22nd Annual Credit Suisse Energy Summit February 16, 2017 Robert Drummond President and Chief Executive Officer Exhibit 99.1

Safe-Harbor Language This presentation contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These statements are only predictions and are subject to substantial risks and uncertainties and are not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. Often, but not always, “forward-looking statements” are identified by words such as “expects,” “believes,” “anticipates” and similar phrases. Important factors that may affect Key’s expectations, estimates or projections include, but are not limited to, the following: conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies; volatility in oil and natural gas prices; Key’s ability to implement price increases or maintain pricing on its core services; risks that Key may not be able to reduce, and could even experience increases in, the costs of labor, fuel, equipment and supplies employed in Key’s businesses; industry capacity; asset impairments or other charges; the periodic low demand for Key’s services and resulting operating losses and negative cash flows; Key’s highly competitive industry as well as operating risks, which are primarily self-insured, and the possibility that its insurance may not be adequate to cover all of its losses or liabilities; significant costs and potential liabilities resulting from compliance with applicable laws, including those resulting from environmental, health and safety laws and regulations, specifically those relating to hydraulic fracturing, as well as climate change legislation or initiatives; Key’s historically high employee turnover rate and its ability to replace or add workers, including executive officers and skilled workers; Key’s ability to incur debt or long-term lease obligations; Key’s ability to implement technological developments and enhancements; severe weather impacts on Key’s business; Key’s ability to successfully identify, make and integrate acquisitions and its ability to finance future growth of its operations or future acquisitions; Key’s ability to achieve the benefits expected from disposition transactions; the loss of one or more of Key’s larger customers; Key’s ability to generate sufficient cash flow to meet debt service obligations; the amount of Key’s debt and the limitations imposed by the covenants in the agreements governing its debt, including its ability to comply with covenants under its debt agreements; an increase in Key’s debt service obligations due to variable rate indebtedness; Key’s inability to achieve its financial, capital expenditure and operational projections, including quarterly and annual projections of revenue and/or operating income and its inaccurate assessment of future activity levels, customer demand, and pricing stability which may not materialize (whether for Key as a whole or for geographic regions and/or business segments individually); risks affecting Key’s international operations, including risks affecting Key’s ability to execute its plans to withdraw from its international markets outside North America; Key’s ability to respond to changing or declining market conditions, including Key’s ability to reduce the costs of labor, fuel, equipment and supplies employed and used in its businesses; Key’s ability to maintain sufficient liquidity; adverse impact of litigation; and other factors affecting Key’s business described in “Item 1A. Risk Factors” in its most recent Annual Report on Form 10-K, recent Quarterly Reports on Form 10 Q, recent Current Reports on Form K and its other filings with the SEC. Given these risks and uncertainties, readers are cautioned not to place undue reliance on forward-looking statements. Unless otherwise required by law, Key disclaims any obligation to update its forward-looking statements.

A New Key ~$1 billion of long-term debt OTCPink traded after de-listing from NYSE Operating in 8 countries across 4 continents “Silo” organizational structure Customer concentration focused on Majors ~$250 million of annualized G&A expense $250 million of long-term debt NYSE re-listing under ‘KEG’ ticker symbol U.S.-focused production services leader De-layered, geo-market organizational structure Diversified customer targeting via organizational realignment ~$100 million Q3 2016 annualized G&A run-rate Financial Restructuring Equity Re-listing International Dispositions Organizational Restructuring Structural Cost Savings Customer Diversification Key is Well Positioned to Deliver Significant Value to its Shareholders

Company Overview

Improved Support Cost Structure Structural cost reductions via organizational restructuring and support structure efficiencies Actions have yielded ~$90 million of annualized cost improvements Key believes these cost structure improvements to be “sticky” and expects to proactively manage support costs in a market recovery Source: Key Energy Services, Inc. Note: Severance, Foreign Corrupt Practices Act (“FCPA”) and Restructuring expenses are considered non-recurring expenses on a go-forward basis. $0 $10 $20 $30 $40 $50 $60 $70 $80 Q1 '14 Q2 '14 Q3 '14 Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15 Q1 '16 Q2 '16 Q3 '16 Recurring G&A Severance FCPA Restructuring Annualized recurring G&A expense down ~$90 million since Q4 2014

Impact of Structural Changes (1) Costs to return international rigs to U.S. were reported in U.S. Rig Services segment. (2) Divested U.S. operations EBITDA comprised of EOT and Deepwater Offshore Fishing. (3) Reflects EBITDA for businesses divested or otherwise exited; EBITDA loss from International operations exit inclusive of EBITDA from divestitures that are currently pending. Company-wide operational, organizational and strategic restructuring since 2014 Leaner, NAM-focused enterprise on a go-forward basis Significant incremental earnings potential from streamlined cost structure

Strategic Focus – Production Services Recurring production-services business model focused on existing producing wells Robust inventory of existing oil wells in the Lower 48 Regular maintenance requirements provide for significant recurring opportunity scope Source: Key Energy Services. Note: Illustrative example and not to be construed as a typical revenue cycle for Key.

Key Service Offering Overview Rig Services Coiled Tubing Services Fluid Management Services Fishing & Rental Services Drilling & Completion Production Plug & Abandonment Horizontal well completions Specialty fit-for-purpose drilling Logistics management: Delivery, storage & disposal Pre-frac wellbore preparation Post-frac plug milling Premium drill pipe & blowout preventers Frac stack assemblies & well testing Fishing services Heavy workovers Repair & maintenance Re-completions Produced water disposal Wellbore cleanouts Repair & maintenance California Market: Production support for secondary recovery operations Workstring and Tubing Rental Fishing services Rig services Fishing and pipe recovery

Service Line and Geographic Exposure Production-driven services revenue comprises ~80% of YTD 2016 revenue Completion-driven services exposure in all service lines Meaningful exposure to every major U.S. oil & gas producing region Significant Permian exposure, comprising over 1/3 of YTD revenue Source: Key Energy Services. (1) All international operations exited at end of Q3 2016 except Russia.

Production Services Wellsite Presence Well Service Rigs BOP / Well Control Rods Specialty Rental Equipment Accommodations Production Chemicals Rig-Assist Snubbing Light Towers & Generators Handling Equipment Hydraulic Rod / Pipe Handling Systems Wellsite Management Roustabout Services Cement / Remedial Stimulation Fishing Tools Swabbing Units Complementary Service Offerings with Horizontal Integration Potential Fluid Pumps Tubulars

Enhanced Capital Structure Completed financial restructuring yields ~$694 million of long-term debt reduction Remaining tranche of debt renegotiated for more attractive and flexible covenants Strong financial backing and operational support from controlling shareholder Platinum Equity (1) Both cash balances include $18.6 million of restricted cash. Pro-forma cash balance includes $10 million of segregated cash to pay restructuring professionals. (2) On 2/6/2017, KEG increased the size of it’s $80 million ABL by $20.0 million; reflects a borrowing base of $60.0 million and $39.0 million in letters of credit outstanding. (3) Stockholder's Equity adjustments include the conversion of pre- and post-bankruptcy Key Stockholder's Equity, $85 million Primary Rights Offering and $24 million of Rights Offering Liquidity Share. (4) Pro-forma cash balance reduced by $18.6 million of restricted cash and $10 million of segregated cash to pay restructuring professionals. (5) New asset appraisal in process, which is required in order to calculate asset coverage ratio.

Market and Service Demand Overview

Market Opportunity Overview Multiple growth drivers identified moving forward Conventional Well Services Demand via Commodity Price Recovery Well Service Demand Normalization Deferred Maintenance “Catch-up” Effect Aging Horizontal Oil Wells Horizontal Oil Well Service Frequency Upside Completion-driven Rig Demand Source: AESC, DrillingInfo, Evercore ISI Research, Key Energy Services, Inc. (1) Market growth consistent with methodology described on slides 14 & 15 of this presentation; assumes current Working Rigs as a % of Implied Rig Demand of 74%, incremental rigs at historical average of 94%, described on slide 15, in ‘Demand Normalization’ figures. (2) Demand normalization defined as a return to historical Working Rigs as a % of Rig Demand; November 2016 was 74% and January 2012 – December 2014 average of 94%. (3) Number of DeM utilized from slide 17; assumes work frequency described on slide 9 and assumes historical average Working Rigs as a % of Implied Rig Demand of 74% for DeM wells to determine Implied Rig Demand. (4) Calculated using 2018E horizontal well count backlog of ~24k wells entering the regular maintenance interval as shown on slide 20. (5) Assumes a frequency increase for horizontal wells of one job every six months; reflects only the incremental rig demand in-excess of baseline frequency of one job every twelve months. (6) Calculated as the average of 2018E completion rigs forecast shown on slide 22 less the estimated current number of completion rigs working in Q3 2016. Assumes full utilization of estimated working rigs.

Conventional Vertical Well Services Opportunity An increase from $40 oil to $55 oil results in a 35% increase in the U.S. population of “Economic” oil wells Source: DrillingInfo, Key Energy Services. Note: ‘Economic’ defined as an oil well in which the payback associated with the cost of a well service “job” is approximately one year based on existing production levels. Assumptions for well service economics are as follows: Monthly well opex of $2,000, 20% royalty, $5/bbl transport charge, total job cost of $20,000. Well count reflects only active, producing vertical oil wells.

Commodity Recovery to Drive Conventional Demand Expansion Oil price directly drives demand for well services Recent oil prices (~$50) yield an Implied Rig Demand for vertical oil wells of 1,505 well service rigs At today’s industry activity levels (~74% of Implied Rig Demand), vertical well demand expansion could yield the following rig count growth: $55 oil could yield an increase of ~211 total well service rigs $75 oil could yield an increase of ~516 total well service rigs Source: DrillingInfo, Key Energy Services, Inc. (1) Assumes an aggregate composite frequency of well service interventions (repair & maintenance, full workover, etc.) of approximately one job annually per vertical oil well. Further assumes an average duration of 2.88 days per “job” and 100% effective utilization (no weekends, no holidays, regularly scheduled asset maintenance, etc.) to determine a given rig’s effective work capacity. Only active, producing Economic vertical oil wells are considered for each oil price scenario reflected on this graph as defined on slide 14 of this presentation. (2) Current Implied Well Service Rig Demand of 1,505 rigs as of November 2016 based on an average oil price of $46/bbl. The 211 and 516 rig increase figures listed in the bullets represent the difference between current Implied Rig Demand of 1,505 rigs and the Implied Rig Demand of 1,791 and 2,204 at $55 and $75 oil, respectively, shown in the chart above, multiplied by the Current AESC Working Rig Count as a % of Implied Rig Demand figure of 74%, shown on slide 16, to adjust for current industry activity levels.

Demand Normalization Provides Meaningful Activity Uplift Stable relationship historically between working rigs and implied rig demand Additional driver of demand generated through “demand normalization”, i.e. a return to historical average activity level Returning to the 94% historical average today could yield a ~28% increase in total working rigs, or 309 incremental rigs Demand normalization for incremental vertical market expansion at $55 oil could yield an additional ~58 rigs, or 367 total rigs (1) Source: AESC, DrillingInfo, Bloomberg, Key Energy Services, Inc. Note: Implied rig demand generated under same methodology as discussed on slides 14 & 15 of this presentation for historical periods based on average monthly WTI oil prices to derive the universe of Economic oil wells and the associated Implied Rig Demand. Working rigs per AESC rig count data as of November 2016. 2012 – 2014 Average AESC Working Rigs as a % of Rig Demand standard deviation of 3.25%. (1) Implied Rig Demand growth from 1,505 rigs to 1,791 rigs at $55 oil at today’s industry activity level of 74% could yield rig count growth of ~211 rigs, as shown on slide 15. However, assuming normalized demand of 94%, as shown in the chart above, on Implied Rig Demand growth from 1,505 rigs to 1,791 rigs, would yield ~270 incremental rigs, or ~59 additional rigs in addition to the ~211 rigs at today’s industry activity level of 74%.

Increased Deferred Maintenance Driving Demand Backlog… Deferred maintenance oil well population increased from ~0 to ~28,000 since January 2015 Key believes a significant drop in working rigs relative to implied rig demand has created a “wedge” of “deferred maintenance” (“DeM”) vertical oil wells Highly unusual relative to historical norms Backlog of ~28,000 DeM vertical oil wells today provides another catalyst for well service demand DeM backlog could require ~241 well service rigs Source: AESC, DrillingInfo, Bloomberg, Key Energy Services, Inc. Note: Implied rig demand generated under same methodology as discussed on slides 14 & 15 of this presentation for historical periods based on average monthly WTI oil prices to derive the universe of Economic vertical oil wells and the associated implied rig demand. Working rigs per AESC rig count data as of November 2016. (1) The figures reflected in this chart are the summation of incremental well service candidates classified as ‘DeM’ wells over the 2012 – 2016 time period reflected.

…The Evidence Can Be Seen in NAM Production Source: DrillingInfo, Key Energy Services, Inc. As operators have reduced the working well service rig count relative to implied demand, oil production has fallen materially Natural decline rates and “shut-in” wells are primary drivers of production declines Well maintenance will be required to “turn on” this existing, available production

Compelling Returns via Maintenance of Existing Oil Wells Source: Key Energy Services, Inc. Note: The above chart utilizes the same payback assumptions described on slide 19 of this presentation. Only depicts payback periods of approximately one year. Existing installed base of Economic oil wells provide a highly-attractive return opportunity in nearly all production and oil price scenarios Investment dollars could move to high cash-return opportunities in a moderated oil price environment Ultimately existing Economic oil wells represent a valuable resource that can be exploited

Aging Horizontal Oil Well Backlog Provides New, Secular Tailwind Source: DrillingInfo, Key Energy Services, Inc. Note: Utilizes the same job frequency and utilization assumptions described on slide 15 and are applied to the Future Cumulative HZ Wells >4 Years Old shown in the chart above. Proliferation of HZ oil wells has created a new class of well service candidates Delay between completion of a new HZ oil well and the beginning of the regular maintenance interval yields a significant well service backlog Incremental rig demand could require ~642 well service rigs for the existing installed base of aging HZ oil wells

Demand Upside via Increased HZ Well Service Frequency Source: DrillingInfo, Key Energy Services, Inc. Note: Reflects same data set shown on slide 20 for Future Cumulative HZ Wells >4 Years Old; assumes baseline frequency rate of one job every 12 months, then increases job frequency to one job every 8 months and then one job every 6 months. Additional well service demand potential as HZ oil wells can benefit from more frequent well maintenance ~65% of all HZ oil wells produce >10 bbls/day, yielding a ~60 day payback at $55 oil and a ~40 day payback at $75 oil Combination of higher natural decline rates and 1-2 month paybacks could drive materially higher frequency of well service jobs and associated rig demand

Multi-Purpose Assets Benefit from Completions Activity Source: BHI, Inc., Evercore ISI Research, Key Energy Services, Inc. (1) Assumes a 4:1 ratio of drilling rigs to completions-focused well service rigs. Majority of work performed by well service rigs is production-focused, though there are well completion applications Well service rigs are used for frac plug mill-out’s during the completion of a new well Deeper wells with longer laterals can require a well service rig, rather than coiled tubing, to optimally complete a mill-out Well service rig completions don’t face the same depth limitations as coiled tubing

Multiple Drivers for Significant Demand Growth Commodity price recovery drives nominal market growth Normalization of well maintenance activity provides added layer of demand growth “Catch-up” effect of DeM wells can provide for added upside Horizontal well backlog provides for new feature of demand Completion-focused activity provides for incremental demand Multiple growth drivers, in addition to HZ frequency expansion upside, yields significant market opportunity Source: AESC, DrillingInfo, Evercore ISI Research, Key Energy Services, Inc. (1) Market growth consistent with methodology described on slides 14 & 15 of this presentation; assumes current Working Rigs as a % of Implied Rig Demand of 74%, incremental rigs at historical average of 94%, described on slide 15, in ‘Demand Normalization’ figures. (2) Demand normalization defined as a return to historical Working Rigs as a % of Rig Demand; November 2016 was 74% and January 2012 – December 2014 average of 94%. (3) Number of DeM utilized from slide 17; assumes work frequency described on slide 9 and assumes historical average Working Rigs as a % of Implied Rig Demand of 74% for DeM wells to determine Implied Rig Demand. (4) Calculated using 2018E horizontal well count backlog of ~24k wells entering the regular maintenance interval as shown on slide 20. (5) Assumes a frequency increase for horizontal wells of one job every six months; reflects only the incremental rig demand in-excess of baseline frequency of one job every twelve months. (6) Calculated as the average of 2018E completion rigs forecast shown on slide 22 less the estimated current number of completion rigs working in Q3 2016. Assumes full utilization of estimated working rigs.

Operational Update U.S. segments combined Q4 2016 revenue up approximately 4% compared to Q3 2016 Absolute rig hours and per-workday rig hours up in Q4 relative to Q3 Historically Q4 is a seasonally-down quarter relative to Q3 due to holidays and severe weather disruptions Q4 rig hours of ~169k up ~163k compared to Q3 Average rig worked in Q4 2016 of 194 compared to 184 rigs in Q3 2016 Pricing discount recovery occurring in certain markets After a slow start due to weather, Permian rig count at a 12-month high in January Source: Key Energy Services, Inc.

Final Thoughts Well positioned to benefit from secular market trends Strong geographical footprint with significant Permian Basin exposure Recently emerged from pre-packaged bankruptcy with significantly less debt and strong financial sponsor backing Structurally reduced our support costs Divested international operations and reorganized business to focus on opportunities in the U.S.A. Limited capital needs to drive significant cash flow growth Meaningful operating leverage Focused on delivering value to shareholders