us, and other factors believed to be appropriate. Although management believes that the expectations and assumptions reflected in these forward-looking statements are reasonable as and when made, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all). Moreover, our forward-looking statements are subject to significant risks and uncertainties, many of which are beyond our control, which may cause actual results to differ materially from our historical experience and our present expectations or projections which are implied or expressed by the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks relating to general economic and industry conditions; our customers drilling and completion expenditures; delays in or failure of delivery of current or future orders of specialized equipment; the loss of or interruption in operations of one or more key suppliers or customers; the effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing; operating risks; the adequacy of our capital resources and liquidity; weather; litigation; competition in the onshore oil and natural gas services industry; and costs and availability of resources. For additional information regarding known material factors that could cause our actual results to differ from our present expectations and projected results, please see our filings with the Securities and Exchange Commission ( SEC ), including our Current Reports on Form 8-K that we file from time to time, Quarterly Reports on Form 10-Q, and Annual Report on Form 10-K filed with the SEC on March 2, Readers are cautioned not to place undue reliance on any forward-looking statement which speaks only as of the date on which such statement is made. We undertake no obligation to correct, revise or update any forward-looking statement after the date such statement is made, whether as a result of new information, future events or otherwise, except as required by applicable law. 2

3 MANAGEMENT TEAM Jerry Winchester, CEO CEO since September 2011 and President and a director since June 2014 Served as President and CEO of Boots & Coots International Well Control Inc. from 2002 until it was acquired by Halliburton Company in 2010 Started his career at Halliburton in 1981 as a fracturing equipment operator and served in numerous operational and managerial roles Over 30 years of industry experience Cary D. Baetz, CFO CFO since January 2012 and Treasurer since June 2014 Served as SVP and CFO of Atrium Companies Inc. from November 2010 to December 2011 Served as CFO of Boots & Coots from August 2008 to September 2010 Served as Vice President of Finance, Treasurer and Assistant Secretary of Chaparral Steel Company from 2005 to 2008 Over 25 years of industry experience Karl Blanchard, COO Joined SSE as COO in June 2014 Previously served as Vice President of Production Enhancement of Halliburton from 2012 to 2014 Began his career at Halliburton in 1981, also serving as Vice President of Cementing, Vice President of Testing and Subsea and President Director of PT Halliburton Indonesia Over 30 years of industry experience Jay Minmier, President Nomac Drilling President since June 2011 Previously served as Vice President and General Manager for Precision Drilling Corporation More than 20 years experience with drilling contractors, notably Grey Wolf Inc. and Helmerich & Payne Inc. William R. Stanger, President Performance Technologies President since 2011 Joined in January 2010 as President of Great Plains Oilfield Rentals A former Vice President of Schlumberger with more than twenty-five years experience in oilfield services Jerome Loughridge, President Great Plains Oilfield Rental President since September 2012 Previously served as President of Black Mesa Energy Services, the oilfield investment arm of private equity firm Ziff Brothers Ventures, Executive Chairman of completions service provider Legend Energy Services and Chief Operating Officer of Great White Energy Services Over nine years of oilfield management experience 3

4 COMPANY HIGHLIGHTS¹ Large integrated footprint in some of the best returning basins and close proximity to customers Based in Oklahoma City operating in close proximity to some of the most active U.S. unconventional resource developers Comprehensive service offerings with modern, high quality asset base Multi-well pad capable Tier 1 and Tier 2 rigs represent 78% of fleet including fit-for-purpose PeakeRigs 21 proprietary PeakeRigs with five under construction Hydraulic fracturing assets among the newest in the industry with an average age of 38 months 400,000 HP and access to three transload facilities Industry-leading contracted backlog providing robust visibility to asset base Contracts with multiple large, well-capitalized customers with an industry leading backlog of approximately $893mm² of expected future revenue Experienced and skilled management team Experience working for highly regarded oilfield services companies including Boots & Coots, Halliburton, Helmerich & Payne and Schlumberger Managed through multiple oilfield services business cycles Strong liquidity $156.2mm in cash and $152.7mm in availability under the revolving bank credit facility as of September 30, 2015 No scheduled debt maturity until 2019 Long term liquidity enhanced by combined estimated drilling and completion backlog of $893mm ¹ Information as of 9/30/2015 ² See Backlog and Service Contract Summary on page 10 of this presentation 4

5 WELL POSITIONED FOR CURRENT INDUSTRY TRENDS Current Industry Trend Full scale development plans of large shale resources (existing and emerging) SSE Positioning Large, integrated footprint in 7 active basins Shale development expertise Increased drilling efficiencies through modern equipment and integrated operations Modern, efficient land drilling fleet of 53 contracted rigs¹ One of the newest pressure pumping fleets in the industry Modern well-maintained tool rental fleet Trend towards factory style development Highly efficient, integrated service model providing singlesource drilling and completion solutions Customer base of large acreage holders that are pioneering factory-style approach Increasing focus on safety and regulatory Industry leading safety performance ¹ Information as of 10/28/2015 5

6 AREAS OF OPERATIONS Oklahoma City Headquarters Significant footprint in many of the most economical plays, including Eagle Ford and Niobrara Shales As of 9/30/2015 6

7 CUSTOMER DIVERSIFICATION STRATEGY Continue strengthening current customer relationships and focus on winning other non-chk business Selected Customers Nomac revenue from other operators averaged 42% in Q Performance Technologies revenue from other operators averaged 27% in Q Great Plains revenue from other operators quadrupled from Q to Q3 2015, averaging 77% for the quarter Business development team continues to educate market and locate potential long term partners in down cycle Continue to bundle our equipment and services to provide value to our customers while increasing utilization SSE YTD SEPTEMBER 2014 REVENUE SSE YTD SEPTEMBER 2015 REVENUE LONG-TERM TARGET REVENUE 18% 30% 50% 50% 82% 70% 7

8 HISTORICAL U.S. RIG CYCLES COMPARISON 120% Historical Recent U.S. Rig Cycles - Peak to Trough Analysis % 80% 60% Peak 1,293 Trough 738 Δ Rigs (555) Δ Rigs % -43% Peak 1,032 Trough 488 Δ Rigs (544) Δ Rigs % -53% Peak 1,929 Trough 787 Δ Rigs (1,142) Δ Rigs % -59% Peak 2,031 Trough 876 Δ Rigs (1,155) Δ Rigs % -57% 40% Week Existing trajectory indicates a potential bottom of the current down cycle Source: Baker Hughes 10/16/2015 8

9 US RIG COUNT: NOMAC VS. PEERS WITH 20 ACTIVE RIGS AND HIGHER 10% INDUSTRY ACTIVE RIGS VS NOMAC RIGS % CHANGE: BASELINE 11/28/14 0% -10% -20% -30% Nomac Contracted Rigs -40% -50% -60% -70% Nomac Active Rigs -80% Source: Rig Data RADAR biweekly report / Internal Nomac Reporting 9

10 $mm BACKLOG AND SERVICE CONTRACT SUMMARY As of September 30, 2015, our contractual backlog¹ was approximately $893mm, ~11% of which was related to contracts with operators other than CHK Contracted Revenues by Business Segment Backlog expected to provide 80% to 85% of revenue in the fourth quarter of 2015 Total early termination value related to the drilling backlog was $50.0mm, $162.4mm, and $83.9mm for 2015, 2016, and thereafter Backlog includes services contracts entered into with CHK in connection with the spin-off under which CHK committed to use the services described below, subject to its rights to terminate the contracts in specified circumstances As of September 30, 2015, the expected drilling backlog was as follows: 12.5 rig years for rig years for rig years for 2017 and thereafter This includes 5 PeakeRigs to come online through 2016 on 2 year term As of September 30th, 2015 PTL hydraulic fracturing services agreement that provides CHK will utilize the lesser of (i) the number of crews set forth below: 9 month term 5 Crews 1.75 year term 3 Crews or (ii) percent (50%) of the total number of all pressure pumping crews working for CHK in all of its operating regions during the respective year PTL has recently captured term work for other operators (not reflected in backlog number). GPOR continues to diversify customer base as well Drilling Completion Total Backlog $893mm ¹We calculate our drilling backlog by multiplying the day rate under our contracts by the number of days remaining under the contract. We calculate our hydraulic fracturing backlog by multiplying the (i) rate per stage, which varies by operating region and is, therefore, estimated based on current customer activity levels by region and current contract pricing, by (ii) the number of stages remaining under the contract, which we estimate based on current and anticipated utilization of our crews. With respect to our hydraulic fracturing backlog, our contracts provide for periodic adjustments of the rates we may charge for our services, which will be negotiated based on then-prevailing market pricing and in the future may be higher or lower than the current rates we charge and utilize in calculating our backlog. Our drilling backlog calculation does not include any reduction in revenues related to mobilization or demobilization, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, many of our drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. We calculate our contract drilling early termination value assuming each rig remains stacked for the remainder of the term of the terminated contract. As a result of the foregoing, revenues could differ materially from the backlog and early termination amounts presented. 10

11 BUSINESS SEGMENTS SNAPSHOT Q DESCRIPTION REVENUE $mm ADJ EBITDA $mm¹ ADJ EBITDA Margin % BUSINESS OUTLOOK DRIVERS Drilling Provides land drilling and drilling-related services, including directional drilling Marketed fleet includes 32 Tier 1 rigs, including 21 fit-for-purpose PeakeRigs, 57 Tier 2 rigs, and three Tier 3 rigs % 5 new contracted rigs to be delivered over Hydraulic Fracturing Provides high-pressure hydraulic fracturing services 10 hydraulic fracturing fleets with an aggregate of 400,000 HP Oilfield Rentals Provides premium rental tools and specialized services for land-based oil and natural gas drilling, completion and workover activities % 15.0 (0.9) (6%) Current fleet of 400,000 HP Continue customer diversification Continue customer diversification Business Outlook Drivers Note: $mm, unaudited 2015 numbers ¹ Adjusted EBITDA is a non-gaap financial measure which we define as net income before interest expense, income tax expense, depreciation and amortization, as further adjusted to add back non-cash stock compensation, impairments and other, gain or loss on sale of property and equipment, rig rent expense and certain non-recurring items, such as the sale of our drilling rig relocation and logistics business, the distribution of our compression manufacturing and geosteering businesses to CHK and the sale of our crude and water hauling assets. See pages of this presentation for a reconciliation of GAAP measures to comparable financial measures calculated in accordance with GAAP. 11

12 NOMAC DRILLING CURRENT FLEET 53 CONTRACTED RIGS (27 OPERATING) OPERATING ACROSS UNCONVENTIONAL PLAYS¹ UTICA SHALE 13 POWDER RIVER AND DJ BASINS 4 ANADARKO BASIN 15 PERMIAN BASIN 2 EAGLE FORD SHALE 8 MARCELLUS SHALE 2 HAYNESVILLE SHALE 9 ¹ Contracted rig count as of 10/28/2015 : excludes refurbished, stacked, training and under construction rigs 12

13 2014 AVG DRILLING DAYS & WELL COUNT FOR HORIZONTAL WELLS Utica: Avg Operated Rigs By Contractor² Q14 2Q14 3Q14 4Q14 Eagle Ford: Avg Operated Rigs By Contractor³ Q14 2Q14 3Q14 4Q14 ¹Source: RigData - spud to release analysis of all 2014 wells as noted. ²Source: RigData 23 companies sampled ³Source: RigData 43 companies sampled 13

14 NOMAC RIG FLEET COMPARED TO PEERS Working to convert fleet to meet longterm drilling needs of all customers Currently 94% of our Tier 1 rigs and 68% of our Tier 2 rigs are multi-well pad-ready and tailored to meet the demands of E&P customers focused on unconventional resource development Delivered five proprietary PeakeRigs ytd and currently fabricating 5 more, 1 of which is expected to be delivered by the end of 2015, with the other 4 rigs expected to be delivered in 2016 Total US Land Active Rig Fleet Mix¹ TIER 1: 53% TIER 2: 19% TIER 3: 28% 9% PEERS US Land Rig Fleet Mix September 2015¹ 91% 63% 59% 50% 48% 35% 33% 19% 9% 25% 12% 32% 8% 40% 35% 10% 16% A B C D E 61% 3% Nomac 2015E 35% Tier 1 Tier 2 Tier 3 81% 60% 33% 32% F G H ¹ Source: RigData Weekly Locations and Operators Report list as of 10/09/2015, RigData Monthly Fleet Specs Report as of 09/25/2015; internal estimates 2 Nomac rig total based on marketed rigs, excludes cold stacked and rigs held for sale 14

15 EVOLUTION OF OUR FLEET Improving tier mix contributes to higher operating margin Based on contracted newbuilds, we expect to own 93 rigs by YE 2015 with 35% Tier 1 rigs Five additional PeakeRig newbuilds scheduled to be delivered over the next eight months Number of Rigs - Year End 160 Fleet Evolution and Operating Margin YTD Q Operating Margin 44% 42% % % 36% E 34% 32% 30% Tier 1 Tier 2 Tier 3 Operating Margin 1 1 Nomac Drilling Operating Margin through Q3 2015; marketed rig count as of year end 15

16 PERFORMANCE TECHNOLOGIES OPERATIONS OVERVIEW Provides high-pressure hydraulic fracturing services As of September 30, 2015, owned ten hydraulic fracturing fleets with an aggregate of 400,000 horsepower Operating throughout the Anadarko Basin, Eagle Ford, and Utica Shales Equipment consists of high pressure rated, premium hydraulic fracturing equipment specially suited for unconventional resource plays Among the newest in the industry with an average age of 38 months as of September 30, 2015 North American Horsepower by Capacity '000s HHP HAL + BHI 4,625 Schlumberger 1,900 FTS International 1,696 C&J 1,235 Calfrac Well Services* 1,198 Trican Well Services* 1,084 Patterson-UTI 1,005 Cudd Pumping (RPC) 920 Weatherford 900 Superior Energy Services 660 Sanjel Incorporated* 550 Pro Petro Services 500 Pioneer Natural Resources 450 Performance Technologies 400 Basic Energy Services 360 Keane Frac 300 U.S. Well Services 288 Canyon Technical Services* 255 Total NAM HHP 21 MM Other 2,641 * Denotes Canadian companies Source: Simmons & Company as of July,

17 PERFORMANCE TECHNOLOGIES OPERATING AREAS UTICA SHALE 3 SPREADS ANADARKO BASIN 3 SPREADS EAGLE FORD SHALE 4 SPREADS Access to three strategically positioned sand storage and transload facilities in Oklahoma, Texas, and Ohio PTL total fleets as of 9/30/

18 HYDRAULIC FRACTURING SUPPLY CHAIN INTEGRATION Access to three strategically positioned transload facilities located in: Oklahoma, South Texas, and Ohio. Dedicated sand storage of 80 million lbs and 34 million lbs at the South Texas and Ohio locations South Texas facility accepts multi-unit trains which secures more favorable rail rates and significantly reduces the number of rail car leases required to manage inventory Have a JV with a dedicated hydraulic fracturing sand carrier to ensure adequate truck transportation services for hauling hydraulic fracturing sand from regional distribution points to the well site Long term rail car leases procured for the bulk transportation of hydraulic fracturing sand by rail from the mine to regional distribution hubs Own mineral mining leases totaling approximately 2,000 acres at multiple sand mining sites in Wisconsin 18

19 GREAT PLAINS OILFIELD RENTAL OVERVIEW Great Plains provides premium rental tools and specialized services for land-based oil and natural gas drilling, completion and workover activities Tool Rental Downhole tubular products including hightorque, premium-connection drill pipe, drill collars, and tubing Surface rental equipment including blowout preventers, frac tanks, mud tanks, and environmental containment Services Water transfer services offering lay-flat hose and leveraging Great Plains surface rental asset base Air drilling services in the Marcellus and Utica Shales Flowback and pressure control 19

20 GREAT PLAINS CURRENT AND POTENTIAL SERVICE LINES SSE has established and is executing a plan to build out the Great Plains organization to increase utilization The percentage of revenue generated from non-chk sources increased from 62% to 77% 20

21 MATURITY AND DEBT SERVICE SCHEDULES Maturity Schedule $275 $650 $94 $374 $450 $1 $1 $1 $1 $1 $1 $2 $4 $4 $4 $4 $4 $ %¹ 3.750%³ 6.500% ⁵ 6.625%² %⁴ Term Loan Tranche A Incremental Term Loan Sr. Notes ABL Credit Facility Interest Schedule⁶ $77 $72 $72 $72 $72 $43 $29 $29 $6 $10 $10 $10 $10 $10 $29 $4 $8 $15 $15 $15 $15 $14 $14 $ Term Loan Tranche A Incremental Term Loan Sr. Notes ¹ 3.75% base rate; 1.50% letter of credit ² 6.625% Senior Notes due 2019; first call price at % on 11/15/2015 ³ 3.00% + LIBOR with 75bps LIBOR floor % + LIBOR with 100bps LIBOR floor % Senior Notes due 2022; first call price at % on 7/15/ Assumes Term Loan interest of 3.75%, Tranche A Loan of 10.00%, and no early call on Sr. Notes. / The $450 Senior Notes and Term Loan have issue dates as of 6/26/14 and 6/25/2014 respectively. Tranche A Incremental Term Loan has issue date of 5/13/

22 APPENDIX Q ADJUSTED EBITDA RECONCILIATION

23 APPENDIX: RECONCILIATION OF CONSOLIDATED NET INCOME TO ADJUSTED EBITDA Three Months Ended Nine Months Ended September 30, June 30, September 30, (In thousands) Net (loss) income $ (48,530) $ (1,770) $ (74,670) $ (160,800) $ 1,384 Add: Interest expense 25,480 23,606 24,968 73,964 55,913 Gains on extinguishment of debt (4,975) (13,085) (18,061) Income tax (benefit) expense (17,544) (2,465) (40,679) (74,455) 873 Depreciation and amortization 68,854 73,855 72, , ,149 Loss on sale of a business and exit costs 1,355 34,989 36,344 Losses (gains) on sales of property and equipment, net 1, ,010 15,023 (7,532) Impairments and other 1,566 7,751 8,882 16,720 30,731 Impairment of equity method investment 4,500 Non-cash compensation 12,160 27,763 13,131 43,646 27,763 Severance-related costs 1, ,102 6, Rent expense on buildings and real estate transferred from CHK 8,187 Rig rent expense 3,608 18,683 Less: Interest income (628) (108) (736) Drilling rig relocation and logistics Adjusted EBITDA 4,898 (5,886) (9,745) 13,115 Water hauling Adjusted EBITDA (777) 55 (4,531) (851) Geosteering Adjusted EBITDA 957 Crude hauling Adjusted EBITDA (5,066) Compression unit manufacturing Adjusted EBITDA 13,073 Non-recurring credit to stock-based compensation expense 10,530 Adjusted EBITDA $ 41,059 $ 129,042 $ 44,321 $ 178,723 $ 327,544 23

24 APPENDIX: RECONCILIATION OF DRILLING NET INCOME TO ADJUSTED EBITDA Three Months Ended Nine Months Ended September 30, June 30, September 30, (In thousands) Net (loss) income $ (6,392) $ 15,146 $ (9,689) $ (15,710) $ 22,328 Add: Income tax (benefit) expense (2,311) 9,088 (5,279) (7,274) 13,700 Depreciation and amortization 38,197 36,062 38, , ,362 Losses on sales of property and equipment, net 1, ,564 9,903 16,126 Impairments and other 6,796 8,688 12,417 29,569 Non-cash compensation 2,273 11,331 2,344 9,942 11,331 Severance-related costs , Rent expense on buildings and real estate transferred from CHK 1,688 Less: Rig rent expense 3,608 18,683 Geosteering Adjusted EBITDA 957 Non-recurring credit to stock-based compensation expense 4,318 Adjusted EBITDA $ 33,911 $ 82,362 $ 38,342 $ 136,262 $ 213,575 24

25 APPENDIX: RECONCILIATION OF HYDRAULIC FRACTURING NET INCOME TO ADJUSTED EBITDA Three Months Ended Nine Months Ended September 30, June 30, September 30, (In thousands) Net (loss) income $ (7,973) $ 21,173 $ (457) $ (1,977) $ 35,490 Add: Income tax (benefit) expense (2,882) 13,904 (248) (916) 21,956 Depreciation and amortization 17,833 17,524 17,804 51,915 53,484 Losses (gains) on sales of property and equipment, net 172 (19) (19) Impairments and other 207 Impairment of equity method investment 4,500 Non-cash compensation 952 1,922 1,043 3,234 1,922 Severance-related costs Rent expense on buildings and real estate transferred from CHK 1,259 Less: Non-recurring credit to stock-based compensation expense 477 Adjusted EBITDA $ 8,229 $ 54,504 $ 18,206 $ 52,695 $ 118,322 25

26 APPENDIX: RECONCILIATION OF OILFIELD RENTALS NET INCOME TO ADJUSTED EBITDA Three Months Ended Nine Months Ended September 30, June 30, September 30, (In thousands) Net loss $ (7,365) $ (686) $ (9,682) $ (20,511) $ (2,481) Add: Income tax benefit (2,663) (411) (5,275) (9,497) (1,424) Depreciation and amortization 8,912 12,812 10,575 31,659 39,527 Gains on sales of property and equipment, net (329) (771) (277) (777) (1,696) Impairments Non-cash compensation 483 1, ,868 1,792 Severance-related costs Rent expense on buildings and real estate transferred from CHK 1,415 Less: Non-recurring credit to stock-based compensation expense 601 Adjusted EBITDA $ (857) $ 13,691 $ (4,102) $ 2,835 $ 37,511 26

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