EX-99.2 3 a201905061q19earningscal.htm EXHIBIT 99.2 a201905061q19earningscal


 


 
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 fact, 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,” “once” “intend,” “plan,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “will,” “could,” “should,” “potential,” “would,” “may,” “probable,” “likely,” and similar expressions that convey the uncertainty of future events or outcomes, and the negative thereof, are intended to identify forward-looking statements. Forward-looking statements contained in this presentation, which are not generally historical in nature, include those that express a belief, expectation or intention regarding our future activities, plans and goals and our current expectations with respect to, among other things: our ability to successfully integrate acquisitions; our operating cash flows, the availability of capital and our liquidity; our future revenue, income and operating performance; our ability to sustain and improve our utilization, revenue and margins; our ability to maintain acceptable pricing for our services; future capital expenditures; our ability to finance equipment, working capital and capital expenditures; our ability to execute our long-term growth strategy; our ability to successfully develop our research and technology capabilities and implement technological developments and enhancements; and the timing and success of strategic initiatives and special projects. Forward-looking statements are not assurances of future performance and actual results could differ materially from our historical experience and our present expectations or projections. These forward-looking statements are based on management’s current expectations and beliefs, forecasts for our existing operations, experience, expectations 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 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). Our forward-looking statements involve significant risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, risks associated with the following: a decline in demand for our services, including due to supply of oil and gas, declining or perceived instability of commodity prices, overcapacity of supply, constrained pipeline capacity and other competitive factors affecting our industry; the cyclical nature and volatility of the oil and gas industry, which may impact the level of drilling, completion and production activity and spending patterns by our customers; a decline in, or substantial volatility of, crude oil and gas commodity prices, which generally leads to decreased spending by our customers and negatively impacts drilling, completion and production activity; pressure on pricing for our services, including due to competition and industry and/or economic conditions, which impacts, among other things, our ability to implement price increases or maintain pricing and margin on our services; the loss of, or interruption or delay in operations by, one or more customers; the failure by one or more of our customers to pay amounts when due, or at all; changes in customer requirements in the markets or industries we serve; costs, delays, compliance requirements and other difficulties in executing our short-and long-term business plans and growth strategies; the effects of recent or future acquisitions or customer opportunities on our business, including our ability to successfully integrate our operations and the costs incurred in doing so and the costs and potential liabilities associated with new or expanded areas of operational risks (such as offshore or international operations); business growth outpacing the capabilities of our infrastructure; the loss of, or interruption or delay in operations by, one or more of our key suppliers, including resulting from product defects, recalls or suspensions; adverse weather conditions in oil and gas producing regions; operating hazards inherent in our industry, including the possibility of accidents resulting in personal injury or death, property damage or environmental damage; the effect of environmental and other governmental regulations on our operations, including the risk that future changes in the regulation of hydraulic fracturing could reduce or eliminate demand for our hydraulic fracturing services; the incurrence of significant costs and liabilities resulting from litigation or governmental proceedings; the incurrence of significant costs and liabilities or severe restrictions on our operations or the inability to perform certain operations or provide certain services resulting from a failure to comply, or our compliance with, new or existing regulations; the effect of new or existing regulations, industry and/or commercial conditions on the availability of and costs for raw materials, consumables and equipment; our ability to implement new technologies and services; the loss of, or inability to attract, key management and other competent personnel; a shortage of qualified workers; damage to or malfunction of equipment; our ability to maintain sufficient liquidity and/or obtain adequate financing to allow us to execute our business plan; and our ability to comply with covenants under our credit facility. For additional information regarding known material factors that could affect our operating results and performance, please see our most recently filed Annual Report on Form 10-K, subsequent Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, which are available at the SEC’s website, http://www.sec.gov. Should one or more of these known material risks occur, or should the underlying assumptions change or prove incorrect, our actual results, performance, achievements or plans could differ materially from those expressed or implied in any forward-looking statement. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. All subsequent written or oral forward-looking statements concerning us are expressly qualified in their entirety by the cautionary statements above. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as required by law. All information in this presentation is as of March 31, 2019 unless otherwise indicated. Non-GAAP Financial Measures: This presentation includes consolidated Adjusted EBITDA, Adjusted Net Income, Free Cash Flow and Adjusted EBITDA per fleet, all of which are measures not calculated in accordance with generally accepted accounting principles in the U.S. ("U.S. GAAP"). Please see slides 16 – 18 for a reconciliation of net income (loss) to each of Adjusted Net Income (loss) and Adjusted EBITDA. Segment Adjusted EBITDA: Adjusted EBITDA at the segment level is not considered to be a non-GAAP financial measure as it is our segment measure of profit or loss and is required to be disclosed pursuant to ASC 280, Segment Reporting. Certain Definitions: We calculate “margin %” as the specified metric divided by revenue.


 
● Increased consolidated revenue ~ 4% to $511 million, generated Adjusted EBITDA(1) of just under $50 million and reported Adjusted EPS(1) of ($0.28) ● Increased fracturing revenue by 22% and grew profitability per fleet by over 60% to $10.2 million of annualized Adjusted EBITDA per fleet(2) ● Improving customer activity levels across our service lines resulted in strong revenue generation in March, which positions us well for additional revenue growth in the second quarter ● Well Construction & Intervention Services (“WC&I”) segment revenue and profitability improved in March as the drilling rig count recovered and coiled tubing units returned to the field ● Well Support Services segment negatively affected by inclement weather throughout 1Q’19 but has experienced improved profitability early in the second quarter ● Continued to streamline costs and manage capital spending in order to meet targeted returns and generate free cash flow in 2019 1. See slide 16 for a reconciliation of net income (loss) to Adjusted Net Income (loss) to Adjusted EBITDA. 2. See slide 18 for a reconciliation of fracturing net income (loss) to fracturing Adjusted EBITDA.


 
1Q’19 Market Conditions Consolidated Revenue ● Revenue decreased y-o-y but increased 4% sequentially; Adj. ($ in MM) EBITDA decreased both y-o-y and sequentially $611 ● Results negatively affected by inclement weather and lower $568 customer activity levels in our non-fracturing businesses $553 ● Fracturing utilization increased due to higher customer activity $511 levels and more dedicated frac fleets $491 ● Wireline and Pumpdown experienced a slow start in several basins; however, activity levels improved in March ● Lower drilling rig counts negatively affected our Cementing business; however, rig counts improved in March 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 ● Inclement weather negatively affected our Well Support Services segment in all operating basins throughout the quarter Consolidated Adjusted EBITDA(1) Consolidated Adjusted Net Income (loss)(1) ($ in MM) Margin (%) ($ in MM) 15% $35 14% $92 14% $29 $79 $77 11% 10% $11 $53 $50 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 -$18 -$19 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 1. See slide 16 for a reconciliation of net income (loss) to Adjusted Net Income (loss) to Adjusted EBITDA.


 
Revenue by Business Revenue by Basin Fluids Management 7% 6% Rig Services 13% 13% 42% Fracturing Coiled Tubing 5% 46% 12% 11% Cementing 9% 2% 18% Other 16% Completions Wireline & Pumping West Texas South Texas / East Texas Rockies / Bakken California 80% of Revenue from New Well Focused Services Mid-Continent Northeast


 
($ in MM) ● Segment revenue decreased 13% year-over-year, $413 but increased 12% sequentially to $327MM $374 $373 ● Segment Adjusted EBITDA decreased 33% year- over-year, but increased 23% sequentially to $54MM $327 ● Fracturing revenue decreased 12% year-over-year, $293 but increased 22% sequentially to $236MM ● Fracturing benefited from refreshed E&P capital budgets, greater customer urgency, operational efficiencies and more dedicated frac fleets 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 ● Increased annualized Adjusted EBITDA per fleet by over 60% sequentially to $10.2 million Margin (%) ● Wireline and Pumpdown revenue decreased 17% ($ in MM) 20% year-over-year and 11% sequentially 22% $84 18% ● Wireline and Pumpdown were negatively affected by: $82 $67 17% o Inclement weather in all operating basins 15% $54 o Curtailed customer activity levels in our largest $44 operating basin: Bakken / Rocky Mountains o More competitive pricing environment ● Wireline and Pumpdown pricing has stabilized and 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 customer activity levels have increased in all operating basins as we exited 1Q’19


 
($ in MM) ● Segment revenue and Adjusted EBITDA decreased both year-over-year and sequentially $99 ● Cementing revenue decreased 12% year-over-year $96 $94 and 15% sequentially $87 ● Cementing business was negatively affected by: $79 o Reduced drilling rig count from smaller public and private customers in West Texas and the Mid-Continent o More competitive pricing environment 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 ● West Texas drilling rig count began to recover in late 1Q’19 resulting in improved customer activity levels Margin (%) entering 2Q’19 ($ in MM) ● Coiled Tubing revenue decreased 3% year-over- year and 17% sequentially 20% ● Coiled Tubing business was negatively affected by: 19% 18% $20 17% $17 o Unexpected downtime with certain large $16 $16 diameter units 8% o Slower than expected completion activity $7 levels in South Texas and the Mid-Continent ● Demand for coiled tubing remains strong and all 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 large diameter units will be deployed in 2Q’19 which should result in higher revenue and profitability


 
● Segment revenue increased 14% year-over-year to ($ in MM) $105MM and was essentially flat sequentially ● Segment Adjusted EBITDA increased 25% year-over- $105 year, but decreased 47% sequentially to $7MM $99 $99 $104 $91 ● Segment profitability was negatively affected by: o Multiple instances of inclement weather in all operating basins o Higher overall labor costs 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 ● Rig Services benefited from the full impact of prior quarter rate increases and slightly higher deployed rig count, all of which was offset by inclement weather Margin (%) ● Demand for plug and abandonment services ($ in MM) 13% remained strong, but Special Services revenue and 12% 11% $13 profitability declined sequentially due rig delays $11 $11 caused by weather 7% 6% ● Fluids Management demand continued to improve but $7 higher labor costs and weather caused results to $6 decline sequentially ● Customer demand remains steady and inclement weather has subsided, which should result in 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 improved segment profitability in 2Q’19


 
SG&A Expense D&A Expense ($ in MM) ($ in MM) $63 $61 $60 $66 $54 $60 $46 $54 $50 $50 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 1Q’19 Highlights 2Q’19 Cost Guidance ● SG&A expense decreased 19% year-over-year but increased ● SG&A expense to range between $52MM – $56MM 8% sequentially to $54MM due to increased compensation ● D&A expense to range between $58MM – $62MM expense and higher payroll taxes ● Large NOL position; not expected to be a cash tax payer o Includes $5.6MM of non-cash, long-term with the exception of certain state and local taxes compensation expense ● Capital expenditures expected to range between $55MM – ● Capital expenditures decreased both year-over-year and $65MM sequentially to $48MM primarily due to lower growth capex and our younger fracturing fleet profile


 
No Leverage and Ample Liquidity 2019 Capital Budget & Highlights ($ in MM) Cash ABL Availability Corporate, Facilities, R&T and Other $466 13% $393 $371 $364 17% Growth $356 $235 $317 $275 70% Maintenance $136 $110 $76 $89 6/30/2018 9/30/2018 12/31/2018 3/31/2019 ● 2019 capital expenditures expected to range between $140MM – ● One of the strongest balance sheets in the sector $180MM ● Strong liquidity position to fund capital expenditures and ● Allocating ~$3.0MM of annual maintenance capex per deployed potential accretive bolt-on acquisitions fleet in our Fracturing business, a 30% reduction compared to 2018 due to our younger fleet profile ● As of 3/31/19, excluding letters of credit, no outstanding ● Growth capital expenditures mostly pertain to: borrowings under our asset-based credit facility o Two large diameter coiled tubing units with expected delivery by mid 4Q’19 ● ~$1.3Bn of NOLs represents substantial value o Greaseless cable and pressure control systems to increase efficiency and safety in our Wireline business o Ancillary components in our Fracturing business to increase safety, reduce non-productive time and lower operating costs


 
2Q’19 Outlook 2019 Thoughts ● Expecting consolidated revenue to increase mid to high ● Current 2019 budget calls for 695,000 HHP deployed single digits sequentially and profitability to improve mostly throughout the year at improving utilization due to higher customer activity levels in our non-fracturing businesses ● Remain focused on dedicating frac fleets with long- standing, efficient customers throughout 2019 ● Expecting fracturing revenue to increase mid single digits sequentially due to stable utilization and pricing ● Focused on maintaining high utilization and strong market share position in Wireline and Pumpdown businesses ● Wireline and Pumpdown revenue expected to increase upper single to low double digits sequentially due to ● Pumpdown units expected to be fully deployed increased completion activity in all operating basins, especially in the Bakken / Rocky Mountains ● Focused on keeping large diameter coiled tubing units deployed with high utilization and taking delivery of two new ● WC&I segment revenue expected to increase mid single build 2⅝ inch units by mid 4Q’19 digits sequentially due to improved drilling rig counts and all coiled tubing units redeployed to the field by mid-May ● Focused on continuing to high-grade customer base and maintaining market share in our Cementing business; ● Expecting Well Support Services segment revenue to successfully performed multiple jobs for major / large increase low to mid single digits and profitability to improve independent customers in 1Q’19 sequentially ● Focused on continued market share growth in California and West Texas in our Well Support Services segment with primarily major / large independent customers


 


 


 
$MM; unless otherwise stated Full Year 1Q'18 2Q'18 3Q'18 4Q'18 2018 1Q'19 Revenue Completion Services $374 $413 $373 $293 $1,454 $327 Well Construction & Intervention Services 88 99 96 94 376 79 Well Support Services 91 99 99 104 393 105 Total Revenue $553 $611 $568 $491 $2,222 $511 Total Gross Profit (1) $134 $147 $122 $94 $497 $94 % Margin 24% 24% 21% 19% 22% 18% Net Income / (Loss) $21 $28 $10 ($190) ($130) ($24) Adjusted EBITDA Completion Services $82 $84 $67 $44 $277 $54 Well Construction & Intervention Services 16 20 17 16 70 7 Well Support Services 6 11 11 13 41 7 Corporate / Eliminations (25) (24) (19) (21) (88) (18) Total Adjusted EBITDA (2) $79 $92 $77 $53 $300 $50 % Margin 14% 15% 14% 11% 13% 10% 1. Gross profit defined as revenue less direct costs. 2. Please see slide 16 for a reconciliation of net income (loss), the nearest measure calculated in accordance with U.S. GAAP.


 
C&J ENERGY SERVICES INC. AND SUBSIDIARIES RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED NET INCOME (LOSS) (In thousands, except per share data) (Unaudited) Three Months Ended March 31, 2019 December 31, 2018 September 30, 2018 June 30, 2018 March 31, 2018 Net income (loss) $ (23,573) $ (189,527) $ 10,433 $ 28,496 $ 20,594 Adjustments, net of tax: Severance and business divestiture costs 3,336 - 129 1,150 6,140 Bad debt reserve 846 - - - - Legal settlements 600 - 500 - 500 Impairment expense - 146,015 - - - Asset impairment - 21,410 - - - Inventory reserve - 6,131 - - - Financial restructuring charges (settlements) - (2,400) - 1,400 - Acquisition-related and other transaction costs - - - 243 727 Non-cash deferred financing charge - - - 1,508 - Restructuring costs and other 261 521 226 2,163 623 Adjusted net income (loss) $ (18,530) $ (17,850) $ 11,288 $ 34,960 $ 28,584 Depreciation and amortization 59,756 63,389 60,748 54,387 46,343 (Gain) loss on disposal of assets 1,956 3,536 2,471 (1,061) (489) Interest expense, net 347 617 669 677 428 Other income, net (465) (316) (370) (294) (620) Income tax expense (benefit) 920 43 (1,504) (893) (60) Non-cash share-based compensation, excluding severance 5,573 3,145 4,071 4,138 4,372 Adjusted EBITDA 49,557 52,564 77,373 91,914 78,558 Per common share: Net income (loss) diluted $ (0.36) $ (2.87) $ 0.16 $ 0.42 $ 0.31 Adjusted net income (loss) diluted $ (0.28) $ (0.27) $ 0.17 $ 0.52 $ 0.42 Diluted weighted average common shares outstanding 65,030 66,138 67,021 67,268 67,266 Note: Adjusted Net Income (Loss) is defined as net income (loss) plus the after-tax amount of acquisition-related costs and other non- routine items. Adjusted Net Income (Loss) per diluted share is calculated as Adjusted Net Income (Loss) divided by diluted weighted average common shares outstanding. Adjusted EBITDA is defined as earnings before net interest expense, income taxes, depreciation and amortization, other income (expense), gain or loss on disposal of assets, acquisition-related costs, non-cash share-based compensation expense and other non-routine items.


 
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES RECONCILIATION OF NET DECREASE IN CASH AND CASH EQUIVALENTS TO FREE CASH FLOW USAGE (In thousands) (Unaudited) Three Months Ended March 31, 2019 Net decrease in cash and cash equivalents $ (46,916) Share repurchases (1) 3,298 Other financing activities 918 Free Cash Flow usage $ (42,700) 1. These share repurchases were transacted in December 2018 and settled in cash in January 2019. Note: Free Cash Flow is defined as the net increase (decrease) in cash and cash equivalents before financing activities, including share repurchase activity.


 
C&J ENERGY SERVICES, INC. AND SUBSIDIARIES RECONCILIATION OF FRACTURING NET INCOME (LOSS) TO FRACTURING ADJUSTED EBITDA (In thousands, except average active fleet data) (Unaudited) Three Months Ended March 31, 2019 December 31, 2018 Fracturing net income (loss) $ 10,423 $ (19,748) Adjustments, net of tax: Depreciation and amortization 29,172 26,107 Loss on disposal of assets 2,058 19,027 Non-cash share-based compensation 209 107 Fracturing adjusted EBITDA $ 41,862 $ 25,493 Average active fleets 16.4 16.3 Annualized Adjusted EBITDA per fleet $ 10,210 $ 6,256 Note: Adjusted EBITDA per fleet on an annualized basis, is a non-GAAP measure and is defined as (i) the earnings before net interest expense, income taxes, depreciation and amortization, other income (expense), gain or loss on disposal of assets, acquisition-related costs and other non-routine items for the fracturing product line, (ii) divided by the active fleets per quarter, and then (iii) multiplied by four.


 
Fracturing Stages Wireline Runs 16,203 15,849 5,100 14,704 4,652 4,823 4,872 4,197 13,132 12,628 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 Coiled Tubing Jobs Cementing Jobs 810 843 721 2,503 721 2,357 2,248 2,097 560 1,898 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19


 
U.S. Rig Hours U.S. Truck Hours 336,261 337,306 96,208 95,149 310,445 93,911 307,002 305,546 92,428 92,956 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19