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Pipestone Energy Fourth Quarter, Full Year 2020 Results

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   |    Wednesday,February 10,2021

Pipestone Energy Corp. reported its Q4 and full year 2020 results, as well as its latest proved reserve summary.

2020 Reserve Highlights:

  • Pipestone delivered 71% growth in Proved Developed Producing (“PDP”) reserves with a strong recycle ratio of 2.0 times(1). This was achieved during a very challenging year for industry cashflows and capital spending with WTI averaging ~US$39 per barrel and significant volatility in condensate differentials.
  • The Company also increased Proved plus Probable reserve volumes by 24% to 228 MMboe, while the associated FDC decreased 16% to $936 million.

Recent Operations Highlights:

  • Record Production Volumes: Q4 2020 production averaged 17,734 boe/d (31% condensate, 44% total liquids), the highest quarterly production since inception, and January 2021 production averaged approximately 20,211 boe/d (33% condensate, 46% total liquids);
  • 2020 Production Guidance Achieved: 2020 production averaged 15,570 boe/d (30% condensate and 43% total liquids) during our first full year of meaningful operations versus guidance of 15,000 – 16,000 boe/d;
  • Lower Montney Test: In January 2021, Pipestone brought on-stream a new Lower Montney well at the 3-12 pad. The 100/05-14-71-8W6 well is 10 km north of our first Lower Montney test and achieved an IP30 rate of 3.3 MMcf/d of raw natural gas and 573 bbl/d of wellhead condensate with an average CGR of 175 bbl/MMcf. This well result is very encouraging and de-risks Lower Montney drilling in the surrounding acreage. This result will be factored into our stacked bench development approach going forward;
  • Eastern Step Out Well: In December 2020, Pipestone brought on-stream the 100/03-16-71-7W6 well, previously drilled and completed in 2017, on our 14-4 pad, approximately 5 km east of our main gathering pipeline corridor. The well was drilled in the Montney ‘B’ formation with a short 1,800 metre lateral length. This well produced at an IP60 of 3.0 MMcf/d of raw natural gas and 329 bbl/d of wellhead condensate with an average CGR of 109 bbl/MMcf. These initial results are an important economic validation for our eastern acreage and additional wells from this pad are being incorporated into the development plan;(1) 2020 annual production volumes, capital expenditures and operating netbacks referenced throughout this press release are unaudited.
  • Continued Capital Efficiency Gains: The most recent three well pad at 8-15, with an average lateral length of ~3,100 metres, achieved a new pacesetter cost for drilling and completions on a per metre and per tonne placed basis.

Operations Update

Updated Pipestone Capital Program Map

Production & Facilities

During Q4 2020, production averaged 17,734 boe/d (31% condensate, 44% total liquids)(1), a quarterly record for Pipestone. During January 2021, production averaged approximately 20,211 boe/d (33% condensate, 46% total liquids)(1) based on field estimates as the six well 3-12 pad was gradually brought on production during the month. January 2021 is the first month Pipestone has exceeded the 20,000 boe/d milestone. In addition to the Lower Montney well previously mentioned at 3-12, the five new Montney B wells are producing at type curve expectations.

The wellsite facilities for the drilled and completed three well 8-15 pad is currently under construction with expected start-up prior to the end of February.

Additionally, on January 15, 2021 Pipestone commissioned its water disposal and enhanced flow-splitting facility at 3-12. This facility increases Pipestone’s fluid handling capacity while removing existing bottlenecks within the Pipestone gathering system. The facility also enhances the Company’s flexibility to direct flow between different processing facilities and will reduce operating costs.

Drilling & Completions

Pipestone continues to demonstrate cost reductions in its drilling and completions program. During Q4 2020, the Company completed six wells on its 3-12 pad for an average cost of $3.1 million (2,650 metre lateral length & 2.4 T/M proppant loading). Including the pad-site facilities, all-in DCE&T costs for this pad are $5.4 million per well.

Our most recent pad at 8-15 drilled in late 2020 had an average lateral length of 3,094 metres at a drilling cost of $2.2 million per well. The three wells were completed in January utilizing a proppant intensity of 2.5 T/M for a capital cost of $3.2 million per well. The 8-15 pad is a new pacesetter for Pipestone at a drilling cost of $378 per metre drilled ($711 per lateral meter), and a completion cost of $438 per tonne of proppant placed. Going forward, Pipestone expects to increase the average lateral length of its development wells to approximately 3,000 metres from a previous typical well length of approximately 2,500 metres.

Year-End 2020 Reserve Results

  • Proved Developed Producing (“PDP”) reserves increased by 71% from 18.5 MMboe to 31.7 MMboe and achieved a Finding & Development (“F&D”) cost of $5.40/boe, driving a 2020 PDP recycle ratio of 2.0x;
  • Total Proved (“1P”) reserves increased by 19% from 112.5 MMboe to 134.0 MMboe and total Proved + Probable (“2P”) reserves increased by 24% from 183.6 MMboe to 227.7 MMboe;
  • Decrease in 1P FDC of 19% from $790 million to $640 million, and a ~16% decrease in 2P FDC from $1,114 million to $936 million; F&D costs for these categories are not applicable because of the decrease in FDC;
  • Go-forward estimated Undeveloped 1P F&D cost (FDC / Undeveloped Reserves) of $6.33/boe ($8.95/boe at YE 2019) and Undeveloped 2P F&D cost of $5.03/boe ($7.28/boe at YE 2019) reflect the significant reductions in well costs achieved during 2020; and
  • Utilizing a 10% discount rate at a flat price deck (US$50/bbl WTI, C$2.50/GJ AECO, $0.785 CADUSD, no inflation), Pipestone estimates a Proved Developed NAVPS of $0.41 per share, a 1P NAVPS of $2.14 per share, and a 2P NAVPS of $3.66 per share.

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