InPlay Oil Corp. Announces its 2019 Financial, Operating and Reserves Results Highlighted by a 20% Increase in Adjusted Funds Flow over 2018

Inplay Oil TSX:IPO Oil & gas, Natural Gas, Energy, 油气,石油,天然气,能源
Published on: March 18, 2020

CALGARY, Alberta, March 18, 2020 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2019, and the results of its independent oil and gas reserves evaluation effective December 31, 2019 (the “Sproule 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, 2019 will be available at “www.sedar.com” and our website at “www.inplayoil.com”.

Message to Shareholders:

InPlay’s strategy has always been to operate a smart, prudent, and well run junior light oil focused Company that has the ability to provide growth through its strong technical expertise and generate top tier efficiencies in finding reserves and adding production.  This has been done while being flexible in executing our capital program and in operations where we have continually been reacting to the extremely volatile commodity price environment that our industry has endured over the last six plus years.

The Company continued to deliver exceptional operational and financial results, delivering 7% production per share growth in 2019 over 2018, achieving our annual average production guidance of 5,000 – 5,200 boe/d, notwithstanding the sale of 250 boe/d in the fourth quarter of 2018.  This average production was achieved while reducing our planned capital expenditures by 11% in the fourth quarter of 2019 which resulted in spending less than adjusted funds flow (“AFF”)(1) for 2019, adhering to our approach of being adaptable and maintaining financial flexibility.  A 10% reduction in operating costs per boe and an increased operating income profit margin(1) of 6% in 2019 over 2018 was achieved, generating a 20% increase in AFF for the year over 2018 to $32.5 million in 2019.  These results were achieved within a reduced pricing environment resulting in a corporate realized price of $41.11/boe in 2019 compared to $45.00/boe in 2018, due to lower West Texas Intermediate (“WTI”) and natural gas liquids (“NGL”) pricing in the year.

InPlay continued to leverage our proven track record of drilling efficiency and operational expertise, setting industry pacesetting drilling times for horizontal wells in our Willesden Green and Pembina core areas. Production results and costs continued to be better than our expectations. The Company is focused on project economics where we drill, complete and equip wells, and build adaptable, fit for purpose, modular infrastructure for the full development of a specific area. The results of our project based economics combined with our technical expertise and focused execution of our capital projects provided expected top tier efficiencies including finding and development costs of $13.98, $7.92 and $7.82 in proved developed producing (“PDP”), total proved (“TP”) and total proved plus probable (“TPP”) reserve categories respectively. This equates to recycle ratios of 1.6, 2.9 and 2.9 in all three respective categories and achieves capital efficiencies in adding producing barrels of $18,387 per boe/d in 2019 which matches our three year average of $18,390 per boe/d.  These are all expected to be competitive with top tier efficiencies amongst our light oil peers.   The beginning of 2020 was looking very promising for the energy industry with stability in world oil prices and several industry agencies predicting that demand would outpace supply at some point during the upcoming year. These are unprecedented times and conditions have changed quickly with concerns of demand destruction due to the COVID – 19 outbreak. In addition, a crude oil price war was initiated between certain OPEC+ members resulting in a quick and severe drop in world oil prices. InPlay’s response to these events will be to continue its approach of maintaining prudence and financial flexibility with a focus on preserving value and the balance sheet. Refer to the Outlook section for further details of our reaction and plans, to address the current economic situation.

InPlay is a nimble, focused Company that has always reacted quickly to volatility in challenging environments. The current situation we are facing is no exception. The Company will be diligent and responsive to react quickly and resume our capital program once the pricing environment improves. As we face these difficult circumstances we would especially like to thank our many dedicated shareholders, our dedicated staff and our strong and vested Board of Directors for their guidance and support.

2019 Highlights:

  • Generated AFF(1) of $32.5 million ($0.48 per basic and diluted share) during 2019, an increase of 20% compared to $27.0 million ($0.40 per basic and diluted share) in 2018.
  • InPlay has always been focused on the prudent and efficient deployment of capital.  This is evident in the exceptional finding and development costs incurred, and associated recycle ratios, in developing new reserves, and the strong capital efficiencies in adding new producing barrels.  These metrics are expected to be top tier amongst our light oil peers:  °  Finding and development (“F&D”)(2) and finding, development and acquisition (“FD&A”)(2) costs of $13.98/boe, $7.92/boe, and $7.82/boe for PDP, TP and TPP reserve categories respectively.  °  Strong recycle ratios(2) of 1.6 (PDP), 2.9 (TP) and 2.9 (TPP)  °  Generated capital efficiency(2) of $18,387 per boe/d in 2019 which substantially equals our average of $18,390 over the last three years.
  • Averaged annual 2019 production of 5,000 boe/d, an increase of 7% compared to 4,653 boe/d in 2018, achieving our annual production guidance of 5,000 – 5,200 boe/d which was increased in August 2019 due to the excellent drilling results during the year which exceeded our expectations.
  • Production growth was achieved notwithstanding the sale of approximately 250 boe/d of non-core producing assets late in 2018 and an 11% reduction to originally forecasted 2019 capital spending.
  • Continued focus on efficiencies resulted in operating cost rates decreasing 10% to $14.36/boe in 2019 compared to $16.02/boe in 2018.
  • Operating income profit margin(1) of 55% was generated in 2019 compared to 52% in 2018, an increase of 6% which was achieved even with a 9% decrease in our overall realized prices per boe received over the same respective periods.
  • Achieved PDP reserve growth of 4% and TPP reserve growth of 1% resulting in 120% and 113% replacement of production respectively.
  • Returns on the reduced capital program resulted in 15% reduction in the Company’s annual Net Debt / AFF(2) ratio of to 1.7 times for 2019 compared to 2.0 times in 2018.

Notes:

  1. “Adjusted funds flow”,”operating income profit margin” and “net debt / adjusted funds flow” 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.
  2. Refer to section “Performance Measures” for the determination of these measures’ calculations

Financial and Operating Results:

(CDN) ($000’s) Three months endedDecember 31 Year endedDecember 31
  2019 2018 2019 2018
Financial (CDN$)
Oil and natural gas sales 18,425 12,716 75,025 76,419
Funds flow 7,592 1,441 30,984 25,800
Per share – basic and diluted 0.11 0.02 0.45 0.38
Per boe 16.51 3.12 16.98 15.19
Adjusted funds flow(1) 7,846 1,721 32,541 27,040
Per share – basic and diluted(1) 0.11 0.03 0.48 0.40
Per boe(1) 17.06 3.73 17.83 15.92
Comprehensive income (loss) (18,892 ) (7,887 ) (26,842 ) (8,598 )
Per share – basic and diluted (0.28 ) (0.12 ) (0.39 ) (0.13 )
Exploration and development capital expenditures 4,574 6,954 32,106 50,206
Property acquisitions/(dispositions) 14 (17,305 ) 93 (21,470 )
Net debt (55,170 ) (53,670 ) (55,170 ) (53,670 )
Shares outstanding 68,256,616 68,256,616 68,256,616 68,256,616
Basic & diluted weighted-average shares 68,256,616 67,987,162 68,256,616 67,911,962
Operational
Daily production volumes
Light and medium crude oil (bbls/d) 2,466 2,937 2,626 2,756
Natural gas liquids (boe/d) 869 573 697 492
Natural gas (Mcf/d) 9,978 9,065 10,058 8,431
Total (boe/d) 4,998 5,021 5,000 4,653
Realized prices
Light and medium crude oil & NGLs ($/bbls) 52.54 35.09 56.59 60.49
Natural gas ($/Mcf) 2.51 1.66 1.74 1.53
Total ($/boe) 40.07 27.53 41.11 45.00
Operating netbacks ($/boe)(1)
Oil and natural gas sales 40.07 27.53 41.11 45.00
Royalties (2.32 ) (2.43 ) (3.19 ) (4.72 )
Transportation expense (0.67 ) (1.00 ) (0.81 ) (0.83 )
Operating costs (15.38 ) (15.26 ) (14.36 ) (16.02 )
Operating netback 21.70 8.84 22.75 23.43
Realized gain (loss) on derivative contracts 0.00 (0.66 ) 0.01 (2.42 )
Operating netback (including realized derivative contracts) 21.70 8.18 22.76 21.01
(1) “Adjusted funds flow”, “adjusted funds flow per share, basic and diluted”, “adjusted funds flow per boe”, “operating income”, “operating netback per boe” 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. “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.

2019 Financial & Operations Overview

InPlay delivered another year of exceptional operational results while successfully responding to commodity price challenges facing the industry. InPlay achieved organic drill bit production growth of 7% over 2018 despite an 11% reduction in originally planned capital spending to accommodate lower commodity prices than originally forecasted. The Company continues to focus on operational efficiencies which resulted in a 10% reduction to operating costs to $14.36/boe in 2019 from $16.02/boe in 2018 and a 6% increase in operating income profit margin to 55% in 2019 from 52% in 2018 (which had higher realized prices).  Prudent decision making on the timing of capital expenditures, continued drilling proficiency in our Willesden Green and Pembina core areas and a strong focus on operational efficiencies allowed InPlay to generate AFF in excess of capital spending and increased AFF by 20% to $32.5 million in 2019 from $27.0 million in 2018. This growth in the year was achieved without any share dilution and positioned the Company with a solid net debt / adjusted funds flow ratio of 1.7 for 2019 compared to 2.0 in 2018.

InPlay’s 2019 capital program consisted of $32.1 million of development capital, focused on drilling wells in our Willesden Green and Pembina Cardium areas, and was less than AFF for the year.  The Company drilled 10 (5.2 net) extended reach horizontal (“ERH”) wells and three (3.0 net) one-mile horizontal wells during the year ended December 31, 2019, amounting to an equivalent of 22 gross horizontal miles (11.8 net horizontal miles) and completed two (2.0 net) ERH wells that were drilled in the fourth quarter of 2018. Eight (4.8 net) ERH wells were drilled in Willesden Green and three (3.0 net) horizontal wells were drilled in Pembina.

The results noted above were achieved in light of negative market factors that affected Natural Gas Liquids (“NGLs”) prices during 2019.  Revenues were impacted by multi-year lows in NGL prices beginning at the start of the second quarter of 2019 which caused a 50% reduction in realized NGL prices to $19.02/boe in 2019 from $38.27/boe in 2018, following continued propane and butane price reductions. These lower NGL prices in addition to lower WTI prices resulted in a 9% reduction in total realized prices in 2019 compared to 2018.  InPlay prudently reacted to these deteriorating prices by reducing 2019 capital expenditures by 11% compared to our initial forecast in order to generate AFF that was in line with total capital expenditures.

2019 Reserve Highlights:

The strong performance of the Company’s assets, specifically in the Willesden Green and Pembina areas is highlighted by increased PDP year-end reserves by 4% to 8,718 mboe. Following are the 2019 year-end reserve highlights derived from the Sproule Report:

Reserves:

  • PDP increased 4% to 8,718 mboe (63% light crude oil & NGLs)
  • TP decreased 2% to 18,573 mboe (69% light crude oil & NGLs)
  • TPP increased 1% to 27,295 mboe (71% light crude oil & NGLs)

F&D and FD&A Costs per boe(1):

  • PDP F&D and FD&A costs were $13.98
  • TP F&D and FD&A costs were $7.92
  • TPP F&D and FD&A costs were $7.82

Recycle Ratios(1):

  • PDP was 1.6 times
  • TP was 2.9 times
  • TPP was 2.9 times

Reserve Replacement(1):

  • PDP replacement was 120%
  • TP replacement was 84%
  • TPP replacement was 113%

Sustainability(1):

  • PDP reserve life index of 4.8 years
  • TP reserve life index of 10.2 years
  • TPP reserve life index of 15.0 years

Growth was achieved in year-end reserves, however decreases in WTI, natural gas and NGL pricing combined with additional Abandonment, Decommissioning and Reclamation (“ADR”) costs recognized as a result of changes to the Canadian Oil and Gas Evaluation Handbook (“COGEH”) resulted in reductions to 2019 year-end reserve net present values (“NPV”) of future net revenues and year-end net asset values (“NAV”)(2):

NAV based on NPV before tax discounted at 10% (“NPV 10 BT”)(3):

  • PDP NAV of $116 mm equating to $1.70 per basic share
  • TP NAV of $196 mm equating to $2.87 per basic share
  • TPP NAV of $311 mm equating to $4.56 per basic share

These results were accomplished despite the following changes in Sproule’s year over year price assumptions:

  • WTI prices dropping 9%, and 7% in years 1 and 2 respectively and 6% for the remaining years.
  • Propane prices dropping 27% and 17% in years 1 and 2 respectively and 18% for the remaining years.
  • Butane prices dropping 25% and 23% in years 1 and 2 respectively and 18% for the remaining years.
  • AECO spot gas prices dropping 16% and 24% in years 1 and 2 respectively and 12% for the remaining years.
  • NPV 10 BT in all reserve categories includes approximately $4.3 million ($0.06 per share) of additional future ARO compared to 2018 as recommended in COGEH’s 2019 industry guidelines.

Notes:

  1. Refer to section “Performance Measures” for the determination of these measures’ calculations
  2. Refer to section “Net Asset Value” for the determination of these values.
  3. It should not be assumed that the net present value of estimated future net revenue (“NPV”) presented 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 crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Corporate Reserves Information:

The following summarizes certain information contained in the Sproule Report.  The Sproule Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (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 2020.

December 31, 2019   Light and Medium   Conventional Oil BTAX NPV Future Development NetUndeveloped
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 4,002.8 1,486.7 19,370 8,717.8 108,937
Proved developed non-producing 165.9 16.8 289 230.9 3,743 560
Proved undeveloped 6,082.3 1,042.8 14,998 9,624.7 76,427 166,649 81.7
Total proved 10,251.0 2,546.3 34,657 18,573.4 189,108 167,209 81.7
Probable developed producing 1,041.1 370.6 4,839 2,218.4 21,159
Probable developed non-producing 157.6 26.2 410 252.1 5,142 102
Probable undeveloped 4,235.2 621.6 8,366 6,251.2 88,880 57,723 26.6
Total probable 5,434.0 1,018.5 13,616 8,721.7 115,182 57,825 26.6
Total proved plus probable(6) 15,684.9 3,564.7 48,273 27,295.1 304,289 225,034 108.3

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 Sproule’s December 31, 2019, escalated price forecast as outlined in the table herein entitled “Pricing Assumptions”.
  3. It should not be assumed that the net present value of estimated future net revenue (“NPV”) 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 crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, 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. In 2018, the InPlay reserve report included abandonment and reclamation costs for active wells and locations only. As recommended in the October 2019 COGEH updated guidance, the Company has now also included abandonment, decommissioning and reclamation costs for all inactive assets including non-producing and suspended wells, facilities and pipelines. The impact on the Sproule Report from these additional burdens on total Proved plus Probable reserves is estimated at $4.3 million of value discounted at 10%, which will differ from the discounted values carried in our financial reporting, due to differences in abandonment activity timing and different inflation and discount values
  6. Totals may not add due to rounding.

Net Asset Value:

December 31, 2019        
  BTAX NPV 5% BTAX NPV 10%
  ($000’s) $/share(5) ($000’s) $/share(5)
PDP NPV(1)(2) 110,235 1.62 108,937 1.60
Undeveloped acreage(3) 62,155 0.91 62,155 0.91
Net debt(4) (55,170 ) (0.81 ) (55,170 ) (0.81 )
Net Asset Value (basic) 117,220 1.72 115,922 1.70

 

December 31, 2019        
  BTAX NPV 5% BTAX NPV 10%
  ($000’s) $/share(5) ($000’s) $/share(5)
TP NPV(1)(2) 226,373 3.32 189,108 2.77
Undeveloped acreage(3) 62,155 0.91 62,155 0.91
Net debt(4) (55,170 ) (0.81 ) (55,170 ) (0.81 )
Net Asset Value (basic) 233,358 3.42 196,093 2.87

 

December 31, 2019        
  BTAX NPV 5% BTAX NPV 10%
  ($000’s) $/share(5) ($000’s) $/share(5)
TPP NPV(1)(2) 385,824 5.65 304,289 4.46
Undeveloped acreage(3) 62,155 0.91 62,155 0.91
Net debt(4) (55,170 ) (0.81 ) (55,170 ) (0.81 )
Net Asset Value (basic) 392,809 5.75 311,274 4.56

Notes:

  1. Evaluated by Sproule as at December 31, 2019.  The estimated net present value of future net revenue (“NPV”) does not represent fair market value of the reserves.
  2. Based on Sproule’s forecast prices and costs as of December 31, 2019.
  3. Duvernay land holdings evaluated by independent third party firm Seaton-Jordan Partners effective December 31, 2018 attributed a value of $49.6 mm ($1,627/acre) for 30,480 net acres.  The remaining undeveloped acreage is based on an internal valuation totaling $12.6 mm ($344/acre) for 36,550 net acres.
  4. Net debt as at December 31, 2019.
  5. Based upon 68,256,616 common shares outstanding as at December 31, 2019.

Future Development Costs (“FDCs”):

FDCs decreased by $18.5 million on a Total Proved basis and $14.6 million on a Proved plus Probable basis.

Future Development Capital Costs (amounts in $000,000’s)
  Total Proved Total Proved + Probable
2020 36.6 41.2
2021 45.5 55.6
2022 43.4 55.7
2023 41.7 51.8
Remainder 50.7
Total undiscounted FDC 167.2 255.0
Total discounted FDC at 10% per year 139.1 182.8

Note: FDC as per Sproule Report based on Sproule forecast pricing as at December 31, 2019

Performance Measures:

  2017 2018 2019 3 Year Avg
Average crude oil price WTI US$/bbl 50.95 64.76 57.02 57.58
E&D Capital ($000’s)(1) 40,679 20,251 30,689
Production boe/day – Full Year 3,972 4,653 5,000 4,542
Production boe/day – Q4 4,185 5,021 4,998 4,735
Operating netback $/boe – FY(2) 21.89 23.43 22.75 22.69
Proved Developed Producing
Total Reserves mboe 7,911 8,348 8,718 8,326
Reserves additions mboe 2,057 2,135 2,195 2,129
FD&A (including FDCs)  $/boe(2) 19.77 9.49 13.98 14.34
FD&A (excluding FDCs) $/boe(2) 19.77 9.49 13.98 14.34
Recycle Ratio(3) 1.1 2.5 1.6 1.6
Reserves Replacement(4) 142 % 126 % 120 % 128 %
RLI (years)(5) 5.2 4.9 4.8 4.9
Total Proved
Total Reserves mboe 17,473 18,859 18,573 18,302
Reserves additions mboe 2,345 3,084 1,540 2,323
FD&A (including FDCs) $/boe(2) 27.88 16.94 7.92 18.63
FD&A (excluding FDCs) $/boe(2) 17.35 6.57 19.93 13.15
Recycle Ratio(3) 0.8 1.4 2.9 1.2
Reserves Replacement(4) 162 % 182 % 84 % 140 %
RLI (years)(5) 11.4 11.1 10.2 11.3
Proved Plus Probable
Total Reserves mboe 26,084 27,063 27,295 26,814
Reserves additions mboe 3,048 2,678 2,057 2,594
FD&A (including FDCs) $/boe(2) 26.17 15.96 7.82 17.81
FD&A (excluding FDCs) $/boe(2) 13.35 7.56 14.92 11.77
Recycle Ratio(3) 0.8 1.5 2.9 1.3
Reserves Replacement(4) 210 % 158 % 113 % 156 %
RLI (years)(5) 17.1 15.9 15.0 15.9

In 2019, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $18,387 per boe/d and a three year average of $18,390 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: 2019 TPP = ($32.2 mm E&D – $1.5 mm capitalized G&A – $nil mm of land acquisitions – $nil mm net acquisition/disposition capital – $14.6 mm FDC)  / (27,295 mboe – 27,063 mboe + 1,825 mboe) = $7.82 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 section.
  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: 2019 TPP = ($22.75/$7.82) = 2.9. 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 section.
  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: 2019 TPP = (27,295 mboe – 27,063 mboe + 1,825 mboe) / 1,825 mboe = 113%, 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 section.
  5. RLI is calculated by dividing the reserves in each category by the 2019 average annual production. For example 2019 TPP = (27,295 mboe) / (5,000 boe\day) = 15.0 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.
  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 34% over the course of the year, calculated as follows: ($32.2 mm E&D capital – $nil mm acquisition/disposition capital – $1.5mm capitalized G&A – $nil mm  land acquisitions) / (Q4/2019 production of 4,998 boe/d – Q4/2018 production of 5,021 boe/d + 2019 declined production at 34% of 1,692 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information section.

Pricing Assumptions:

The following tables set forth the benchmark reference prices, as at December 31, 2019, reflected in the Sproule Report. These price assumptions were provided to InPlay by Sproule and were Sproule’s then current forecast at the effective date of the Sproule Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1) as of December 31, 2019 FORECAST PRICES AND COSTS

Year WTICushingOklahoma($US/Bbl) CanadianLight Sweet 40o API($Cdn/Bbl) CromerLSB 35o API($Cdn/Bbl) Natural Gas AECO-C Spot($Cdn/MMBtu) NGLsEdmonton Propane($Cdn/Bbl) NGLs Edmonton Butanes($Cdn/Bbl) EdmontonPentanesPlus($Cdn/Bbl) Operating Cost Inflation Rates%/Year Capital Cost Inflation Rates%/Year Exchange Rate (2)($Cdn/$US)
Forecast(3)
2020 61.00 73.84 73.84 2.04 25.07 37.72 76.32 0.0% 0.0% 0.76
2021 65.00 78.51 77.51 2.27 31.84 43.90 80.52 1.0% 1.0% 0.77
2022 67.00 78.73 77.73 2.81 32.43 47.74 80.00 2.0% 2.0% 0.80
2023 68.34 80.30 79.30 2.89 33.26 48.69 81.68 2.0% 2.0% 0.80
2024 69.71 81.91 80.91 2.98 34.12 49.67 83.38 2.0% 2.0% 0.80
2025 71.10 83.54 82.54 3.06 34.99 50.66 85.13 2.0% 2.0% 0.80
2026 72.52 85.21 84.21 3.15 35.88 51.67 86.90 2.0% 2.0% 0.80
2027 73.97 86.92 85.92 3.24 36.78 52.71 88.72 2.0% 2.0% 0.80
2028 75.45 88.66 87.66 3.33 37.71 53.76 90.57 2.0% 2.0% 0.80
2029 76.96 90.43 89.43 3.42 38.65 54.84 92.45 2.0% 2.0% 0.80
2030 78.50 92.24 91.24 3.51 39.61 55.93 94.38 2.0% 2.0% 0.80
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, 2019.

Outlook:

InPlay began the 2020 capital program drilling one (1.0 net) ERH horizontal Willesden Green well and three (3.0 net) horizontal Pembina wells in the first quarter of 2020.  The Company also recompleted and commissioned a water disposal well in Pembina which is expected to provide long term savings in the area.  All wells drilled in the first quarter have been completed and placed on production albeit at lower ramp up rates than would normally occur, as a result of the current low oil price.

In January of 2020, the Company’s Board of Directors had approved a 2020 capital program of $35 million which was less than projected AFF on WTI futures pricing of $57 USD/bbl.  With the significant drop and volatility in world crude oil prices as a result of the COVID – 19 outbreak and the corresponding oil price war, consistent with past practices the Company will manage its spending and adjust the capital program accordingly throughout 2020 and no longer has plans for capital spending of $35 million. InPlay has completed its first quarter capital program and only minimal capital spending is expected over the second quarter during spring break-up. As such, no major capital spending decisions are being made at this time. Capital planning decisions for the second half of 2020 and any updated forecasts will be made in due course in consideration of forecasted AFF reflecting the prevailing commodity prices at that time.

The Company’s low decline rate, strong operating netbacks, top-tier capital efficiencies, lack of drilling commitments and primarily operated capital program provide flexibility in this volatile market. Efforts have been initiated to optimize operations in order to minimize costs and preserve value for the Company.  All operations will be thoroughly vetted to optimize corporate cash flows which may include shutting in any wells that that will not generate positive cash flow under current prices (net of fixed cost considerations).  Further operating and corporate cost efficiencies will also be pursued in consideration of the current pricing environment.

For further information please contact:

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

Reader Advisories

Non-GAAP Financial MeasuresIncluded 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”, “operating income”, “operating netback per boe” and “operating income profit margin”. 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 also 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.

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 value ascribed to undeveloped acreage; production estimates including 2020 annualized forecasts; targeted 2020 annual organic production growth; light oil and liquids weighting estimates; future oil and natural gas prices; the assumption that adjusted funds flow will equal or be less than capital expenditures; 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 2020 capital program, suspension thereof and future updates thereto the number of wells to be drilled, completed and tied-in and the timing thereof; the amount and timing of capital projects; forecasted spending on decommissioning; our belief that we will deliver top tier returns, capital efficiencies, production growth and production per share growth; the potential for long-term savings resulting from our water disposal well at Pembina; the potential of our Duvernay project and extension of our land holdings; 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 and oil price wars including planned reductions or suspension of our 2020 capital program; 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: changes in our planned 2020 capital program; changes in commodity prices; 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 oil and 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 disclosure documents.

The internal projections, expectation or beliefs underlying InPlay’s 2020 capital program and associated guidance for 2020 is subject to change based on ongoing results, prevailing economic circumstances, commodity prices and industry conditions.  InPlay’s outlook for 2020 and beyond provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions, dispositions or other strategic transactions that may be completed in 2020 or beyond.  Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted and InPlay’s guidance may not be appropriate for other purposes.

In early 2020, the Company disclosed guidance for 2020 including its forecast capital program, net wells planned to be drilled, forecast annual average production, AFF and operating income profit margin. Given the planned suspension of the capital program for the second quarter (which may be extended further), the Company has elected to withdraw this FLI as this forecast is no longer applicable given the significant declines and volatility in the spot price for oil for various reasons linked to the Coronavirus pandemic and other conditions impacting worldwide oil prices.

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 InformationOur oil and gas reserves statement for the year ended December 31, 2019, 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, 2020.  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 below 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” and “recycle ratio”, “reserve replacement” and “reserve life index or “RLI”.  Each of these terms are calculated by InPlay as described 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 and exploration costs incurred acquiring Duvernay lands with no reserves assigned  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.

Test Results and Initial Production RatesTest 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.

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.

Natural Gas Oil & Gas