This presentation (and any oral statements made regarding the matters in this presentation, including those related to the proposed merger with Keane) 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 that address circumstances, activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. In addition, words such as “anticipate,” “believe,” “ensure,” “expect,” “if,” “once” “intend,” “plan,” “focus,” “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: we may be unable to obtain governmental, stockholder and/or regulatory approvals required for the proposed Merger, or required approvals may delay the proposed Merger or result in the imposition of conditions that could cause the parties to abandon the proposed Merger; conditions to closing the proposed Merger may not be satisfied or the timing to complete the proposed Merger may change; we may not realize, or it may take longer to realize, expected cost savings, benefits and any other synergies from the proposed Merger; disruption from the proposed Merger may make it more difficult to maintain relationships with customers, employees or suppliers; 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 may impact, 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 of our significant customers; the failure by one or more of our significant customers to pay amounts when due, or at all; adverse weather conditions in oil or gas producing regions; changes in customer requirements in the markets 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; operating hazards inherent in our industry, including the possibility of accidents resulting in personal injury or death, property damage or environmental damage; 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; 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; the loss of, or inability to attract, key management and other competent personnel; a shortage of qualified workers; our ability to implement new technologies and services; 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 debt facilities. 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 U.S. Securities and Exchange Commission, 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. 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. 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 June 30, 2019 unless otherwise indicated. Non-GAAP Financial Measures: This presentation includes consolidated Adjusted EBITDA, Adjusted EBITDA per fully-utilized fleet, 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 16 – 19 for a reconciliation of net income (loss) to each of Adjusted Net Income (loss) and Adjusted EBITDA, a reconciliation of net increases (decreases) in cash and cash equivalents to free cash flow, a reconciliation of fracturing net income (loss) to Adjusted EBITDA, and a reconciliation of SG&A to Adjusted SG&A. 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.

● Consolidated revenue totaled $501 million, generating Adjusted EBITDA(1) of $52 million, reported Adjusted EPS(1) of ($0.20), and free cash flow(2) of $26 million ● Stacked under-utilized equipment in several businesses and idled two horizontal and one vertical fracturing fleet, generating annualized Adjusted EBITDA per fully-utilized fleet(3) of ~$11.3 million vs. ~$12 million in the prior quarter ● Reduced SG&A headcount 11% since year-end 2018 ● Restructured our research & technology division, eliminated two executive positions, flattened the management structure in our cementing business, and upgraded our SAP ERP system, which positions us well for further productivity and efficiency improvement in the coming quarters ● Cost reductions resulted in Adjusted SG&A(4) expense decreasing 20% y-o-y and 11% sequentially ● Well Support Services segment Adjusted EBITDA(1) doubled sequentially, generating double-digit segment Adjusted EBITDA margin in line with previous guidance ● Divested the majority of our South and West Texas fluids management assets on July 31, 2019 1. See slide 16 for a reconciliation of net income (loss) to Adjusted Net Income (loss) to Adjusted EBITDA and Adjusted EPS. 2. See slide 17 for a reconciliation of net increase (decrease) in cash and cash equivalents to free cash flow. 3. See slide 18 for a reconciliation of fracturing net income (loss) to fracturing Adjusted EBITDA per fully-utilized fleet. 4. See slide 19 for a reconciliation of SG&A to Adjusted SG&A.

2Q’19 Market Conditions Consolidated Revenue ● Revenue decreased 18% y-o-y and 2% sequentially; Adj. ($ in MM) EBITDA decreased 43% y-o-y, but increased 5% sequentially $611 ● Results negatively affected by increased white space in our frac calendar and lower customer activity levels and competitive $568 pricing in most of our non-fracturing businesses ● Wireline and Pumpdown experienced improved activity levels in $511 $501 $491 most basins; however, pricing has remained competitive ● Returned two large diameter coiled tubing units to service by late May, but lower drilling rig count and competitive pricing in our cementing business negatively affected WC&I results 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 ● Well Support Services segment activity levels increased mostly from improved workover rig counts in California resulting in improved segment profitability Consolidated Adjusted EBITDA(1) Consolidated Adjusted Net Income (loss)(1) ($ in MM) Margin (%) ($ in MM) 15% $35 $92 14% $77 11% 10% 10% $11 $52 $53 $50 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 -$13 -$18 -$19 2Q'18 3Q'18 4Q'18 1Q'19 2Q'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% 9% Rig Services 14% 15% 34% Fracturing Coiled Tubing 44% 5% 13% 10% Cementing 2% 10% 19% Other 18% Completions Wireline & Pumpdown West Texas South Texas / East Texas Rockies / Bakken California 79% of Revenue from New Well Focused Services Mid-Continent Northeast

($ in MM) ● Segment revenue decreased 22% year-over-year and 1% sequentially to $322MM $413 $373 ● Segment Adjusted EBITDA decreased 43% year- over-year and 12% sequentially to $48MM $327 $322 $293 ● Fracturing revenue decreased 24% year-over-year and 7% sequentially to $220MM ● Fracturing experienced increased white space in the frac calendar mostly due to operational inefficiencies 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 ● Stacked two horizontal and one vertical fracturing fleet due to decreased utilization Margin (%) ($ in MM) ● Annualized Adjusted EBITDA per fully-utilized fleet(1) 20% declined 6% sequentially to $11.3 million $84 18% $67 17% ● Wireline and Pumpdown revenue decreased 20% 15% 15% $54 year-over-year, but increased 11% sequentially $48 $44 ● Wireline and Pumpdown experienced a sequential increase in customer activity levels, especially in our largest operating basin of the Bakken 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 ● Wireline and Pumpdown activity levels are expected to remain stable relative to 2Q’19 exit rates; however, pricing is expected to remain competitive 1. See slide 18 for a reconciliation of fracturing net income (loss) to fracturing Adjusted EBITDA per fully-utilized fleet.

($ in MM) ● Segment revenue decreased 27% year-over-year and 8% sequentially to $73 million $99 $96 ● Segment Adjusted EBITDA decreased year-over- $94 year, but increased 8% sequentially to $7 million $79 $73 ● Segment profitability improved due to the: o Return of two large diameter coiled tubing units to service by late-May o Stacking of under-utilized equipment, closing 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 unprofitable facilities and further streamlining corporate overhead in Cementing Margin (%) ● Cementing revenue decreased 30% year-over-year ($ in MM) and 11% sequentially to $48MM 20% ● Coiled Tubing revenue decreased 18% year-over- 18% year and 3% sequentially to $24MM $20 17% $17 $16 ● Return to service of large diameter units should 8% 10% increase Coiled Tubing revenue, but lower rig count $7 $7 and competitive pricing in Cementing will cause WC&I revenue to decline in 3Q’19 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19

($ in MM) ● Segment revenue increased 8% year-over-year to $106MM and was essentially flat sequentially $106 $104 $105 ● Segment Adjusted EBITDA increased 17% year-over- $99 $99 year and doubled sequentially to $13MM ● Segment profitability increased primarily due to: o Higher customer activity levels in most operating basins 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 o Improved weather conditions o Additional workdays with longer daylight hours Margin (%) ● Rig Services experienced highest deployed rig count ($ in MM) in California and the Mid-Continent in over a year, 13% 13% partially offset by rig declines in West Texas 12% 11% $13 $13 $11 $11 ● Divested most of our South and West Texas Fluids 7% Management assets on July 31, 2019 $7 ● Segment revenue to decline in 3Q’19 due to the announced Fluids Management asset divestiture, which should be partially offset by slightly higher activity levels in our Rig Services and Special 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 Services businesses

SG&A Expense D&A Expense ($ in MM) ($ in MM) $61 $63 $60 $57 $60 $58 $54 $55 $54 $50 $50 $50 $49 $52 $46 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 (1) SG&A Adjusted SG&A 2Q’19 Highlights 3Q’19 Cost Guidance ● SG&A expense decreased 9% year-over-year but increased ● D&A expense to range between $54MM – $58MM 2% sequentially to $55MM ● SG&A expense to range between $50MM – $55MM, which o Included ~$6MM of severance and business includes expected merger-related costs divestiture costs and ~$3MM of merger-related ● Not expected to be a cash tax payer with the exception of transaction costs certain state and local taxes o Adjusted SG&A(1) totaled $46MM falling to 9.2% of ● Capital expenditures expected to range between $35MM – consolidated revenue primarily due to an 11% $40MM reduction in SG&A headcount since YE’18 ● Capital expenditures decreased both year-over-year and sequentially to $43MM mostly due to lower growth capex 1. See slide 19 for a reconciliation of SG&A to Adjusted SG&A.

No Leverage and Ample Liquidity Revised 2019 Capital Budget ($ in MM) Cash ABL Availability Corporate, Facilities, $393 R&T and Other $371 $364 $380 7% 8% Growth $235 $266 $317 $275 85% Maintenance $136 $114 $76 $89 9/30/2018 12/31/2018 3/31/2019 6/30/2019 ● One of the strongest balance sheets in the sector ● Reduced 2019 capital expenditure guidance range by 6% at the mid-point to $140MM – $160MM ● Strong liquidity position to fund capital expenditures and invest in technologies to further enhance efficiencies ● Allocating ~$3.0MM of annual maintenance capex per deployed fleet in our Fracturing business, a 30% reduction ● As of 6/30/19, excluding letters of credit, no outstanding compared to 2018 due to our younger fleet profile borrowings under our asset-based credit facility ● Growth capital expenditures mostly pertain to: o Two large diameter coiled tubing units with expected delivery in 1Q’20 o Ancillary components that increase efficiency and safety in our Fracturing and Wireline businesses

3Q’19 Outlook(1) 2H’19 Thoughts(1) ● Currently expecting consolidated revenue to decline mid to ● Focused on dedicating deployed fracturing fleets with long- upper single digits sequentially due to the divestiture of our standing, efficient customers South and West Texas fluids management assets on July 31, 2019, continued white space in the frac calendar, and ● Will prudently manage asset base in all core businesses in competitive pricing in our non-fracturing businesses line with current market conditions, customer demand, and expectations for customer budget exhaustion ● Fracturing revenue currently expected to decrease mid to upper single digits due to instances of white space in the ● Focused on keeping large diameter coiled tubing units frac calendar from customer budget exhaustion and delayed deployed with high utilization and deploy two new build 2⅝ completion activity inch units with efficient customers in 1Q’20 o Deployed fleet counts will be further adjusted based on market conditions and customer demand ● Will accelerate cost reductions by further streamlining corporate overhead, stacking under-utilized equipment, ● Wireline and Pumpdown revenue currently expected to consolidating facilities, and closing unprofitable districts remain flat sequentially due to higher customer activity o Upgraded SAP ERP system positions us well for levels being offset by continued pricing pressure further cost saving over the coming quarters ● WC&I segment revenue currently expected to decrease upper single to low double digits sequentially due to lower ● Reduced 2019 capital expenditure program by 6% at the drilling rig count, soft customer activity levels and mid-point to $140MM – $160MM competitive pricing in our Cementing business ● Focused on free cash flow generation during 2H’19 ● Currently expecting Well Support Services segment revenue to decline upper single digits due to the divestiture of select fluids management assets as well as other market-driven closures; however, profitability should remain stable 1. As of August 6, 2019.

$MM; unless otherwise stated Full Year 1Q'18 2Q'18 3Q'18 4Q'18 2018 1Q'19 2Q'19 Revenue Completion Services $374 $413 $373 $293 $1,454 $327 $322 Well Construction & Intervention Services 88 99 96 94 376 79 73 Well Support Services 91 99 99 104 393 105 106 Total Revenue $553 $611 $568 $491 $2,222 $511 $501 Total Gross Profit (1) $134 $147 $122 $94 $497 $94 $93 % Margin 24% 24% 21% 19% 22% 18% 18% Net Income (Loss) $21 $28 $10 ($190) ($130) ($24) ($110) Adjusted EBITDA Completion Services $82 $84 $67 $44 $277 $54 $48 Well Construction & Intervention Services 16 20 17 16 70 7 7 Well Support Services 6 11 11 13 41 7 13 Corporate / Eliminations (25) (24) (19) (21) (88) (18) (16) Total Adjusted EBITDA (2) $79 $92 $77 $53 $300 $50 $52 % Margin 14% 15% 14% 11% 13% 10% 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) TO ADJUSTED EBITDA (In thousands, except per share data) (Unaudited) Three Months Ended June 30, 2019 March 31, 2019 December 31, 2018 September 30, 2018 June 30, 2018 Net income (loss) $ (110,306) $ (23,573) $ (189,527) $ 10,433 $ 28,496 Adjustments, net of tax: Severance and business divestiture costs 7,668 3,336 - 129 1,150 Loss on disposal of assets 6,881 - - - - Impairment expense 79,935 - 146,015 - - Asset impairment - - 21,410 - - Inventory reserve - - 6,131 - - Merger/transaction-related costs 2,640 - - - 243 Non-cash deferred financing charge - - - - 1,508 Restructuring costs and other 70 1,707 (1,879) 726 3,563 Adjusted net income (loss) $ (13,112) $ (18,530) $ (17,850) $ 11,288 $ 34,960 Depreciation and amortization 58,093 59,756 63,389 60,748 54,387 (Gain) loss on disposal of assets 1,881 1,956 3,536 2,471 (1,061) Interest expense, net 442 347 617 669 677 Other (income) expense, net 449 (465) (316) (370) (294) Income tax expense (benefit) (1,065) 920 43 (1,504) (893) Non-cash share-based compensation, excluding severance 5,292 5,573 3,145 4,071 4,138 Adjusted EBITDA $ 51,980 $ 49,557 $ 52,564 $ 77,373 $ 91,914 Per common share: Net income (loss) diluted $ (1.69) $ (0.36) $ (2.87) $ 0.16 $ 0.42 Adjusted net income (loss) diluted $ (0.20) $ (0.28) $ (0.27) $ 0.17 $ 0.52 Diluted weighted average common shares outstanding $ 65,082 $ 65,030 $ 66,138 $ 67,021 $ 67,268 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 INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS TO FREE CASH FLOW GENERATION (USAGE) (In thousands) (Unaudited) Three Months Six Months June 30, 2019 Net increase (decrease) in cash and cash equivalents $ 25,544 $ (21,372) Share repurchases (1) - 3,298 Other financing activities 49 967 Free Cash Flow generation (usage) $ 25,593 $ (17,107) 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 ADJUSTED EBITDA (In thousands, except average active fleet data) (Unaudited) Three Months Ended June 30, 2019 March 31, 2019 December 31, 2018 September 30, 2018 June 30, 2018 March 31, 2018 Fracturing net income $ 5,539 $ 10,423 $ (19,748) $ 7,613 $ 22,746 $ 42,609 Adjustments, net of tax: Depreciation and amortization 26,670 29,172 26,107 23,860 21,991 17,064 Loss on disposal of assets 2,409 2,058 19,027 941 3,788 (350) Non-cash share-based compensation 210 209 107 257 265 269 Severance and business divestiture costs 248 - - - - - Fracturing adjusted EBITDA $ 35,076 $ 41,862 $ 25,493 $ 32,671 $ 48,790 $ 59,592 Average active fleets 16.1 16.1 15.8 17.7 16.5 15.3 Fleet utilization 77 % 87 % 86 % 90 % 81 % 86 % Annualized Adjusted EBITDA per fully-utilized fleet $ 11,284 $ 11,962 $ 7,412 $ 8,163 $ 14,615 $ 18,100 Note: Adjusted EBITDA per fully-utilized 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 fully-utilized fleets (average active fleets multiplied by fleet utilization) per quarter, and then (iii) multiplied by four.

C&J ENERGY SERVICES INC. AND SUBSIDIARIES RECONCILIATION OF SG&A TO ADJUSTED SG&A (In thousands) (Unaudited) Three Months Ended June 30, 2019 March 31, 2019 June 30, 2018 SG&A $ 54,562 $ 53,684 $ 59,908 Severance and business divestiture costs (5,748) (1,079) (40) Merger/transaction-related costs (2,640) - (243) Restructuring costs and other (70) (861) (2,163) Adjusted SG&A $ 46,104 $ 51,744 $ 57,462 Revenue $ 501,082 $ 510,769 $ 610,521 Adjusted SG&A as a percentage of revenue 9.2 % 10.1 % 9.4 % Note: Adjusted SG&A is defined as selling, general and administrative expenses adjusted for severance and business divestiture costs, merger/transaction-related costs, restructuring costs and other non-routine items.

Fracturing Stages Wireline Runs 16,203 15,849 5,100 15,546 4,823 4,872 4,743 4,197 13,132 12,628 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 Coiled Tubing Jobs Cementing Jobs 843 2,357 2,248 2,097 721 721 1,898 610 1,715 560 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19

U.S. Rig Hours U.S. Truck Hours 336,261 337,306 335,892 96,208 95,985 95,149 310,445 93,911 305,546 92,956 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19