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Inplay Oil Corp TSX: IPO-T

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

GlobeNewswire - Wed Mar 17, 6:38AM CDT

InPlay Oil Corp. (TSX:IPO.TO) (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") 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") 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 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") for 2021 is now forecast to be 1.3 - 1.5 times with the 2021 operating income profit margin 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 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") 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") costs of $9.85, $5.86 and $8.21 in the PDP, TP and TPP reserve categories respectively. This equates to recycle ratios 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:

Notes:

Financial and Operating Results:

(CDN) ($000's)                                              Three months ended              Year ended
                                                            December 31                     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                                         3,291           7,846           7,436         32,541
Per share - basic and diluted                               0.05            0.11            0.11          0.48
Per boe                                                     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)
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

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.

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.

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:

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). 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 (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:

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                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       18,219.3         4,155.6 62,647       32,816.1   263,691  258,517            122.8

Notes:

Net Asset Value:

December 31, 2020       BTAX NPV 5%            BTAX NPV 10%
                        ($000's)     $/share   ($000's)     $/share
PDP NPV                 99,950       1.46      94,599       1.38
Undeveloped acreage     49,029       0.72      49,029       0.72
Net debt                (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   ($000's)     $/share
TP NPV                  197,253      2.89      157,201      2.30
Undeveloped acreage     49,029       0.72      49,029       0.72
Net debt                (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   ($000's)     $/share
TPP NPV                 351,506      5.15      263,691      3.86
Undeveloped acreage     49,029       0.72      49,029       0.72
Net debt                (73,681 )    (1.08 )   (73,681 )    (1.08 )
Net Asset Value (basic) 326,854      4.79      239,039      3.50

Notes:

-- Evaluated by Sproule as at December 31, 2020. The estimated NPV does not represent fair market value of the reserves.

-- 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.

-- 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.

-- Net debt as at December 31, 2020.

-- 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)                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        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         9.49        13.98       9.85     11.08
FD&A (excluding FDCs) $/boe         9.49        13.98       9.85     11.08
Recycle Ratio                       2.5         1.6         1.2      1.8
Reserves Replacement                126    %    120    %    166    % 135    %
RLI (years)                         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         16.94       7.92        5.86     9.95
FD&A (excluding FDCs) $/boe         6.57        19.93       5.28     8.19
Recycle Ratio                       1.4         2.9         2.0      2.0
Reserves Replacement                182    %    84     %    309    % 183    %
RLI (years)                         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         15.96       7.82        8.21     9.92
FD&A (excluding FDCs) $/boe         7.56        14.92       3.41     6.38
Recycle Ratio                       1.5         2.9         1.4      2.0
Reserves Replacement                158    %    113    %    479    % 235    %
RLI (years)                         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.

Notes:

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

as of December 31, 2020

FORECAST PRICES AND COSTS

Year     WTI        Canadian    Cromer      Natural Gas NGLs       NGLs       Edmonton
         Cushing    Light Sweet LSB 35      AECO-C Spot Edmonton   Edmonton   Pentanes   Operating Cost Capital Cost    Exchange
         Oklahoma   40API       API         ($Cdn/      Propane    Butanes    Plus       Inflation RatesInflation Rates Rate
         ($US/Bbl)  ($Cdn/Bbl)  ($Cdn/Bbl)  MMBtu)      ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) %/Year         %/Year          ($Cdn/$US)
Forecast
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:

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) 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 forecast for 2021 is increased over prior guidance to $39.0 to $42.0 million which results in forecasted FAFF of $15.0 to $18.0 million. Net debt to EBITDA for 2021 is now forecast to be 1.3 - 1.5 times with the 2021 operating income profit margin 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:

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        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        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        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

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:

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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