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InPlay Oil Corp. Announces Its 2020 Financial, Operating and Reserves Results Highlighted by Record Reserves


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INPLAY.png
Source: InPlay Oil Corp.

CALGARY, Alberta, March 17, 2021 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and operating results for the three and twelve months ended December 31, 2020, and the results of its independent oil and gas reserves evaluation effective December 31, 2020 (the “Reserve Report”) prepared by Sproule Associates Limited (“Sproule”). InPlay’s audited annual financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2020 will be available at “www.sedar.com” and our website at “www.inplayoil.com”.

Message to Shareholders:

InPlay’s mandate of operating a prudent and adaptable junior light oil focused Company could not have been more critical than in 2020. The Company’s strong foundation of assets and our ability to react quickly to the commodity price volatility as a result of the global COVID-19 pandemic enabled InPlay to endure a year which had the most significant challenges faced by our industry in recent memory. Immediate efforts were taken to halt capital spending, implement cost reduction initiatives, defer well servicing programs, and shut in and curtail production from wells that were uneconomic at distressed prices. These efforts enabled the Company to rebound from 2020 with a solid financial footing and remain well positioned to pursue our development program within the much improved commodity price environment while maintaining our mandate to generate significant Free Adjusted Funds Flow (“FAFF”)(2) to pay down debt while also delivering measured, top-tier production growth per share amongst our light oil peers for our shareholders.

Given the improvements to West Texas Intermediate (“WTI”) prices since the announcement of our 2021 capital budget and associated guidance in January, InPlay’s 2021 adjusted funds flow (“AFF”)(2)(3) forecast has increased by over 25% to $39.0 – $42.0 million (from prior guidance of $30.5 – $33.5 million) which results in forecasted FAFF(2)(3) of $15.0 to $18.0 million (from prior guidance of $7.5 to $10.5 million). This results in a significant improvement to our forecasted 2021 year end net debt level, which is now forecasted to be $58.0 – $61.0 million (from prior guidance of $65.0 – $68.0 million). Net debt to earnings before interest, taxes and depletion (“EBITDA”)(2)(3) for 2021 is now forecast to be 1.3 – 1.5 times with the 2021 operating income profit margin(2)(3) forecast to be approximately 64%. Refer to the Outlook section for further details of our 2021 guidance.

During a period of significant hardship for the energy industry, the Company improved its liquidity position considerably during 2020. InPlay was able to secure a $25 million senior second lien four-year term loan facility (the “BDC Term Loan”) with the Business Development Bank of Canada (“BDC”) and our lending syndicate in October. This significant injection of liquidity not only allowed InPlay to re-activate its development program in the fourth quarter of 2020, but also allowed the Company to complete a strategic $1.9 million asset acquisition in our core Pembina area. As a result, the Company achieved record reserves generating significant reserve growth across all reserve categories compared to 2019: Proved Developed Producing (“PDP”) reserves increased by 11% in 2020 to 9,677 mboe, Total Proved (“TP”) reserves increased by 16% to 21,624 mboe and Total Proved and Probable (“TPP”) reserves increased by 20% to 32,816 mboe. The price forecast used to value the Company’s reserves was based on four independent reserve evaluator’s average price and foreign exchange rates forecasts as at December 31, 2020 (the “four evaluator average”). The before-tax net present value of reserves discounted at 10% (“NPV 10BT”) was $95 million on a PDP basis ($1.38 per basic share), $157 million on a TP basis ($2.30 per basic share) and $264 million ($3.86 per basic share) on a TPP basis. Current WTI strip pricing for 2021 and 2022 is approximately 34% and 13% higher, respectively, than the four evaluator average price forecasts for 2021 and 2022.

Annual average production was 3,985(1) boe/d for 2020 was a result of efforts to preserve PDP and TP reserves through a significant halt in capital spending, production curtailments and shut-in of wells. These actions enabled us to avoid selling our reserves at a loss. The Company began re-activating wells and then resumed our capital spending program as commodity prices recovered through the second half of 2020. Management of our asset base in this manner has allowed InPlay to achieve production rates in the first quarter of 2021 similar to our pre-COVID (2019) production, with the benefit of selling this 2021 production at significantly higher commodity prices than in 2020.

With the restart of our capital development program in the fourth quarter of 2020, InPlay continued to deliver on our track record of drilling efficiency and operational expertise, setting industry standard pacesetting drilling times for three horizontal wells in Willesden Green. Continued innovation in well design has resulted in capital costs on these new wells to be better than expectations with our 2020 capital program providing top tier efficiencies including finding and development (“F&D”)(4) costs of $10.29 and $12.62 in TP and TPP reserve categories respectively. The strategic $1.9 million asset acquisition provided significant reserve additions and is expected to generate considerable future value for the Company through drilling activity, all within our control given the Company’s 100% ownership of these assets. This capital and Acquisition and Disposition (A&D) activity resulted in the Company achieving finding, development and acquisition (“FD&A”)(4) costs of $9.85, $5.86 and $8.21 in the PDP, TP and TPP reserve categories respectively. This equates to recycle ratios(4) of 1.2, 2.0 and 1.4 in the respective categories.

The increase in reserves has been a remarkable achievement given the economic environment during 2020. Most importantly, the Company generated sizable increases in PDP and TP reserves which form the basis of lending valuations. Also, the strong increase in reserves without stock dilution is an accomplishment very few light oil peers have achieved and will benefit our shareholders significantly with the recent uptick in crude oil pricing.

2020 Highlights:

  • Record reserves and significant growth in an extremely challenging environment
    • PDP reserves increased 11% to 9,677 mboe (63% light and medium crude oil & NGLs)
    • TP reserves increased 16% to 21,624 mboe (67% light and medium crude oil & NGLs)
    • TPP reserves increased 20% to 32,816 mboe (68% light and medium crude oil & NGLs)
  • Successful development and A&D activity resulted in top-tier reserve replacement(4) of 2020 production
    • PDP replacement of 166% (2019 – 120%)
    • TP replacement of 309% (2019 – 84%)
    • TPP replacement of 479% (2019 – 113%)
  • Exceptional FD&A costs and associated recycle ratios (in a very low operating netback environment) in developing new reserves, in addition to strong capital efficiencies in adding new producing barrels.
    • Improved FD&A costs of $9.85/boe (PDP), $5.86/boe (TP) and $8.21/boe (TPP) compared to $11.08/boe (PDP), $9.95/boe (TP) and $9.92 (TPP) average for the last three years.
    • Strong recycle ratios of 1.2 (PDP), 2.0 (TP) and 1.4 (TPP) compared to 1.6 (PDP), 2.9 (TP) and 2.9 (TPP) in 2019.
    • Capital efficiencies(4) of $19,949 per boe/d in 2020
  • Improvements to the sustainability of the Company’s reserves
    • PDP reserve life index(4) of 6.6 years compared to 4.8 years in 2019
    • TP reserve life index of 14.8 years compared to 10.2 years in 2019
    • TPP reserve life index of 22.5 years compared to 15.0 years in 2019
  • Significantly improved the Company’s liquidity position through securing the $25 million, four-year BDC Term Loan.
  • Successfully closed a strategic acquisition in our core Pembina Cardium area for $1.9 million (net of adjustments) providing strong reserves additions and a sizeable drilling inventory to significantly contribute to the future growth of the Company.
  • $1.8 million in total grants received to date from the Alberta Site Rehabilitation Program (“ASRP”) to be directed towards reclamation and abandonment efforts.
  • Continued focus on efficiencies resulted in operating cost rates remaining flat at $14.43/boe in 2020 compared to $14.36/boe in 2019 despite the presence of fixed operating costs being incurred over a significantly lower production base and incurring costs associated with servicing wells that were shut-in or curtailed in response to COVID-19.
  • Reduced general and administrative costs by $2.0 million in comparison to 2019 as a result of cost cutting measures implemented by the Company in response to the COVID-19 pandemic.

Notes:

  1. See “Reader Advisories – Production Breakdown by Product Type”
  2. “Free adjusted funds flow”, “Adjusted Funds Flow”, “Net Debt/EBITDA” and “operating income profit margin” do not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.
  3. See table in the Reader Advisories for key budget and underlying material assumptions related to the Company’s 2021 capital program and associated guidance.
  4. “F&D”, “FD&A”, “recycle ratio”, “reserve replacement”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures.

Financial and Operating Results:

(CDN) ($000’s) Three months ended
December 31
Year ended
December 31
2020 2019 2020 2019
Financial
Oil and natural gas sales 12,829 18,425 41,934 75,025
Funds flow 3,227 7,592 6,834 30,984
Per share – basic and diluted 0.05 0.11 0.10 0.45
Per boe 8.23 16.51 4.69 16.98
Adjusted funds flow(1) 3,291 7,846 7,436 32,541
Per share – basic and diluted(1) 0.05 0.11 0.11 0.48
Per boe(1) 8.40 17.06 5.10 17.83
Comprehensive (loss) (3,227 ) (18,892 ) (112,629 ) (26,842 )
Per share – basic and diluted (0.05 ) (0.28 ) (1.65 ) (0.39 )
Exploration and development capital expenditures 10,633 4,574 23,134 32,106
Property acquisitions 1,875 14 1,610 93
Net debt (73,681 ) (55,170 ) (73,681 ) (55,170 )
Shares outstanding 68,256,616 68,256,616 68,256,616 68,256,616
Basic & diluted weighted-average shares 68,256,616 68,256,616 68,256,616 68,256,616
Operational
Daily production volumes
Light and medium crude oil (bbls/d) 2,194 2,466 2,031 2,626
Natural gas liquids (boe/d) 708 869 668 697
Conventional natural gas (Mcf/d) 8,141 9,978 7,715 10,058
Total (boe/d) 4,259 4,998 3,985 5,000
Realized prices
Light and medium crude oil & NGLs ($/bbls) 40.41 52.54 35.90 56.59
Conventional natural gas ($/Mcf) 2.72 2.51 2.29 1.74
Total ($/boe) 32.74 40.07 28.75 41.11
Operating netbacks ($/boe)(1)
Oil and natural gas sales 32.74 40.07 28.75 41.11
Royalties (1.78 ) (2.32 ) (2.00 ) (3.19 )
Transportation expense (0.80 ) (0.67 ) (0.87 ) (0.81 )
Operating costs (14.35 ) (15.38 ) (14.43 ) (14.36 )
Operating netback 15.81 21.70 11.45 22.75
Realized gain (loss) on derivative contracts (0.38 ) 0.00 (0.82 ) 0.01
Operating netback (including realized derivative contracts) 15.43 21.70 10.63 22.76
  1. “Adjusted funds flow”, “adjusted funds flow per share, basic and diluted”, “adjusted funds flow per boe”, “operating income” and “operating netback per boe” do not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. “Adjusted funds flow” adjusts for decommissioning expenditures from funds flow. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.

2020 Reserves Overview:

As a result of the Company’s efficient execution in 2020, strategic A&D activity and the high quality nature of our assets, significant reserve growth was generated in all reserve categories compared to 2019. PDP reserves increased by 11% in 2020 to 9,677 mboe, TP reserves increased by 16% to 21,624 mboe and TPP reserves increased by 20% to 32,816 mboe. This reserve based growth easily replaced our 2020 production, with 166% of production being replaced on a PDP basis, 309% on a TP basis and 479% on a TPP basis.

Despite this significant reserve growth, 2020 year-end reserve net present values of future net revenues (“NPV”) and net asset values per basic share (“NAVPS”) decreased in comparison to the prior year as a result of the significantly reduced price decks used in the Reserve Report, being an average of four external reserve evaluators at December 31, 2020. InPlay believes the four independent reserve evaluators over corrected in reducing their pricing, working towards a new mandate to be more comparable to future pricing as a result of updates to the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) with an effective date of April 1, 2021. The price forecasts are extremely conservative in our view as the WTI prices used in the Reserve Report are approximately 34% and 13% less than current strip pricing in 2021 and 2022 respectively. Despite this conservatism, the Company has provided shareholders with solid NAVPS with NPV 10BT at $95 million on a PDP basis, $157 million on a TP basis and $264 million on a TPP basis using a four independent reserve evaluators average pricing forecast and foreign exchange rates as at December 31, 2020. This equates to NAVPS of $1.02 on a PDP basis, $1.94 on a TP basis and $3.50 on a TPP basis(1).

The reduction in NPV 10BT and NAVPS from the 2019 year end Reserve Report is primarily due to substantial decreases in pricing assumptions incorporated in the Reserve Report which are summarized below.

  • WTI prices dropping 28%, 24% and 20% in years 1, 2 and 3 respectively and 19% for the remaining years.
  • Propane prices dropping 43% and 28% in years 1 and 2 respectively and 21-23% for the remaining years.
  • Butane prices dropping 41% and 30% in years 1 and 2 respectively and 16% for the remaining years.
  • AECO spot gas prices increasing 21% in year 1, decreasing 4% in year 2 and decreasing 10-13% for the remaining years.

To provide perspective on the impact of these price reductions, had pricing assumptions remained consistent with those used in the December 31, 2019 Reserve Report, NPV 10BT would have amounted to $141 million on a PDP basis, $266 million on a TP basis and $416 million on a TPP basis. These NPV 10BT values would have equated to NAVPS of $1.71 on a PDP basis, $3.53 on a TP basis and $5.73 on a TPP basis. Also, pricing changes year over year equated to reserve losses of 1,971 mboe on a TP basis and 1,692 mboe on a TPP basis based on the 2019 price deck. InPlay believes that a significant portion of these losses could be added back to future reserve results with continued gains in pricing.

Note:

  1. See “Net Asset Value” for detailed calculations.

2020 Financial & Operations Overview:

Production averaged 3,985 boe/d (68% light oil & liquids) in 2020 compared to 5,000 boe/d in 2019 (66% light oil & liquids)(1). As commodity prices began to recover during the third quarter of 2020 the Company gradually eased temporary production curtailments and shut-ins implemented as a response to the commodity price volatility due to the COVID-19 pandemic. This resulted in average production of 4,259 boe/d(1) (68% light oil & liquids) in the fourth quarter of 2020.

InPlay’s 2020 capital program consisted of $23.1 million of development capital, focused on drilling wells in our Willesden Green and Pembina Cardium areas. The Company drilled four (4.0 net) extended reach horizontal (“ERH”) wells in Willesden Green (three of which came on production in the last week of December 2020), three (3.0 net) one-mile horizontal wells in Pembina and participated in one (0.2 net) non-op Nisku ERH well during the year ended December 31, 2020, amounting to an equivalent of 11 gross horizontal miles (9.4 net horizontal miles).

InPlay delivered a year of strong operational results while successfully maneuvering through the pandemic and the commodity price challenges that faced the industry. As a result of initiatives in response to COVID-19 to reduce costs and scale back discretionary expenditures, the Company achieved lower total operating and general and administrative (“G&A”) costs during 2020 of $21.0 million and $4.5 million compared to $26.2 million and $6.5 million respectively during 2019. The Company started incurring costs associated with servicing wells that went down and despite the presence of fixed costs being incurred over a significantly lower production base, InPlay’s aggressive cost cutting campaign resulted in only a minor increase in operating expenses per boe ($14.43 in 2020 vs. $14.36 in 2019) and a reduction in G&A per boe of $3.08 in 2020 compared to $3.52 in 2019.

Note:

  1. See “Reader Advisories – Production Breakdown by Product Type”

Corporate Reserves Information:

The following summarizes certain information contained in the Reserve Report. The Reserve Report was prepared in accordance with the definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF”) which will be filed on SEDAR by the end of March 2021.

December 31, 2020 Light and Medium Conventional Oil BTAX NPV Future Development Net
Undeveloped
Reserves Category(1)(2)(3)(4)(5) Crude Oil NGLs Natural Gas Equivalent 10% Capital Wells
Mbbl Mbbl MMcf MBOE ($000’s) ($000’s) Booked
Proved developed producing 4,374.4 1,712.9 21,540 9,677.3 94,599
Proved developed non-producing 559.4 86.4 1,960 972.4 10,166 1,156
Proved undeveloped 6,562.7 1,183.8 19,364 10,973.8 52,436 168,612 82.3
Total proved 11,496.6 2,983.2 42,863 21,623.6 157,201 169,768 82.3
Probable developed producing 1,138.5 438.3 5,530 2,498.3 21,261
Probable developed non-producing 157.7 23.6 518 267.7 2,064 55
Probable undeveloped 5,426.5 710.4 13,737 8,426.5 83,165 88,694 40.5
Total probable 6,722.7 1,172.3 19,785 11,192.5 106,490 88,749 40.5
Total proved plus Probable(6) 18,219.3 4,155.6 62,647 32,816.1 263,691 258,517 122.8

Notes:

  1. Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.
  2. Based on an arithmetic average of the price forecasts of four independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd., GLJ Ltd. and Deloitte LLP) then current forecast at December 31, 2020, as outlined in the table herein entitled “Pricing Assumptions”.
  3. It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
  4. All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
  5. The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2020 reserve NPV values are also inclusive of currently enacted carbon taxes.
  6. Totals may not add due to rounding.

Net Asset Value:

December 31, 2020 BTAX NPV 5% BTAX NPV 10%
($000’s) $/share(5) ($000’s) $/share(5)
PDP NPV(1)(2) 99,950 1.46 94,599 1.38
Undeveloped acreage(3) 49,029 0.72 49,029 0.72
Net debt(4) (73,681 ) (1.08 ) (73,681 ) (1.08 )
Net Asset Value (basic) 75,298 1.10 69,947 1.02
December 31, 2020 BTAX NPV 5% BTAX NPV 10%
($000’s) $/share(5) ($000’s) $/share(5)
TP NPV(1)(2) 197,253 2.89 157,201 2.30
Undeveloped acreage(3) 49,029 0.72 49,029 0.72
Net debt(4) (73,681 ) (1.08 ) (73,681 ) (1.08 )
Net Asset Value (basic) 172,601 2.53 132,549 1.94
December 31, 2020 BTAX NPV 5% BTAX NPV 10%
($000’s) $/share(5) ($000’s) $/share(5)
TPP NPV(1)(2) 351,506 5.15 263,691 3.86
Undeveloped acreage(3) 49,029 0.72 49,029 0.72
Net debt(4) (73,681 ) (1.08 ) (73,681 ) (1.08 )
Net Asset Value (basic) 326,854 4.79 239,039 3.50

Notes:

  1. Evaluated by Sproule as at December 31, 2020. The estimated NPV does not represent fair market value of the reserves.
  2. Based on an arithmetic average of the price forecasts of four independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd., GLJ Ltd. and Deloitte LLP) then current forecast at December 31, 2020.
  3. Duvernay land holdings attributed a value of $36.6 mm ($1,200/acre) for 30,480 net acres based on internal valuations. The remaining undeveloped acreage is based on an internal valuation totaling $12.5 mm ($351/acre) for 35,452 net acres. These internal valuations are based on land sale results in the area.
  4. Net debt as at December 31, 2020.
  5. Based upon 68,256,616 common shares outstanding as at December 31, 2020

Future Development Costs (“FDCs”):

FDCs increased by $2.6 million on a Total Proved basis and $33.5 million on a Total Proved plus Probable basis.

Future Development Capital Costs (amounts in $000,000’s)
Total Proved Total Proved +
Probable
2021 23.1 30.7
2022 53.4 72.8
2023 45.9 75
2024 33.1 47.7
Remainder 14.2 32.3
Total undiscounted FDC 169.8 258.5
Total discounted FDC at 10% per year 137.4 205.8
Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”
Performance Measures:
2018 2019 2020 3 Year Avg
Average crude oil price WTI US$/bbl 64.76 57.02 39.40 53.73
E&D Capital ($000’s)(1) 20,251 30,689 22,213
Production boe/day – Full Year 4,653 5,000 3,985 4,546
Production boe/day – Q4 5,021 4,998 4,259 4,759
Operating netback $/boe – FY(2) 23.43 22.75 11.45 19.21
Proved Developed Producing
Total Reserves mboe 8,348 8,718 9,677 8,914
Reserves additions mboe 2,135 2,195 2,418 2,249
FD&A (including FDCs) $/boe(2) 9.49 13.98 9.85 11.08
FD&A (excluding FDCs) $/boe(2) 9.49 13.98 9.85 11.08
Recycle Ratio(3) 2.5 1.6 1.2 1.8
Reserves Replacement(4) 126 % 120 % 166 % 135 %
RLI (years)(5) 4.9 4.8 6.6 5.4
Total Proved
Total Reserves mboe 18,859 18,573 21,624 19,685
Reserves additions mboe 3,084 1,540 4,509 3,044
FD&A (including FDCs) $/boe(2) 16.94 7.92 5.86 9.95
FD&A (excluding FDCs) $/boe(2) 6.57 19.93 5.28 8.19
Recycle Ratio(3) 1.4 2.9 2.0 2.0
Reserves Replacement(4) 182 % 84 % 309 % 183 %
RLI (years)(5) 11.1 10.2 14.8 11.9
Proved Plus Probable
Total Reserves mboe 27,063 27,295 32,816 29,058
Reserves additions mboe 2,678 2,057 6,980 3,905
FD&A (including FDCs) $/boe(2) 15.96 7.82 8.21 9.92
FD&A (excluding FDCs) $/boe(2) 7.56 14.92 3.41 6.38
Recycle Ratio(3) 1.5 2.9 1.4 2.0
Reserves Replacement(4) 158 % 113 % 479 % 235 %
RLI (years)(5) 15.9 15.0 22.5 17.5

In 2020, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $19,949 per boe/d and a three year average of $17,702 per boe/d.(6)

Notes:

  1. Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2020 TPP = ($23.1 mm E&D – $0.9 mm capitalized G&A – $nil mm of land acquisitions + $1.6 mm net acquisition/disposition capital + $33.5 mm FDC) / (32,816 mboe – 27,295 mboe + 1,458 mboe) = $8.21 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
  2. “Operating netback per boe” does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.
  3. Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2020 TPP = ($11.45/$8.21) = 1.4. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
  4. The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2020 TPP = (32,816 mboe – 27,295 mboe + 1,458 mboe) / 1,458 mboe = 479%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
  5. RLI is calculated by dividing the reserves in each category by the 2020 average annual production. For example 2020 TPP = (32,816 mboe) / (3,985 boe/day) = 22.5 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
  6. Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate of 29% over the course of the year, calculated as follows: ($23.1 mm E&D – $0.9 mm capitalized G&A – $nil mm of land acquisitions + $1.6 mm net acquisition/disposition capital – $9.2 mm of capital not adding reserves in 2020) / (Q4/2020 production of 4,259 boe/d – Q4/2019 production of 4,998 boe/d + 2020 declined production at 29% of 1,474 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

Pricing Assumptions:

The following tables set forth the benchmark reference prices, as at December 31, 2020, reflected in the Reserve Report. These price assumptions were an arithmetic average of the price forecasts of four independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd., GLJ Ltd. and Deloitte LLP) then current forecast at the effective date of the Reserve Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1)
as of December 31, 2020
FORECAST PRICES AND COSTS

Year WTI Canadian Cromer Natural Gas NGLs NGLs Edmonton
Cushing Light Sweet LSB 35o  AECO-C Spot Edmonton  Edmonton   Pentanes Operating Cost Capital Cost Exchange
Oklahoma 40API  API ($Cdn/  Propane Butanes Plus  Inflation Rates   Inflation Rates   Rate (2) 
($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) MMBtu)  ($Cdn/Bbl)  ($Cdn/Bbl)  ($Cdn/Bbl) %/Year  %/Year  ($Cdn/$US) 
Forecast(3)
2021 46.88 55.13 54.74 2.74 18.30 25.76 57.75 0.0 % 0.0 % 0.77
2022 51.14 60.61 58.41 2.70 23.49 33.27 63.09 1.0 % 1.0 % 0.77
2023 54.83 64.68 62.91 2.65 26.11 40.49 67.58 2.0 % 2.0 % 0.77
2024 56.48 66.73 65.67 2.69 26.94 41.80 69.74 2.0 % 2.0 % 0.77
2025 57.62 68.11 67.07 2.74 27.50 42.66 71.15 2.0 % 2.0 % 0.77
2026 58.77 69.52 68.49 2.81 28.07 43.55 72.58 2.0 % 2.0 % 0.77
2027 59.94 70.95 69.93 2.86 28.64 44.44 74.04 2.0 % 2.0 % 0.77
2028 61.14 72.40 71.42 2.91 29.23 45.36 75.52 2.0 % 2.0 % 0.77
2029 62.36 73.89 72.92 2.97 29.82 46.28 77.03 2.0 % 2.0 % 0.77
2030 63.61 75.37 74.38 3.02 30.42 47.21 78.58 2.0 % 2.0 % 0.77
2031 64.88 76.88 75.87 3.09 31.02 48.16 80.16 2.0 % 2.0 % 0.77
Thereafter Escalation rate of 2.0%

Notes:

  1. This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
  2. The exchange rate used to generate the benchmark reference prices in this table.
  3. As at December 31, 2020.

Operations Update

InPlay drilled and completed three Willesden Green ERH wells during our fourth quarter 2020 drilling program that came on production late in December 2020, which were our most cost effective and efficient programs to date in Willesden Green. In the first quarter of 2021, the Company also initiated drilling a three well program on lands acquired in our Q4 2020 strategic asset acquisition, with the wells expected to be on production in the last week of March 2021, later than originally forecasted. This drilling activity and other optimization projects in the first quarter of 2021 are estimated to add an additional 10% to the PDP reserves as assigned in the December 31, 2020 Reserve Report.

Outlook

The energy industry has a renewed sense of optimism beginning in late 2020 and continuing into 2021 with world crude oil prices recovering from the COVID-19 pandemic more quickly than initially anticipated. Demand continues to increase with the rollout of vaccines throughout the world and there is less risk of significant production growth from the United States as shareholders are demanding that industry focus on providing free cash flow used to reduce debt, a return on capital employed, and providing a return to shareholders (via dividends and share buy-backs) as opposed to pursuing aggressive production growth. For these reasons, InPlay shares this sense of optimism and is very excited about the road ahead. The Company is actively drilling again and is looking forward to continuing to deliver on our track record of operational excellence.

InPlay’s planned capital program for 2021 of $23 million is unchanged from the guidance we released on January 7, 2021, which will include the planned drilling of approximately 8.0 net ERH Cardium wells in Pembina and Willesden Green and completing the 0.2 net Nisku ERH well drilled in late 2020. Forecasted production for 2021 is unchanged, with annual average production of 5,100 to 5,400 boe/d (69% light oil & liquids)(1) delivering estimated organic annual production growth of approximately 28% to 35% over 2020. As a result of improved 2021 commodity prices to date along with increases to forward commodity pricing for 2021, the AFF(2)(3) forecast for 2021 is increased over prior guidance to $39.0 to $42.0 million which results in forecasted FAFF(2)(3) of $15.0 to $18.0 million. Net debt to EBITDA(2)(3) for 2021 is now forecast to be 1.3 – 1.5 times with the 2021 operating income profit margin(2)(3) forecast to be approximately 64%, as a result of improving reduced operating costs and higher forecasted future strip commodity prices. This forecast is anticipated to result in a record year of production for the Company, matching our record 2020 year-end reserves and would generate our highest level of AFF at our current price forecast, which is below current strip pricing.

Expenditures under the Alberta Energy Regulator’s Area Based Closure (“ABC”) program are planned to be approximately 3 – 4% of our forecast AFF on decommissioning efforts throughout the year in addition to approximately $0.8 million being incurred under the ASRP.

This 2021 guidance is based on a current future commodity price curve with an annual average WTI price of US $60.50/bbl (US $60.00/bbl in H2/2021), $2.60/GJ AECO and estimated foreign exchange of $0.79 CDN/USD.

We would like to thank our employees and directors for their ongoing commitment and dedication and all of our shareholders for their continued interest and support. We look forward to announcing our operating and financial results for the first quarter of 2021 in May.

For further information please contact:

Doug Bartole Darren Dittmer
President and Chief Executive Officer Chief Financial Officer
InPlay Oil Corp. InPlay Oil Corp.
Telephone: (587) 955-0632 Telephone: (587) 955-0634

Notes:

  1. See “Reader Advisories – Production Breakdown by Product Type”
  2. “AFF”, “FAFF”, “Net Debt/EBITDA” and “operating income profit margin” are Non-IFRS Measures and do not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP Financial Measures” and “BOE equivalent” at the end of this news release and to the section entitled “Non-GAAP Measures” in our MD&A for details of calculations, rationale for use and applicable reconciliation to the nearest IFRS measure.
  3. See table in the Reader Advisories for key budget and underlying material assumptions related to the Company’s 2021 capital program and associated guidance.

Reader Advisories

Non-GAAP Financial Measures
Included in this press release are references to the terms “adjusted funds flow”, “adjusted funds flow per share, basic and diluted”, “adjusted funds flow per boe”, “free adjusted funds flow”, “operating income”, “operating netback per boe”, “operating income profit margin” and “Net Debt to EBITDA”. Management believes these measures are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil and natural gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than, “funds flow”, “profit (loss) before taxes”, “profit (loss) and comprehensive income (loss)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position.

InPlay uses “adjusted funds flow”, “adjusted funds flow per share, basic and diluted” and “adjusted funds flow per boe” as key performance indicators. Adjusted funds flow should not be considered as an alternative to or more meaningful than funds flow as determined in accordance with GAAP as an indicator of the Company’s performance. InPlay’s determination of adjusted funds flow may not be comparable to that reported by other companies. Adjusted funds flow is calculated by adjusting for decommissioning expenditures from funds flow. This item is adjusted from funds flow as decommissioning expenditures are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets, making the exclusion of this item relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. Adjusted funds flow per share, basic and diluted is calculated by the Company as adjusted funds flow divided by the weighted average number of common shares outstanding for the respective period. Management considers adjusted funds flow per share, basic and diluted an important measure to evaluate its operational performance as it demonstrates its recurring operating cash flow generated attributable to each share. Adjusted funds flow per boe is calculated by the Company as adjusted funds flow divided by production for the respective period. Management considers adjusted funds flow per boe an important measure to evaluate its operational performance as it demonstrates its recurring operating cash flow generated per unit of production. For a detailed description of InPlay’s method of calculating adjusted funds flow, adjusted funds flow per share, basic and diluted and adjusted funds flow per boe and their reconciliation to the nearest GAAP term, refer to the section “Non-GAAP Measures” in the Company’s MD&A filed on SEDAR.

InPlay uses “free adjusted funds flow” as a key performance indicator. Free adjusted funds flow should not be considered as an alternative to or more meaningful than funds flow as determined in accordance with GAAP as an indicator of the Company’s performance. Free adjusted funds flow is calculated by the Company as adjusted funds flow less capital expenditures and is a measure of the cashflow remaining after capital expenditures that can be used for additional capital activity, repayment of debt or decommissioning expenditures. Management considers free adjusted funds flow an important measure to identify the Company’s ability to improve the financial condition of the Company through debt repayment, which has become more important recently with the introduction of second lien lenders. Refer to “Forward Looking Information and Statements” section for a calculation of forecast free adjusted funds flow.

InPlay uses “operating income”, “operating netback per boe” and “operating income profit margin” as key performance indicators. Operating income should not be considered as an alternative to or more meaningful than net income as determined in accordance with GAAP as an indicator of the Company’s performance. Operating income is calculated by the Company as oil and natural gas sales less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, share-based compensation, financing and other non-cash items. Management considers operating income an important measure to evaluate its operational performance as it demonstrates its field level profitability. Operating netback per boe is calculated by the Company as operating income divided by average production for the respective period. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability per unit of production. Operating income profit margin is calculated by the Company as operating income as a percentage of oil and natural gas sales. Management considers operating income profit margin an important measure to evaluate its operational performance as it demonstrates how efficiently the Company generates field level profits from its sales revenue. For a detailed description of InPlay’s method of the calculation of operating income, operating netback per boe and operating income profit margin and their reconciliation to the nearest GAAP term, refer to the section “Non-GAAP Measures” in the Company’s MD&A filed on SEDAR.

InPlay uses “Net Debt/EBITDA” as a key performance indicator. EBITDA should not be considered as an alternative to or more meaningful than funds flow as determined in accordance with GAAP as an indicator of the Company’s performance. EBITDA is calculated by the Company as adjusted funds flow before interest expense. This measure is consistent with the EBITDA formula prescribed under the Company’s Credit Facility. Net Debt/EBITDA is calculated as Net Debt divided by EBITDA. Management considers Net Debt/EBITDA a key performance indicator as it is a key metric under our first lien and second lien credit facilities and is an important measure to identify the Company’s annual ability to fund financing expenses, net debt reductions and other obligations. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Net Debt/EBITDA.

Forward-Looking Information and Statements
This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading “Corporate Reserves Information”, the future net value of InPlay’s reserves, the future development capital and costs, the life of InPlay’s reserves and the net asset values disclosed under the heading “Net Asset Value” including the internal value ascribed to undeveloped acreage; 2021 guidance based on the planned capital program of $23 million including forecasts of 2021 annual average production levels, light oil and liquids weightings; funds flow, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin and growth rates; our estimate that our 2021 capital program is anticipated to result in a record year of production, match our 2020 year-end reserves and generate our highest level of AFF; future oil and natural gas prices; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our planned 2021 capital program; the amount and timing of capital projects; forecasted spending on decommissioning; the expectation that our wells drilled in the first quarter of 2021 will be on production in the last week of March; our expectation that the assets purchased in 2020 will generate considerable future value; and expected increases to PDP reserves in 2021 from drilling activity and other optimization projects; and methods of funding our capital program.

Forward-looking statements or information are based on a number of material factors, expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which InPlay operates; the timely receipt of any required regulatory approvals; the ability of InPlay to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which InPlay has an interest in to operate the field in a safe, efficient and effective manner; the ability of InPlay to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and the ability of InPlay to secure adequate product transportation; future commodity prices; expectations regarding the potential impact of COVID-19; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which InPlay operates; and the ability of InPlay to successfully market its oil and natural gas products.

The forward-looking information and statements included herein are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: the continuing impact of the COVID-19 pandemic; changes in our planned 2021 capital program; changes in commodity prices and other assumptions outlined herein; the potential for variation in the quality of the reservoirs in which we operate; changes in the demand for or supply of our products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of InPlay or by third party operators of our properties; increased debt levels or debt service requirements; inaccurate estimation of our light oil and natural gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in InPlay’s continuous disclosure documents filed on SEDAR including our Annual Information Form.

The internal projections, expectations or beliefs underlying the Company’s 2021 capital budget, associated guidance and corporate outlook for 2021 and beyond are subject to change in light of ongoing results, prevailing economic circumstances, commodity prices and industry conditions and regulations. InPlay’s outlook for 2021 and beyond provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions, dispositions or strategic transactions that may be completed in 2021 and beyond. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted and InPlay’s 2021 guidance and outlook may not be appropriate for other purposes.

The key budget and underlying material assumptions used by the Company in the development of its planned 2021 capital program and associated guidance including forecasted 2021 production, funds flow, adjusted funds flow, free adjusted funds flow, Net Debt, Net Debt/EBITDA ratio and operating income profit margin are as follows:

Prior Guidance Updated Guidance
FY 2021(1) FY 2021
WTI US$/bbl $49.50 $60.50
NGL Price $/boe $24.50 $27.30
AECO $/GJ $2.45 $2.60
Foreign Exchange Rate (US$/CDN$) 0.78 0.79
MSW Differential US$/bbl $4.95 $4.00
Production Boe/d 5,100 – 5,400 5,100 – 5,400
Royalties $/boe 2.90 – 3.40 3.90 – 4.50
Operating Expenses $/boe 11.50 – 13.50 11.50 – 13.50
Transportation $/boe 0.80 – 0.90 0.80 – 0.90
Interest $/boe 2.25 – 2.75 2.25 – 2.75
General and Administrative $/boe 2.60 – 3.10 2.60 – 3.10
Hedging (gain)/loss $/boe 0.80 – 1.20 3.75 – 4.25
Capital Expenditures $ millions $23 $23
Decommissioning Expenditures $ millions $1.3 – $1.5 $1.3 – $1.5
Net Debt $ millions $65.0 – $68.0 $58.0 – $61.0
Forecasted Adjusted Funds Flow $ millions $30.5 – $33.5 $39.0 – $42.0
Forecasted Funds Flow $ millions $29.0 – $32.0 $37.5 – $40.5
Prior Guidance Updated Guidance
FY 2021(1) FY 2021
Forecasted Adjusted Funds Flow $ millions $30.5 – $33.5 $39.0 – $42.0
Capital Expenditures $ millions $23 $23
Forecasted Free Adjusted Funds Flow $ millions $7.5 – $10.5 $15.0 – $18.0
Prior Guidance Updated Guidance
FY 2021(1) FY 2021
Forecasted Adjusted Funds Flow $ millions $30.5 – $33.5 $39.0 – $42.0
Interest $/boe 2.25 – 2.75 2.25 – 2.75
EBTIDA $ millions $35.5 – $38.5 $43.0 – $46.0
Net Debt $ millions $65.0 – $68.0 $58.0 – $61.0
Net Debt/EBITDA 1.7 – 1.9 1.3 – 1.5
  1. As per press release dated January 7, 2021

 

  • Forecasted production breakdown is as follows: light oil – 56%, natural gas liquids – 13%, natural gas – 31%. See “Production Breakdown by Product Type” below
  • Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above
  • Changes in working capital are not assumed to have a material impact between Dec 31, 2020 and Dec 31, 2021

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about InPlay’s prospective capital expenditures, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of InPlay and the resulting financial results will likely vary from the amounts set forth in this press release and such variation may be material. InPlay and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, InPlay undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about InPlay’s anticipated future business operations. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.

The forward-looking information and statements contained in this news release speak only as of the date hereof and InPlay does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
Our oil and gas reserves statement for the year ended December 31, 2020, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2021. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed above under the heading “Forward-Looking Information and Statements”.

This press release contains metrics commonly used in the oil and natural gas industry, such as “finding, development and acquisition costs”, “finding and development costs”, “operating netbacks”, “recycle ratios”, “reserve replacement” and “reserve life index” or “RLI”. Each of these terms are calculated by InPlay as described in the section “Performance Measures” in this press release. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.

Finding, development and acquisition (“FD&A”) and finding and development (“F&D”) costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated future development costs may not reflect total finding and development costs related to reserves additions for that year. Finding, development and acquisition costs have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Exploration & development capital means the aggregate exploration and development costs incurred in the financial year on exploration and on reserves that are categorized as development. Exploration & development capital excludes capitalized administration costs. Acquisition capital amounts to the total amount of cash and share consideration net of any working capital balances assumed with an acquisition on closing.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare InPlay’s operations over time, however such measures are not reliable indicators of InPlay’s future performance and future performance may not be comparable to the performance in prior periods. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes, however such measures are not reliable indicators on InPlay’s future performance and future performance may not be comparable to the performance in prior periods.

References to light oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“Nl 51-101“).

Test Results and Initial Production Rates
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long term performance or of ultimate recovery. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed.

Production Breakdown by Product Type
Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51-101 and their respective quantities disclosed in the table below:

Light and Medium Conventional 
Crude oil NGLS Natural gas Total
(bbls/d) (boe/d)  (Mcf/d)  (boe/d) 
Q4 2020 Average Production 2,466 869 9,978 4,998
2019 Average Production 2,626 697 10,058 5,000
Q4 2020 Average Production 2,194 708 8,141 4,259
2020 Average Production 2,031 668 7,715 3,985
2021 Annual Guidance 2,960 733 9,344 5,250

Note:

  1. With respect to forward-looking production guidance, product type breakdown is based upon management’s expectations based on reasonable assumptions but are subject to variability based on actual well results.

BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

 



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