Seventy Seven Energy Investor Relations Presentation
Transcription
Seventy Seven Energy Investor Relations Presentation
INVESTOR PRESENTATION MAY 2015 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 forwardlooking 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 economic conditions; volatility of crude oil and natural gas commodity prices; 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; oil and gas market conditions; 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 oil and natural gas 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, 2015. 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 MANAGEMENT TEAM Jerry Winchester, CEO Served for thirteen years as the President and CEO of Boots & Coots International Well Control, Inc. which was acquired by Halliburton in September 2010 Started his career with Halliburton in 1981 as a fracturing equipment operator and served in positions of increasing responsibility, most recently as Global Manager over Well Control, Coil Tubing and Special Services Over 30 years of industry experience Cary D. Baetz, CFO Served as Senior Vice President and Chief Financial Officer of Atrium Companies, Inc. From November 2010 to December 2011 Served with Mr. Winchester as Chief Financial Officer 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 in June 2014 Previously served as Vice President of Production Enhancement of Halliburton Company 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 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 (PTL) 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 eight years of oilfield management experience 3 COMPANY HIGHLIGHTS 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 76% of fleet including fit-for-purpose PeakeRigs™ 16 active PeakeRigs™ with 9 under construction Hydraulic fracturing assets among the newest in the industry with an average age of 32 months 400,000 HP and two sand transload facilities Industry-leading contracted backlog providing robust visibility to asset base Contracts with multiple large, well-capitalized customers with an industry leading three-year backlog of approximately $1.4B1 of expected future revenue Experienced and skilled management team Experience working at highly regarded oilfield services companies including Boots & Coots, Halliburton, Helmerich & Payne, and Schlumberger. Managed through multiple oilfield services business cycles Strong liquidity 1 Approximately $204 mm available under our revolving credit facility as of March 31, 2015 No scheduled debt maturity until 2019 Planning to exercise the $100 mm accordion feature under the term loan See “Backlog and Service Contract Summary” on page 9 of this presentation 4 BUSINESS SEGMENTS AND OUTLOOK Description Drilling Provides land drilling and drilling-related services, including directional drilling Marketed fleet includes 26 Tier 1 rigs, including 16 fit-for-purpose PeakeRigs™, 57 Tier 2 rigs and seven Tier 3 rigs TTM 3/31/15 Adjusted Adjusted Adjusted Revenue¹ EBITDA² EBITDA % 758 303 40% Hydraulic Fracturing Provides high-pressure hydraulic fracturing services 10 hydraulic fracturing fleets with an aggregate of 400,000 horsepower 886 151 17% 150 50 Current fleet of 400,000 hp Continue customer diversification and growth 34% Oilfield Trucking Provides drilling rig relocation and logistics services 9 new contracted rigs to be delivered over the next 11 months Continue customer diversification and growth Oilfield Rentals Provides premium rental tools and specialized services for land-based oil and natural gas drilling, completion and workover activities 2015 - 2016 Business Outlook Drivers 153 5 3% Continue customer diversification and growth Note: $mm, unaudited 2014/2015 numbers 1 “Adjusted Revenue” is a non-GAAP financial measure that we define as Revenue including the pro forma effects of the spin-off; this excludes Geosteering and Crude hauling revenue of $2mm and $10.5mm and excludes Other Operations revenue of $2mm which is comprised of $41mm less $39mm from compression manufacturing unit that CHK retained in spin-off. 2 “Adjusted EBITDA” is a non-GAAP financial measure that we define as net income before interest expense, income tax expense, depreciation and amortization, as further adjusted to add back impairments and gain or loss on sale of property and equipment; Total and Nomac Drilling reflects EBITDA net of rig rental expense of $10mm and lease termination cost of $1.3mm. Total SSE EBITDA reflects sum of segment EBITDA net of Other Segment of ($63mm). See pages 23-28 of this presentation for a reconciliation of GAAP measures to comparable financial measures calculated in accordance with GAAP. 5 SSE IS WELL POSITIONED FOR CURRENT INDUSTRY TRENDS Current Industry Trend SSE Positioning Full scale development plans of large shale resources (existing and emerging) Large, integrated footprint in 8 active basins Shale development expertise (“it’s in our DNA”) Increased drilling efficiencies through modern equipment and integrated operations Modern, efficient land fleet of 57 contracted rigs One of the newest pressure pumping fleet in the industry Modern well-maintained tool rental fleet Trend towards “factory style” development Highly efficient, integrated service model providing single-source 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 6 AREAS OF OPERATIONS Marcellus Shale Niobrara Shale Utica Shale Anadarko Basin Permian Basin Barnett Shale Haynesville Shale Eagle Ford Shale – Oklahoma City Headquarters Significant footprint in many of the most economical plays, including Eagle Ford and Niobrara Shales As of 3/31/2015 7 CUSTOMER DIVERSIFICATION STRATEGY Replicate Nomac success in winning other non CHK business with PTL and Great Plains Nomac revenue from other operators increased to 41% in Q1 2015 compared to 29% in Q1 2014 Great Plains revenue from other operators increased to 44% in Q1 2015 compared to 10% in Q1 2014 Selected Customers Business development team continues to educate market and locate potential long term operator partners in down cycle Continue to bundle our equipment and services to provide value to our customers while increasing utilization 8 BACKLOG AND SERVICE CONTRACT SUMMARY As of March 31, 2015, our contractual backlog¹ was approximately $1.4B, ~13% of which was related to contracts with operators other than CHK Backlog expected to provide 60% to 70% of revenue in 2015 Total backlog of 36.8, 41.3, and 23.2 rig years for 2015, 2016, and thereafter Total early termination value related to the drilling backlog was $154.6mm, $165.9mm, and $85.8mm for 2015, 2016, and thereafter Contracted Revenues by Business Segment $1.4B 3 Year Backlog 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 March 31, 2015 Nomac rig-specific daywork drilling contracts for a remaining term ranging from 3 months to 2.25 years are set forth below: 3 month term – 10 Rigs 1.25 year term – 5 rigs 2.25 year term – 25 Rigs Additional PeakeRigs to come online through Q1 2016 on 2 year term As of March 31, 2015 PTL hydraulic fracturing services agreement that provides CHK will utilize the lesser of (i) the number of crews set forth below: 3 month term– 7 Crews 1.25 year term – 5 Crews 2.25 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 $mm 586 557 343 258 243 300 2015 2016 269 Drilling Completion 94 175 2017 Total ¹ We calculate our contract 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 estimated rate per stage, based on the then current contract prices, by the number of guaranteed stages remaining under the contract. Our Services Agreement for hydraulic fracturing with CHK provides for periodic adjustments of the rates we may charge for our services thereunder, 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. The 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 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. As a result, revenues could differ materially from the backlog amounts presented. 9 HISTORICAL U.S. RIG CYCLES COMPARISON 120% Historical Recent U.S. Rig Cycles - Peak to Trough Analysis 1997-99 2001-02 2008-09 2014-15 100% 80% Peak Trough Δ Rigs Δ Rigs % 1,293 738 (555) -43% 60% Peak Trough Δ Rigs Δ Rigs % 1,929 905 (1,024) -53% Peak Trough Δ Rigs Δ Rigs % 1,032 488 (544) -53% Peak Trough Δ Rigs Δ Rigs % 2,031 876 (1,155) -57% 40% 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 Week Current trajectory suggests 1-3 remaining months to trough based on prior cycles Source: Baker Hughes 05/01/2015 10 NOMAC DRILLING CURRENT FLEET Currently the 5th largest drilling rig contractor in the U.S.¹ Utica Shale 14 Rigs Nomac has 57 contracted rigs which operate across unconventional plays² Marcellus Shale Powder River and DJ Basins 1 Rigs 4 Rigs Haynesville Shale Anadarko Basin 5 Rigs 16 Rigs Permian Basin 7 Rigs Eagle Ford Shale 10 Rigs ¹ Based on RigData active rig count as of 4/17/2015 ² Rig count as of 5/4/2015 : excludes refurbished, stacked, training and under construction rigs 11 2014 AVG DRILLING DAYS & WELL COUNT FOR HORIZONTAL WELLS UTICA Drilling Contractor Nomac A Contractors with one rig B C Avg Total Avg Days/Well¹ 17 19 21 24 31 20 Well Count 219 203 81 78 61 642 Utica: Avg Operated Rigs By Contractor² 15 10 5 0 1Q14 EAGLE FORD Drilling Contractor Nomac A B C D E F Contractors with one rig G H Avg Total Avg Days/Well¹ 13 14 15 16 16 17 18 19 19 21 16 ¹Source: RigData - spud to release analysis of all 2014 wells as noted. ²Source: RigData – 23 companies sampled ³Source: RigData – 43 companies sampled Well Count 400 362 486 141 1,805 195 620 303 125 103 4,540 2Q14 3Q14 4Q14 Eagle Ford: Avg Operated Rigs By Contractor³ 40 20 30 15 10 5 0 1Q14 2Q14 3Q14 4Q14 12 NOMAC RIG FLEET COMPARED TO PEERS Working to convert fleet to meet longterm drilling needs of all customers Currently 93% of our Tier 1 rigs and 68% of our Tier 2 rigs are multi-well pad-ready and able to meet the demands of E&P customers focused on unconventional resource development US Land Rig Fleet Mix April 2015¹ 91% 61% 58% 47% 45% 35% 26% 77% 37% 61% 40% 25% 36% 33% 37% 19% Total US Land Active Rig Fleet Mix¹ 14% 9% Tier 2 21% Tier 3 28% A PEERS ¹ Source: RigData Weekly Locations and Operators Report list as of 5/1/2015, internal estimates 2 Nomac rig total based on marketed rigs, excludes cold stacked and rigs held for sale B 35% 13% 9% 5% 3% 51% 3% 62% Currently fabricating 9 proprietary PeakeRigs, 7 of which are expected to be delivered by the end of 2015 with the other 2 rigs expected to be delivered in 2016 Tier 1 18% C D F E G H Nomac 2015E Tier 1 Tier 2 Tier 3 13 EVOLUTION OF OUR FLEET Improving tier mix contributes to higher operating margin, continuing to increase with rig newbuilds, conversions, and removal of Tier 3 rigs Based on contracted newbuilds, we expect to own 93 rigs by YE 2015 with 35% Tier 1 rigs 9 PeakeRig newbuilds over the next 11 months Number of Rigs - Year End Fleet Evolution and Operating Margin Operating Margin 42% 160 YTD Q1 2015 40% 120 38% 91 85 80 90 93 26 33 12 20 36% 34% 57 40 57 57 57 32% 22 0 2012 Tier 1 1 Operating Margin through Q1 2015; marketed rig count as of year end 8 7 3 2013 2014 2015E Tier 2 Tier 3 30% Operating Margin1 14 PERFORMANCE TECHNOLOGIES OPERATING AREAS Utica Shale 3 spreads Anadarko Basin 3 spreads Eagle Ford Shale 4 spreads PTL total fleets as of 3/31/2015 15 PTL OPERATIONS OVERVIEW Provides high-pressure hydraulic fracturing services As of Mar 31, 2015, owned ten hydraulic fracturing fleets with an aggregate of 400,000 horsepower Seven fleets contracted by CHK and two fleets by other operators Operating throughout the Anadarko Basin, Eagle Ford, and Utica Shales North American Horsepower by Capacity '000s HHP HAL + BHI 4,625 Other 2,488 Schlumberger 1,900 FTS International 1,696 NBR + CJES PF 1,235 Calfrac Well Services 1,193 Trican Well Services 1,084 Patterson-UTI 1,005 Cudd Pumping (RPC) 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 32 months as of Mar. 31, 2015 Source: Simmons & Company as of February 27, 2015 920 Weatherford Superior Energy Services 800 660 Sanjel Incorporated 550 Pro Petro Services 500 Pioneer Natural Resources 450 Performance Technologies 400 Basic Energy Services 360 Keane Frac / Ultra Tech 300 U.S. Well Services 288 Go Frac 255 Total North American Horsepower Capacity 21 MM HHP 16 HYDRAULIC FRACTURING SUPPLY CHAIN INTEGRATION Access to three strategically positioned sand storage and trans load Storage and Distribution Facilities facilities, one in Oklahoma with storage capacity of 140 million pounds, one in south Texas with 80 million pound capacity, and one in Transloading Facilities Ohio with 30 million pound capacity 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 Sandbox Executed 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 Rail Cars hydraulic fracturing sand by rail from the mine to regional distribution hubs Own mineral mining leases totaling approximately 2,000 acres at Sand Reserves multiple sand mining sites in Wisconsin; capable to self source a majority of sand supply by 2016 helping to mitigate future impact of sand price volatility 17 GREAT PLAINS ASSET BASE AND SERVICES Great Plains provides premium rental tools and specialized services for land-based oil and natural gas drilling, completion, and workover activities Air Package Tool Rental Downhole tubular products including high-torque, premium-connection drill pipe, drill collars, and tubing Surface rental equipment including blowout preventers, frac tanks, mud tanks, and environmental containment Tanks Services Water transfer services offering lay-flat hose and leveraging Great Plains’ surface rental asset base Air drilling services in the Marcellus and Utica Flowback and pressure control 18 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 Great Plains equipment utilization remained relatively flat from Q4 2014 to Q1 2015, while the percentage of revenue generated from non CHK sources increased from 27% to 44% 19 SEVENTY SEVEN TRUCKING ASSETS Hodges has provided drilling rig relocation and logistics services for over 80 years Truck Fleet As of March 31, 2015, we owned a fleet of 263 rig relocation trucks and 67 cranes and forklifts Oilfield Trucking Assets Units Transportation Trucks 195 Crane & Forklift 67 Rig Up 68 Hodges Crane Transportation Truck 20 MATURITY AND DEBT SERVICE SCHEDULES Maturity Schedule $275 $650 $374 $2 2014 $4 2015 $4 2016 $4 2017 $4 2018 $4 2019 $4 2020 3.567%¹ 2021 3.750%³ $500 2022 6.500% 4 6.625%² Term Loan Sr. Notes ABL Credit Facilty Interest Schedule5 $76 $76 $76 $76 $71 $60 $33 $33 $8 $15 $15 $15 $15 $14 $14 $7 2014 2015 2016 2017 2018 2019 2020 2021 Term Loan $18 2022 Sr. Notes ¹ 3.75% base rate; 1.50% letter of credit ² 6.625% Senior Notes due 2019; first call price at 103%.313 on 11/15/2015 ³ 3.00% + LIBOR with 75bps LIBOR floor 4 6.500% Senior Notes due 2022; first call price at 104.875% on 7/15/2017 5 Assumes Term Loan interest of 3.75% and no early call on Sr. Notes. / The $500 Senior Notes and Term Loan have issue dates as of 6/26/14 and 6/25/2014 respectively. 21 CORPORATE INFORMATION SSE HEADQUARTERS 77nrg.com 777 NW 63rd St. Oklahoma City, OK 73116 405-608-7777 CORPORATE CONTACTS Bob Jarvis Senior Director – Investor Relations and Marketing [email protected] 405-935-2572 22 APPENDIX APPENDIX: RECONCILIATION OF CONSOLIDATED NET INCOME TO ADJUSTED EBITDA Three Months Ended March 31, 2015 2014 (In thousands) Net loss $ (37,601) $ (18,557) Add: Interest expense Income tax benefit Depreciation and amortization 23,516 14,692 (16,232) (10,697) 84,975 72,465 Impairments and other 6,272 19,808 Losses on sales of property and equipment, net 4,210 977 Non-cash compensation 18,355 146 Severance-related costs 1,404 167 Rent expense on buildings and real estate transferred from CHK(a) — 4,106 Rig rent expense(b) — 9,059 Compression unit manufacturing Adjusted EBITDA — 6,715 Geosteering Adjusted EBITDA — 194 Crude hauling Adjusted EBITDA — (543) Less: Adjusted EBITDA $ 84,899 $ 85,800 24 APPENDIX: RECONCILIATION OF OPERATING CASH TO ADJUSTED EBITDA Three Months Ended March 31, 2015 2014 (In thousands) Cash provided by operating activities $ 27,513 $ 54,582 Add: Changes in operating assets and liabilities 35,102 (1,628) Interest expense 23,516 14,692 Lease termination costs — 8,379 Amortization of sale/leaseback gains — 4,214 Amortization of deferred financing costs (1,028) Income (loss) from equity investees (737) 972 Provision for doubtful accounts (917) (2,580) Current tax expense Severance-related costs (83) — 333 1,404 167 Rent expense on buildings and real estate transferred from CHK — 4,106 Rig rent expense — 9,059 — Other (1) Less: Compression unit manufacturing Adjusted EBITDA — Geosteering Adjusted EBITDA — 194 Crude hauling Adjusted EBITDA — (543) Adjusted EBITDA $ 84,899 6,715 $ 85,800 25 APPENDIX: RECONCILIATION OF DRILLING NET INCOME TO ADJUSTED EBITDA Three Months Ended March 31, 2015 2014 (In thousands) Net income (loss) $ 479 $ (2,359) Add: Income tax benefit 207 Depreciation and amortization (1,329) 49,539 34,903 Impairments and other 3,729 19,601 Losses on sales of property and equipment, net 4,386 1,710 Non-cash compensation 5,326 — Severance-related costs 344 63 Rent expense on buildings and real estate transferred from CHK — 880 Rig rent expense — 9,059 — 194 Less: Geosteering Adjusted EBITDA Adjusted EBITDA $ 64,010 $ 62,334 26 APPENDIX: RECONCILIATION OF HYDRAULIC FRACTURING NET INCOME TO ADJUSTED EBITDA Three Months Ended March 31, 2015 2014 (In thousands) Net income $ 6,054 $ 595 Add: Income tax expense 2,613 610 16,277 18,109 Impairments — 207 Gains on sales of property and equipment, net (5) — Depreciation and amortization Non-cash compensation 1,238 — Severance-related costs 81 — — Rent expense on buildings and real estate transferred from CHK Adjusted EBITDA $ 26,258 630 $ 20,151 27 APPENDIX: RECONCILIATION OF OILFIELD RENTALS NET INCOME TO ADJUSTED EBITDA Three Months Ended March 31, 2015 2014 (In thousands) Net loss $ (3,509) $ (2,136) Income tax expense (benefit) (1,515) (1,237) Depreciation and amortization 12,172 13,347 Add: Gains on sales of property and equipment, net (171) (742) Non-cash compensation 861 — Severance-related costs (46) 24 — Rent expense on buildings and real estate transferred from CHK Adjusted EBITDA $ 7,792 720 $ 9,976 28 APPENDIX: RECONCILIATION OF OILFIELD TRUCKING NET INCOME TO ADJUSTED EBITDA Three Months Ended March 31, 2015 2014 (In thousands) Net loss $ (12,836) $ (3,397) Add: Income tax benefit (5,541) (1,871) Depreciation and amortization 5,054 5,929 Impairments 2,543 — Gains on sales of property and equipment, net (10) (8) Non-cash compensation 1,320 — Severance-related costs 1,025 5 — 863 — (543) Rent expense on buildings and real estate transferred from CHK Less: Crude hauling Adjusted EBITDA Adjusted EBITDA $ (8,445) $ 2,064 29 30