Full Year and Fourth Quarter 2018 Earnings Call Presentation FEBRUARY 21, 2019 1

Important Disclaimer 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 impacts 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 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 new 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 December 31, 2018 unless otherwise indicated. Non-GAAP Financial Measures: This presentation includes consolidated Adjusted EBITDA, Adjusted Net Income and Free Cash Flow, all of which are measures not calculated in accordance with generally accepted accounting principles in the U.S. ("U.S. GAAP"). Please see slides 17 – 19 for a reconciliation of net income (loss) to each of Adjusted Net Income (loss) and Adjusted EBITDA and for a reconciliation of net increases (decreases) in cash and cash equivalents to free cash flow. 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. 2

2018 Financial Highlights ● Grew consolidated revenue 36% to a Company record $2.2 billion and generated Adjusted EBITDA(1) of $284 million, approaching the highest in Company history ● Initiated $150 million share buyback program and repurchased $40.4 million of C&J common stock in 2H’18, representing 3.6% of total shares outstanding since announcement ● Generated a net increase in cash of $21.9 million with free cash flow(2) generation of $66.3 million ● Maintained a debt-free balance sheet with total liquidity of $370 million+ 1. See slide 17 for a reconciliation of net income (loss) to Adjusted EBITDA. 2. See slide 19 for a reconciliation of net increases (decreases) in cash and cash equivalents to free cash flow. 3

2018 Operational Highlights ● Delivered superior service quality to our growing customer base while also achieving the best safety record by incident rates in our Company’s history ● Completed the O-Tex Pumping integration that more than doubled the size of our legacy Cementing business and created one of the largest U.S. onshore oilfield cementers ● Made significant progress on divesting select non-core businesses including Directional Drilling and Artificial Lift ● Launched multiple R&T initiatives to increase efficiency and reduce non- productive time including frac pump warm start technology, blender upgrades and standardization, cloud-based data analytics and our Tru-Mill frac plug ● Partnered with long-time customers to deploy additional assets and grow market share returning our Well Support Services segment to improved financial performance 4

4Q’18 Financial & Operational Highlights ● Generated $78 million of free cash flow(1) by cutting costs, reducing capital expenditures and managing working capital ● Repurchased ~1.4 million shares of common stock for $20 million, or $13.85 per share ● Continued to focus on returns by reducing capex 25% sequentially ● Re-deployed spot fleets to dedicated customers in the Mid-Continent and West Texas and exited 4Q’18 back at our low 2Q’18 spot fleet levels ● Over 65% of deployed frac fleets now streaming performance data to cloud based analytics system designed to monitor operational performance and enable preemptive maintenance ● Increased productivity of perforating gun manufacturing process with installation of robotic manufacturing cell designed to increase production capacity by over 50% ● Increased Well Support Services segment revenue 5% sequentially and improved Adjusted EBITDA margin by ~150 bps 1. See slide 19 for a reconciliation of net increases (decreases) in cash and cash equivalents to free cash flow. 5

4Q’18 Financial Highlights & Market Conditions 4Q’18 Market Conditions Consolidated Revenue ● Revenue was flat y-o-y but decreased 14% sequentially; Adj. ($ in millions) EBITDA decreased 14% y-o-y and 32% sequentially $611 $553 $568 ● 4Q’18 results negatively affected by customer budget $492 $491 exhaustion, higher levels of year-end seasonality and the general slowing of completion activity into year-end ● Fracturing utilization improved throughout 4Q’18 and we exited 2018 with the lowest spot fleet count since 2Q’18 ● Wireline and Pumping experienced lower activity levels ● Demand for large diameter coiled tubing remained strong but activity levels declined in our Well Construction & Intervention 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 Services segment ● Deployed more equipment and grew market share in our Well Support Services segment Consolidated Adjusted EBITDA(1) Consolidated Adjusted Net Income(2) ($ in millions) Margin (%) ($ in millions) 14% $34 13% $27 $88 13% 12% $20 $74 $73 10% $11 $57 $49 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 -$18 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1. See slide 17 for a reconciliation of net income (loss) to Adjusted EBITDA. 2. See slide 18 for a reconciliation of net income (loss) to Adjusted net income (loss). 6

4Q’18 Revenue Overview Revenue by Business Revenue by Basin Fluids Management 6% Rig Services 8% 13% 11% 35% Coiled Tubing 39% 6% Fracturing 12% Cementing 13% 12% 4% 22% Other 19% Completions Wireline & Pumping West Texas South Texas / East Texas Rockies / Bakken California 81% of Revenue from New Well Focused Services Mid-Continent Northeast 7

Completion Services Segment Overview Full Year & Fourth Quarter 2018 Highlights Reported Segment Revenue ($ in millions) ● 2018 segment revenue and Adjusted EBITDA $413 $374 $373 increased 31% to $1.5 billion and 37% to $274 $343 million, respectively, when compared to 2017 $293 ● Our fracturing business generated over $1.0 billion of annual revenue for the first time in Company history ● 4Q’18 segment revenue decreased 15% year-over- year and 21% sequentially to $293 million ● 4Q’18 segment Adjusted EBITDA decreased 39% year-over-year and 33% sequentially to $44 million 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 ● 4Q’18 fracturing revenue and profitability were negatively affected by customer budget exhaustion Reported Segment Adjusted EBITDA Margin (%) and lower activity levels, partially due to decreased ($ in millions) asset deployment 22% 20% 21% ● Temporarily idled two horizontal fracturing fleets in $81 $83 18% early October, but redeployed them to dedicated $73 $66 15% customers in early December that commenced 2019 completion activities earlier than anticipated $44 ● Exited 4Q’18 with the lowest number of spot frac fleets since 2Q’18 ● Wireline and Pumping revenue and profitability 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 negatively affected by soft activity levels from customer budget exhaustion, year-end seasonality and inclement weather 8

Well Construction & Intervention Services Segment Overview Full Year & Fourth Quarter 2018 Highlights Reported Segment Revenue ($ in millions) ● 2018 segment revenue and Adjusted EBITDA increased 151% to $376 million and ~3x to $68 $99 $96 $94 million, respectively, when compared to 2017 $87 ● Revenue and profitability improvement mostly driven $56 by the O-Tex Pumping acquisition in November 2017 that more than doubled the size of our cementing business ● 2018 coiled tubing revenue increased 47% to $115 million when compared to 2017 due to the 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 deployment of new large diameter units, improved utilization and disciplined pricing ● 4Q’18 segment revenue increased 66% year-over- Reported Segment Adjusted EBITDA Margin (%) year, but decreased 2% sequentially to $94 million ($ in millions) ● 4Q’18 segment Adjusted EBITDA increased 60% year-over-year, but decreased 9% sequentially to 20% 18% 18% 17% $16 million 17% $20 ● 4Q’18 segment revenue and profitability were $16 $17 $16 negatively affected by customer budget exhaustion $10 and year-end seasonality ● Demand for large diameter coiled tubing remained strong in 4Q’18, but activity levels fell mostly due to 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 lower completion-driven activity 9

Well Support Services Segment Overview Full Year & Fourth Quarter 2018 Highlights Reported Segment Revenue ● 2018 segment revenue and Adjusted EBITDA ($ in millions) increased 3% to $393 million and ~4x to $40 million, $99 $104 respectively, when compared to 2017 $92 $91 $99 ● In 2018, we further streamlined costs, deployed additional assets and maintained disciplined pricing while improving both safety and service quality ● Prior year results contained our Canadian rig services business that we divested in November 2017, which diluted 2018 revenue and profitability improvement 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 ● 4Q’18 segment revenue increased 13% year-over- year and 5% sequentially to $103.9 million Reported Segment Adjusted EBITDA Margin (%) ● 4Q’18 segment Adjusted EBITDA increased ~5x year- ($ in millions) over-year and 19% sequentially to $12.9 million 12% 11% 11% ● 4Q’18 segment results improved due to additional $13 equipment deployment and disciplined pricing $11 $11 ● Exited 4Q’18 with highest deployed workover rig count 6% and day rate of 2018 after deploying more rigs 3% $5 primarily in California and West Texas $3 ● Special Services revenue and profitability remained strong due to increased fishing and rental activity in 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 our Rig Services business ● Fluids Management business benefited from the full quarter impact of contract wins in California from late 3Q’18, offset by lower activity levels in South Texas 10

Continued Focus on Reducing Cash Costs SG&A Expense D&A Expense ($ in millions) ($ in millions) $61 $63 $68 $66 $54 $60 $46 $50 $50 $40 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 4Q’18 Highlights 1Q’19 Cost Guidance ● SG&A expense decreased ~27% year-over-year and was ● SG&A expense to range between $54MM – $58MM flat sequentially at $49.8MM ● D&A expense to range between $61MM – $65MM ● R&D expense was flat year-over-year but increased 11% ● R&D expense to range between $2.3MM – $2.5MM sequentially to $1.4MM ● Large NOL position; not expected to be a cash tax payer ● Capital expenditures decreased 25% sequentially with the exception of certain state and local taxes ● Recorded $146MM non-cash goodwill impairment charge ● Capital expenditures to decline significantly in 2019 with associated with WC&I reporting unit 1Q’19 expenditures expected to range between $50MM – ● Recorded $21.4MM non-cash loss on retirement of fixed $60MM, which includes some rollover from 4Q’18 assets of certain fracturing, coiled tubing and well servicing units 11

Strong Capital Structure and Reasonable Growth Plan No Leverage and Ample Liquidity 2019 Capital Budget & Highlights ($ in millions) $466 Corporate, Facilities, $414 $393 R&T and Other $371 13% $356 $326 $235 17% Growth $317 $110 $136 70% $88 $76 Maintenance Proforma 3/31/18 6/30/2018 9/30/2018 12/31/2018 Cash ABL Availability ● One of the strongest balance sheets in the sector ● 2019 capital expenditures expected to range between $140MM – $180MM ● Strong liquidity position to fund capital expenditures and potential accretive bolt-on acquisitions ● Allocating ~$3.0MM of annual maintenance capex per deployed fleet in our Fracturing business, a 30% reduction ● As of 12/31/18, excluding letters of credit, no outstanding compared to 2018 borrowings under our asset based credit facility ● Growth capital expenditures mostly pertain to: ● Purchased ~$20MM, or ~1.4 million shares, of C&J common stock during the fourth quarter ● Two large diameter coiled tubing units recently ordered with expected delivery in 3Q’19 ● ~$1.4Bn of NOLs represents substantial value with potential incremental FCF impact of almost $300MM ● Greaseless cable and pressure control systems to increase efficiency and safety in our Wireline business ● Ancillary components in our Fracturing business to increase safety and lower long-term operating costs 12

Thoughts on the Forward Outlook 1Q’19 Outlook 2019 Thoughts ● Expecting consolidated revenue and Adjusted EBITDA to be ● Remain focused on dedicating frac fleets with long- flat to slightly down sequentially standing, efficient customers throughout 2019 ● Utilization in our Fracturing business has continued to ● Two dedicated frac fleets deployed to mid-cap customer in improve due to refreshed E&P capital expenditure budgets the Mid-Continent in late November 2018 with strong and our lowest spot fleet count since 2Q’18 utilization; customer already requesting additional fleets ● Wireline and Pumping revenue and profitability expected to ● Deployed second dedicated fleet to current major integrated decline sequentially due to: customer in West Texas in early December 2018 with strong utilization; now fracing in two basins for this customer ● Bakken and Rocky Mountains customers indicating delayed completion activity until late 1Q’19 ● Focused on maintaining high utilization and strong market share position in Wireline and Pumping businesses ● Instances of inclement weather in select core basins ● Pumping units expected to be fully deployed ● More competitive pricing environment ● Focused on keeping large diameter coiled tubing units ● Expecting softness in our Well Construction & Intervention deployed with high utilization Services segment due to: ● Focused on high-grading customer base and maintaining ● Lower overall drilling rig count and competitive pricing market share in our Cementing business negatively affecting our Cementing business ● Expecting continued market share growth in California and ● Slower than expected completion activity levels in West Texas in our Well Support Services segment as we certain basins creating some softness in our Coiled deploy more assets with primarily major integrated Tubing business in early 1Q’19 customers ● Expecting continued Well Support Services segment improvement from the deployment of additional assets and growing market share mostly in California and West Texas 13

C&J Tenants: The Differentiated U.S. Oilfield Services Company Leading Diversified Modern, High-Quality 1 Service Provider in most 2 Asset Base Enhanced with U.S. Land Basins Proprietary Technology Established and Growing Focused on Quality, Safe Relationships with 3 and Reliable Execution 4 “Blue-Chip” Customer Base Operating Model Focused Strong Balance Sheet with on Targeted Returns and 5 Low Leverage and Ample 6 Delivering Value to Liquidity Shareholder Committed to Creating Long-Term Shareholder Value 14

APPENDIX: Additional Information & Non-GAAP Reconciliation

Historical Financial Summary Select Historical Financial Information $MM; unless otherwise stated Full Year Full Year Full Year 2016 1Q'17 2Q'17 3Q'17 4Q'17 2017 1Q'18 2Q'18 3Q'18 4Q'18 2018 Revenue Completion Services $524 $192 $263 $309 $343 $1,107 $374 $413 $373 $293 $1,454 Well Construction & Intervention Services 84 26 31 36 56 150 88 99 96 94 376 Well Support Services 364 96 96 98 92 382 91 99 99 104 393 Total Revenue $971 $314 $390 $443 $492 $1,639 $553 $611 $568 $491 $2,222 Total Gross Profit (1) $24 $52 $80 $103 $116 $351 $134 $147 $122 $94 $497 % Margin 2% 17% 21% 23% 24% 21% 24% 24% 21% 19% 22% Net Income / (Loss) ($944) ($32) ($13) $10 $57 $22 $21 $28 $10 ($190) ($130) Adjusted EBITDA (2) Completion Services ($43) $22 $45 $62 $73 $201 $81 $83 $66 $44 $274 Well Construction & Intervention Services (4) 1 3 7 10 21 16 20 17 16 68 Well Support Services 19 4 2 1 3 9 5 11 11 13 40 Corporate / Eliminations (67) (22) (25) (26) (28) (100) (28) (26) (21) (23) (99) Total Adjusted EBITDA (2) ($95) $5 $25 $44 $57 $131 $74 $88 $73 $49 $284 % Margin (10%) 2% 6% 10% 12% 8% 13% 14% 13% 10% 13% 1. Gross profit defined as revenue less direct costs 2. Please see slide 17 for a reconciliation of net income (loss), the nearest measure calculated in accordance with U.S. GAAP 16

Non-GAAP Reconciliation Adjusted EBITDA Reconciliation* $MM Full Year Full Year Full Year 2016 1Q'17 2Q'17 3Q'17 4Q'17 2017 1Q'18 2Q'18 3Q'18 4Q'18 2018 Net income (loss) ($944) ($32) ($13) $10 $57 $22 $21 $28 $10 ($190) ($130) Interest expense, net 157 1 0 0 0 2 0 2 1 1 4 Income tax expense (benefit) (129) (3) (2) (3) (31) (40) (0) (1) (2) 0 (2) Depreciation and amortization 217 32 33 36 40 141 46 54 61 63 225 Other (income) expense, net (10) (2) 1 (1) 1 (0) (1) 1 (0) (3) (2) (Gain) loss on disposal of assets 3 (6) (3) (1) (21) (31) (0) 0 1 25 26 Impairment expense 436 - - - - - - - - 146 146 Restructuring costs 31 - 8 2 2 11 1 2 0 0 3 Reorganization costs 55 - - - - - - - - - - Inventory reserve 35 - - - - - - - - 6 6 Acquisition-related and other transaction costs 11 - - 1 3 4 1 0 - - 1 Severance and business divestiture costs 34 - 1 - 5 6 6 0 1 - 7 Share-based compensation expense acceleration 8 16 - - - 16 - - - 0 0 Adjusted EBITDA ($95) $5 $25 $44 $57 $131 $74 $88 $73 $49 $284 Note: *We present Adjusted EBITDA, because management believes that the disclosure of Adjusted EBITDA as a measure of the Company’s operating performance allows investors to make a direct comparison to competitors, without regard to differences in capital and financing structure and the incurrence of other charges that impact comparability of our results of operations to those of our competitors. Investors should be aware, however, that there are limitations inherent in using Adjusted EBITDA as a measure of overall profitability because it excludes significant expense items. An improving trend in Adjusted EBITDA may not be indicative of an improvement in the Company’s profitability. To compensate for the limitations in utilizing Adjusted EBITDA as an operating measure, management also uses U.S. GAAP measures of performance, including operating income (loss) and net income (loss), to evaluate performance. As required under Regulation G and Item 10(e) of Regulation S-K, the table above provides a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, from net income (loss), which is the nearest comparable U.S. GAAP financial measure for the years ended December 31, 2017 and 2016 and for their interim periods. We generally define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation and amortization, other income (expense), gain or loss on the disposal of assets and other items that our management considers to be extraordinary, such as impairment expenses, acquisition-related costs, costs and charges associated with severance, facility closures, write-offs of bad debts and similar charges. Additionally, for the years ended December 31, 2017 and 2016 and for their interim periods, we have added back in calculating Adjusted EBITDA several categories of expenses and charges incurred in connection with our Chapter 11 proceedings which are detailed in the table above. 17

Non-GAAP Reconciliation (continued) 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 December 31, 2018 September 30, 2018 December 31, 2017 Net income (loss) $ (189,527) $ 10,433 $ 56,995 Adjustments, net of tax: Impairment expense 146,015 — — Loss on retirement of assets 21,410 — — Inventory reserve 6,131 — — Settlements related to financial restructuring (2,400) — — Income tax benefit associated with the O-Tex acquisition — — (28,950) Net gain on sale of Canadian rig services business — — (11,766) Acquisition-related and other transaction costs — — 3,423 Other 204 129 — Adjusted net income (loss) $ (18,167) $ 10,562 $ 19,702 Per common share: Net income (loss) diluted $ (2.87) $ 0.16 $ 0.88 Adjusted net income (loss) diluted $ (0.27) $ 0.16 $ 0.31 Diluted weighted average common shares outstanding 66,138 67,021 64,497 18

Non-GAAP Reconciliation (continued) C&J ENERGY SERVICES INC. AND SUBSIDIARIES RECONCILIATION OF NET INCREASE IN CASH AND CASH EQUIVALENTS TO FREE CASH FLOW (In thousands) (Unaudited) December 31, 2018 Three Months Ended Year Ended Net increase in cash and cash equivalents $ 59,842 $ 21,859 Share repurchases (1) 16,721 37,053 Other financing activities 1,673 7,373 Free cash flow $ 78,236 $ 66,285 1. $3.3 million of share repurchases were transacted on December 28, 2018 and December 31, 2018 and settled in cash on January 2, 2019 and January 3, 2019. 19

Supplemental Information Fracturing Stages Wireline Runs 16,203 15,849 14,704 4,652 4,823 4,872 14,325 4,057 4,197 13,132 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 Coiled Tubing Jobs Cementing Jobs 843 2,503 2,357 810 2,248 2,097 743 1,222 721 721 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 20

Supplemental Information (continued) U.S. Rig Hours U.S. Truck Hours 336,261 95,149 310,445 93,911 304,185 307,002 305,546 92,956 92,302 92,428 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 21