Value Proposition of Polyketone Liners & Continuous Rod in Deviated Wells

Deviated Rod Pumped Failure Methods Abrasive Wear Rod on tubing wear Deviation Buckling Enhanced by presence of solids Corrosive Wear Chemical reaction on surface of tubing Corroded material worn away, allowing for corrosion to attack again 12/10/2018

Potential Benefits of Thermoplastic Liners Prevents rod on tubing contact, eliminating steel on steel wear Does not allow corrosive fluids to continuously erode tubing Protects tubing from exposure to abrasive solids Holiday-free to prevent localized corrosion attack 12/10/2018

Thermoplastic Liner Resin Options General Specifications Material Type Max Temp. Dimensions H2S CO2 Cost HDPE 140° F 2 3/8" - 4 1/2" 2% 10% $ HDPE - Modified 210° F $$ POK - Modified 240° F 5% 20% PPS - Modified 340° F $$$$ PEEK 500° F $$$$$ 12/10/2018

Polyolefin Ketone Resin (POK) Unique engineering plastic with a carbon-only backbone Highly crystalline with a compact crystal structure Stable at high temperatures Has excellent abrasion/chemical/fuel resistance Gas barrier properties Physical and chemical properties make the resin well suited for downhole applications 12/10/2018

Resin Working Temperature vs. Cost 12/10/2018

Potential Benefits of Continuous Rod Side Load Distributed over Entire String, Not on Coupling Alone No Reduced Flow Area around Couplings Reduce breakout of corrosive elements due to turbulent flow around couplings and rod guides Potentially increase production with less flow restriction in the tubing Eliminate Care & Handling Failures and Improper Makeup Fast, Easy Installation 12/10/2018

Superior Toughness – Charpy Impact Testing Performed at 20˚C 12/10/2018

Trial Wells: Continuous Rod in Permian Basin Well #1, installed 1/30/2017 with taper design 1” and 7/8” Well #2, installed 2/3/2017 with taper design 1” and 7/8” Well #3, installed 2/7/2017 with taper design 1” and 7/8” Well #4, installed 4/11/2017 with taper design 1” and 7/8” Well #5, installed 4/13/2017 with taper design 1” and 7/8” Well #6, installed 7/21/2017 with design 7/8” 12/10/2018

Trial Wells: Previous Failures and Run Times Failures primarily due to wear: Side Loading Accelerated by corrosion issues Tubing failures Field-Wide MTBF before Continuous Rod: 180 Days 12/10/2018

Current Run Times 12/10/2018

Trial Well #1 – Cost Analysis—5400 ft Well Base rod workover cost $15,000 Rod Cost per Foot (mix) $4.38 Oil Price per Barrel $60 Oil Production Rate (BPD) 30 Lifting Cost per Barrel $10 Annual Production Decline Rate 10% Downtime per Failure (days) 21 Previous MTBF (months) 6 Failures Saved to Date 1.88 Delayed Production Revenue per Failure $30,500 Total Savings per Failure $45,500 Total Savings Less Investment to Date $86,000 ROI to Date 262 12/10/2018

Continuous Rod Installation 12/10/2018

Permian Basin Trial Parameters Operator began experimenting with a mixture of continuous rod and thermoplastic liners on very high failure frequency wells Q4 2016 Initial pilot consisted of 6 wells, with various configurations Longest running wells used conventional sucker rod with thermoplastic liners More recent installations included both thermoplastic liners and continuous rod Failure frequency on the six wells prior to trial was 2.95 failures/well/year 12/10/2018

Trial Wells Six well pilot in South Delaware Basin Asset Trial Well #1 installed 9/29/2016 with mixture of PPS and POK Trial Well #2 installed 11/17/2016 with conventional stick rod Trial Well #3 installed 12/8/2016 Trial Well #4 installed 2/14/2017 Trial Well #5 installed 3/23/2017 Trial Well #6 installed 7/13/2017 Failures primarily due to wear Side loads near 200 lbs Likely due to buckling in many instances Accelerated by mild corrosion 12/10/2018

Case Study 1 – Trial Well #2 Delaware Basin, Reeves County, Texas MTBF of ~60 days on tubing prior to installing thermoplastic liner POK liner installed from 4000ft to 10,000ft Bare tubing ran above 4000ft Run in the hole with conventional rods Currently operating 568 days without tubing failure (was down 32 days due to rod failure) 12/10/2018

Case Study 1 – Cost Analysis Base tubing workover cost $60,000 Liner Cost per Foot $5.73 Oil Price per Barrel $60 Oil Production Rate (BPD) 30 Lifting Cost per Barrel $10 Annual Production Decline Rate 10% Downtime per Failure (days) 21 Previous MTBF (months) 2 Failures Saved to Date 8.34 Delayed Production Revenue per Failure $30,400 Total Savings per Failure $90,400 Total Savings Less Investment to Date $754,000 ROI to Date 2092 12/10/2018

Case Study 1 – Cumulative Operating Profit * Annual Decline Rate = 10%, Annual Discount Rate = 7% 12/10/2018

Case Study 2 – Trial Well #1 Delaware Basin, Reeves County, Texas MTBF of 6 months on tubing prior to installing thermoplastic liner POK liner installed from surface to 6,500ft PPS liner installed from 6,500ft to 10,000ft Run in the hole with continuous rods Currently operating for 639 days (was down 10 days to replace 25 jts of tubing) 12/10/2018

Case Study 2 – Cost Analysis Base tubing workover cost $60,000 Liner Cost per Foot (blended) $7.57 Initial Continuous Rod Investment $20,000 Oil Price per Barrel $60 Oil Production Rate (BPD) 30 Lifting Cost per Barrel $10 Annual Production Decline Rate 10% Downtime per Failure (days) 21 Previous MTBF (months) 6 Failures Saved to Date 2.5 Delayed Production Revenue per Failure $30,200 Total Savings per Failure $90,200 Total Savings Less Investment to Date $212,000 ROI to Date 159 12/10/2018

Case Study 2 – Cumulative Operating Profit * Annual Decline Rate = 10%, Annual Discount Rate = 7% 12/10/2018

Case Study 2 – ROI Sensitivity All variables remain constant except run-time ROI after 30 additional days = 177 ROI after 90 additional days = 212 ROI after 180 additional days = 264 ROI after 365 additional days = 371 All variables remain constant except oil price ROI at $50/bbl = 144 ROI at $65/bbl = 166 ROI at $80/bbl = 189 12/10/2018

Trial Results to Date Early results on initial 6 well pilot indicate a decrease in failures from 2.95 failures/well/year to ~0.25 failures/well/year At this point, it is too early to tell whether continuous rod with lined tubing will be more effective than lined tubing alone, but the cost of continuous rod is comparable with conventional rod so investment is minimal Reducing failure rate by half would allow project to break even, which has already been accomplished in first 6 wells Current average run time on 6 well pilot is 522 days, which would equate to .70 failures/well/year if all 6 wells failed today Current savings of $293,000 per well and an average ROI of 487 12/10/2018

Current Field Performance Over 30 wells with LF115 lined tubing installed in the Permian and Rockies Longest runtimes have exceeded 500 days Numerous wells have extended MTBF by two to three times Over two years of run time on oldest LF170 installations 30+ continuous rod installations to date, with over 12 months run time on the oldest installation Four wells with continuous rod and lined tubing with pumps in horizontal section of wellbore 12/10/2018

Lined Tubing Field Performance Install Date Location Product Previous MTBF Current Run Time 8/29/2016 Midland County - Permian LF115 & LF170 180 Days 650+ Days 9/29/2016 Reeves County - Permian LF115 600+ Days 11/17/2016 Reeves County – Permian 90 Days 500+ Days 2/8/2017 Ward County - Permian 450+ Days 4/1/2017 Altamont, Utah 200 Days 400+ Days One Permian operator has extended decreased failure rate from 2.95 failures/well/year to 0.25 failures/well/year by using LF115 liners in combination with continuous rod. 12/10/2018

Sample ROI Calculation (5,000 ft well) 1 well 100 wells Failures Saved per Year 1.527 150 Days production saved per year 5 days 500 days Production Avg. 20 bbl/d 100 bbl 10,000 bbl Workover costs $15,000 $1,500,000 Delayed Production Revenue $4,500 $450,000 Total Savings per Failure $19,500 $1,950,000 Total Savings per Year $29,791 $2,979,100 ROI to Date 70% 12/10/2018 26

Field-wide Cost of Failures 12/10/2018

Other Ongoing Trials Continuous rod run in Reeves County, TX to a depth of 11,200 ft Continuous rod and Polyketone Thermoplastic Liner ran in two wells where pump is landed at 90˚ and 7000’ MD in Irion County, TX Polyketone liner being run in SWD wells in same basin with OXY Around 40+ wells now using Polyketone Thermoplastic Liner with operators in Permian Basin, Delaware Basin, and Uintah Basin 30+ continuous rod installations with LPS continuous rod since January, 2017 12/10/2018

Considerations to Improve ROI Investment cost for thermoplastic liner can be reduced by lining used tubulars Lost production value is more impactful for wells with high production or long lead times for workovers Continuous rod workover typically are quicker than conventional stick rod, which can reduce workover cost Combination of Coiled Rod & Thermoplastic Liners have the greatest impact on ROI For most applications, thermoplastic liner will break even before the first workover is avoided Continuous rod can have a positive ROI by increasing MTBF by as little as 30 days 12/10/2018

Questions? Zach Stearman – Artificial Lift Applications Engineer z.stearman@lpsus.net C: (405) 834-7673 L.J. Guillotte - President lguillotte@lpsus.net C: (281) 446-8024 O: (281) 799-4466 12/10/2018