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InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

InPlay Oil Corp.
InPlay Oil Corp.

CALGARY, Alberta, March 16, 2022 (GLOBE NEWSWIRE) -- InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its record setting financial and operating results for the three and twelve months ended December 31, 2021, and the results of its independent oil and gas reserves evaluation effective December 31, 2021 (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, 2021 will be available at “www.sedar.com” and our website at “www.inplayoil.com”.

2021 Highlights:

  • Completed the acquisition of Prairie Storm Resources Corp. on November 30, 2022 at attractive transaction metrics which enhances InPlay’s position as a sizable producer and acreage holder with a deep and highly economic drilling inventory in the light oil window of Central Alberta's Cardium fairway.

  • Achieved record average annual production of 5,768 boe/d(1) (65% light crude oil and NGLs), an increase of 45% from 2020 at 3,985 boe/d(1) (68% light crude oil and NGLs) and an increase of 15% compared to pre-COVID levels of 5,000 boe/d(1) (66% light crude oil and NGLs) in 2019. Annual average production per weighted average basic share increased 31% compared to 2020.

  • Generated record annual adjusted funds flow (“AFF”)(2) of $47.0 million ($0.67 per weighted average basic share(3)), an increase of 532% compared to $7.4 million ($0.11 per weighted average basic share) in 2020 and an increase of 45% compared to $32.5 million ($0.48 per weighted average basic share) in 2019, our prior record year. Excluding the impact of realized hedging losses, AFF for 2021 would have been $59.9 million.

  • Increased operating netbacks(4) by 203% to $34.63/boe from $11.45/boe in 2020 and 52% from $22.75/boe in 2019.

  • Realized annual record operating income(4) and operating income profit margin(4) of $72.9 million and 64% respectively compared to $16.7 million and 40% in 2020; $41.5 million and 55% in 2019.

  • Reduced operating expenses to an annual record $12.83/boe compared to $14.43/boe in 2020 and $14.36/boe in 2019, despite rising costs of services in the industry.

  • Generated annual free adjusted funds flow (“FAFF”)(4) of $13.6 million.

  • Lowered annual net debt(2) to earnings before interest, taxes and depletion (“EBITDA”)(4) ratio to 1.5, compared to 6.7 in 2020 and 1.6 in 2019. Fourth quarter 2021 annualized net debt to EBITDA ratio was 1.1 compared to 4.0 in 2020 and 1.6 in 2019 achieving the lowest leverage ratios in our corporate history.

  • Achieved significant growth in reserves and reserves per weighted average basic share:

    • Proved developed producing (“PDP”) reserves increased 64% (61% per weighted average basic share) to 15,890 mboe (58% light and medium crude oil & NGLs)

    • Total proved (“TP”) reserves increased 112% (106% per weighted average basic share) to 45,891 mboe (62% light and medium crude oil & NGLs)

    • Total proved plus probable (“TPP”) reserves increased 85% (81% per weighted average basic share) to 60,640 mboe (63% light and medium crude oil & NGLs)

  • Achieved record NPV BT10 reserve and net asset values (“NAV”)(6):

    • NPV BT10: $206 million (PDP), $471 million (TP) and $686 million (TPP)

    • NAV: $1.85 per weighted average basic share (PDP), $4.92 per weighted average basic share (TP) and $7.41 per weighted average basic share (TPP)

    • West Texas Intermediate (“WTI”) prices used in the Reserve Report to value the Company’s reserves are approximately 22% and 15% less than current strip pricing for 2022 (US $72.83 vs. approximately US $89.00) and 2023 (US $68.78 vs. approximately US $79.00) respectively.

  • Finding, Development and Acquisition (“FD&A”)(5) costs, associated recycle ratios and capital efficiencies which are top tier amongst light oil weighted peers.

    • FD&A(5) costs of $8.47/boe (PDP), $12.03/boe (TP) and $9.56/boe (TPP), consistent with three year averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP).

    • Recycle ratios(5) of 4.1 (PDP), 2.9 (TP) and 3.6 (TPP) compared to 1.2 (PDP), 2.0 (TP) and 1.4 (TPP) in 2020.

    • InPlay added new light oil weighted production at a capital efficiency(5) of $12,583 per boe/d.

  • Materially increased the reserve life index of our assets which in turn improves the long term sustainability of the Company:

    • PDP reserve life index(5) of 7.5 years compared to 6.6 years in 2020

    • TP reserve life index of 21.8 years compared to 14.8 years in 2020

    • TPP reserve life index of 28.8 years compared to 22.5 years in 2020

  • Successful development and A&D activity resulting in top-tier reserve replacement(5):

    • PDP replacement of 395% (2020 – 166%)

    • TP replacement of 1,253% (2020 – 309%)

    • TPP replacement of 1,422% (2020 – 479%)

  • Increased liquidity through an increased capacity within our Senior Credit Facility from $65.0 million to $85.0 million and total debt capacity of $111 million.

  • Abandonment and Reclamation Obligations spending of $2.3 million, reducing our liability by 3% through the successful abandonment of 75 wellbores and the reclamation of 22 well sites.

  • Achieved a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.

Notes:

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

  2. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.

  3. Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.

  4. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”.

  5. “FD&A”, “recycle ratio”, “reserve replacement”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures.

  6. See “Corporate Reserves Information” and “Net Asset Value” for detailed information from the Reserve Report and associated calculations.

Message to Shareholders:

The Company exited 2021 in its best operational and financial position to date. The disciplined and measured steps taken during 2020 and 2021, allowed us to implement a strategy focused on measured growth combined with generating strong free adjusted funds flow once oil prices began to recover in mid-2021. InPlay initially directed its free adjusted funds flow to debt reduction ensuring a strong and sustainable balance sheet from which to grow the Company. The strategy led to record annual AFF of $47.0 million and record annual FAFF of $13.6 million for the year while also reducing net debt, resulting in InPlay’s lowest historic leverage ratios. As the Company solidified its financial position, the strategy evolved to the point where InPlay was able to evaluate and execute upon accretive acquisition opportunities. Following up on a small but highly successful tuck-in acquisition during Q4 2020 (where InPlay grew production from 300 boe/d to 2,900 boe/d(2) in Q4 2021), InPlay closed the highly accretive corporate acquisition of Prairie Storm Resources Corp. on November 30, 2022. This acquisition enhanced the Company’s sustainability by adding low decline production, sizeable economic drilling inventory that complements InPlay’s own high internal rate of return, quick payout inventory, and increased reserve life while also adding material scale to the Company. All of these attributes enhance InPlay’s ability to grow and to continue to generate sustained long term FAFF per share(1). Immediately post closing, InPlay started drilling two wells on the Prairie Storm lands with results exceeding our expectations, confirming our technical evaluation of the assets. InPlay management is proud to be able to consistently deliver top tier reserve, production and AFF per share growth while also generating significant FAFF per share growth.

The Company’s sustainability has improved significantly with a very strong weighting of PDP reserves relative to TP and TPP reserves which now represent approximately 35% and 26% of the Company’s TP and TPP reserves respectively, with long-life reserves providing RLI’s of 7.5 years (PDP), 21.8 years (TP) and 28.8 years (TPP). InPlay’s long life reserves combined with the expected 2022 PDP base production decline rate of 23.2% (compared to 25.9% in 2021) puts the Company in a solid position to sustainably deliver long term per share growth and shareholder returns.

InPlay continued to deliver on our track record of drilling efficiency, operational expertise and accretive strategic acquisition activity, driving attractive light oil reserve addition metrics. FD&A costs per boe were $8.47, $12.03 and $9.56 in PDP, TP and TPP reserve categories respectively. These costs were consistent with InPlay’s three year FD&A averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP). The Prairie Storm acquisition provided highly accretive and economic reserve additions that are expected to generate strong production and FAFF growth. The 2021 capital program continued to convert the Company’s high quality drilling inventory into reliable cash flow capital efficiencies of $12,583 per boe/d, representing a new record for the Company.

Notes:

  1. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”.

  2. See “Production Breakdown by Product Type” at the end of this press release.

2022 Outlook Update

InPlay’s focus has been concentrated on reducing debt and improving leverage ratios. Execution of this focus is significantly ahead of schedule with the increased commodity prices. With our sound financial footing and projected liquidity capacity, InPlay is expected to be able to deliver measured production per share growth and strong free adjusted funds flow which positions the Company to execute on strategic accretive opportunities with the ultimate goal of maximizing returns to shareholders.


InPlay is forecasting 2022 to be another record year for the Company, and reiterates its previously announced January 12, 2022 average production guidance of 8,900 to 9,400 boe/d(1). With the recent sustained increase in commodity prices, we are updating our price forecast using USD $90/bbl WTI, $4.30/mcf AECO and a CAD/USD exchange rate of 0.80. Based on this revised commodity price forecast, InPlay is now expected to generate 2022 AFF of $141 to $150 million and 2022 FAFF of $83 to $92 million which would result in InPlay being in a positive working capital position, in excess of debt, by year end.

The table below outlines InPlay’s financial results of the board approved capital budget based on several WTI pricing scenarios for the remainder of 2022 (assuming an average Q1/22 WTI price of US$91.50/bbl):

2022

US$70
WTI

US$80
WTI

US$90
WTI

US$100
WTI

US$110
WTI

Production (boe/d)(1)(2)

9,150

9,150

9,150

9,150

9,150

Debt adjusted prod. per share growth (%)(3)

67%

79%

90%

102%

109%

AFF ($ millions)(4)

$121

$134

$146

$156

$162

FAFF ($ millions)(3)

$63

$76

$88

$98

$104

FAFF Yield (%)(3)(6)

24%

29%

33%

37%

40%

Year-end Working Capital / (Net Debt) ($ millions)(4)

($19)

($6)

$6

$16

$22

Annual Net Debt / EBITDA(3)

0.2

0.0

0.0

(0.1)

(0.1)

EV / DAAFF(3)(6)

2.2

1.9

1.7

1.5

1.4

Notes:

  1. See “Production Breakdown by Product Type” at the end of this press release.

  2. This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.

  3. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”.

  4. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release. .

  5. See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2022 capital program and associated guidance.

  6. Assumes a share price of $3.06.

Operations Update

InPlay’s capital program for the first quarter of 2022 was initiated in mid December 2021 due to the availability of services and the desire to take advantage of strong commodity prices, including winter natural gas prices. The two (1.6 net) wells that were drilled in December 2021 on the Prairie Storm lands were brought on production in the second half of January and are currently exceeding forecasts. The average initial production (“IP”) rates from these wells are as follows:

IP 30
(% light crude oil and NGLs)

Current
(% light crude oil and NGLs)

1.5 mile well

593 boe/d (80%)

368 boe/d (77%)

1.0 mile well

203 boe/d (83%)

165 boe/d (78%)


An additional three (3.0 net) Extended Reach Horizontal (“ERH”) wells were drilled in Pembina during January and February and were brought on production ahead of schedule in late February. These wells are in the early clean up stage and are also currently producing above forecasts. The average combined IP rates from these wells are as follows:

IP 15
(% light crude oil and NGLs)

Current
(% light crude oil and NGLs)

1,022 boe/d (79%)

1,354 boe/d (71%)


Current corporate production is approximately 9,050 boe/d(1) (62% light crude oil and NGLs), based on field estimates.

Plans for the remainder of the first quarter of 2022 consist of completing two (1.7 net) wells that were drilled on our recently acquired Prairie Storm lands. These wells are expected to be on production before the end of the first quarter. In addition, InPlay will bring on production one (0.2 net) non-operated Cardium ERH well.

Looking forward, the Company has started capital preparations for the second quarter of 2022. Due to strong commodity prices and access to our preferred service providers, the Company expects to start the second quarter drilling program early, with certain operations including lease construction already completed. It is expected that drilling operations will commence approximately six weeks ahead of schedule.

Notes:

  1. See “Production Breakdown by Product Type” at the end of this press release.

  2. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”.

Financial and Operating Results:

(CDN) ($000’s)

Three months ended
December 31

Year ended
December 31

2021

2020

2021

2020

Financial

Oil and natural gas sales

37,255

12,829

113,854

41,934

Adjusted funds flow(1)

17,149

3,291

47,028

7,436

Per share – basic(2)

0.23

0.05

0.67

0.11

Per share – diluted(2)

0.22

0.05

0.66

0.11

Per boe(2)

27.87

8.40

22.34

5.10

Comprehensive income (loss)

55,191

(3,227

)

115,071

(112,629

)

Per share – basic

0.74

(0.05

)

1.65

(1.65

)

Per share –diluted

0.71

(0.05

)

1.61

(1.65

)

Capital expenditures – PP&E and E&E

6,024

10,633

33,434

23,134

Property acquisitions (dispositions)

-

1,875

(84

)

1,610

Net Corporate acquisitions(3)(4)

38,287

-

38,287

-

Net debt(1)

(80,196

)

(73,681

)

(80,196

)

(73,681

)

Shares outstanding

86,214,751

68,256,616

86,214,751

68,256,616

Basic weighted-average shares

74,338,118

68,256,616

69,798,836

68,256,616

Diluted weighted-average shares

77,669,551

68,256,616

71,681,264

68,256,616

Operational

Daily production volumes

Light and medium crude oil (bbls/d)

3,156

2,194

2,981

2,031

Natural gas liquids (boe/d)

932

708

782

668

Conventional natural gas (Mcf/d)

15,589

8,141

12,030

7,715

Total (boe/d)

6,687

4,259

5,768

3,985

Realized prices(2)

Light and medium crude oil & NGLs ($/bbls)

79.83

40.41

70.08

35.90

Conventional natural gas ($/Mcf)

5.04

2.72

4.01

2.29

Total ($/boe)

60.56

32.74

54.08

28.75

Operating netbacks ($/boe)(4)

Oil and natural gas sales

60.56

32.74

54.08

28.75

Royalties

(7.53

)

(1.78

)

(5.51

)

(2.00

)

Transportation expense

(1.09

)

(0.80

)

(1.11

)

(0.87

)

Operating costs

(12.51

)

(14.35

)

(12.83

)

(14.43

)

Operating netback(4)

39.43

15.81

34.63

11.45

Realized (loss) on derivative contracts

(5.67

)

(0.38

)

(6.20

)

(0.82

)

Operating netback (including realized derivative contracts)(4)

33.76

15.43

28.43

10.63


(1)

Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.

(2)

Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.

(3)

This amount consists of total gross consideration of $49.9, net of $11.6 million in working capital balances assumed on closing of the Prairie Storm acquisition.

(4)

Non-GAAP financial measure or ratio that 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 and Other Financial Measures”

2021 Financial & Operations Overview:

Production averaged 5,768 boe/d (65% light crude oil & NGLs) (1) in 2021, a 45% increase compared to 3,985 boe/d (68% light crude oil & NGLs)(1) in 2020 and a 15% increase compared to 5,000 boe/d (66% light crude oil & NGLs)(1) in 2019. The four quarter sales volumes were slightly affected due to the following factors; operational downtime caused by extreme cold, third party processing facility shut downs and a larger build in period ending oil inventories of approximately 9,000 barrels.

InPlay’s 2021 capital program consisted of $33.4 million of development capital. The Company drilled eight (8.0 net) ERH wells in Pembina, and two (1.6) Willesden Green ERH wells on our newly acquired Prairie Storm assets during the year, for a total of 12 (10.0 net) wells drilled during the year. The Company also participated in one (0.2 net) Nisku ERH well and one (0.2 net) Willesden Green ERH well in 2021. This activity amounted to the drilling of an equivalent of 20.5 gross horizontal miles (15.4 net horizontal miles). This capital spending also included the construction of a multi-well battery in Pembina, which is anticipated to accommodate future development in the area over the next three years. InPlay also accelerated the start of its 2022 capital program at the end of 2021, initiating construction operations and the start of drilling activities on a three well pad in Pembina due to optimal timing and availability of services.

Efficient field operations resulted in the Company achieving record low operating costs of $12.83/boe. This result was achieved despite rising power costs throughout the year and in services in the second half of the year. The resulting operating income(2) and operating income profit margin(2) for 2021 were also annual records for the Company at $72.9 million and 64% respectively.

Note:

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

  2. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”.

2021 Reserves Overview:

As a result of the Company’s efficient execution of development capital in 2021, strategic A&D activity and the quality of our asset base, significant reserve growth was generated in all reserve categories compared to 2020. PDP reserves increased by 64% in 2021 to 15,890 mboe, TP reserves increased by 112% to 45,891 mboe and TPP reserves increased by 85% to 60,640 mboe. This reserve based growth easily replaced our 2021 production, with 395% of production being replaced on a PDP basis, 1,253% on a TP basis and 1,422% on a TPP basis.

This significant reserve growth and improvements to commodity prices resulted in strong 2021 year-end reserve net present values of future net revenues before tax (“NPV BT”) and net asset values per basic share (“NAVPS”). This resulted in reserve values of NPV BT10 of $206 million (PDP), $471 million (TP) and $686 million (TPP) using a three independent reserve evaluators average pricing forecast and foreign exchange rates as at December 31, 2021 as used in the Reserve Report. This equates to Net Asset Values of $160 million and $1.85 NAVPS (PDP), $424 million and $4.92 NAVPS (TP) and $639 million and $7.41 NAVPS (TPP)(1), representing 81% (PDP), 154% (TP) and 112% (TPP) growth for each category respectively on a per weighted average basic share basis over 2020.

Note:

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

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 2022.

December 31, 2021

Light and
Medium

Conventional

Oil

BTAX
NPV

Future
Development

Net
Undeveloped

Reserves Category(1)(2)(3)(4)(5)

Crude Oil

NGLs

Natural Gas

Equivalent

10%

Capital

Wells

Mbbl

Mbbl

MMcf

MBOE

($000's)

($000's)

Booked

Proved developed producing

6,224.8

2,972.1

40,156

15,889.6

206,481

287

-

Proved developed non-producing

595.9

254.1

3,191

1,381.9

19,464

3,617

-

Proved undeveloped

14,151.6

4,028.9

62,633

28,619.3

245,156

412,786

179.2

Total proved

20,972.4

7,255.2

105,979

45,890.7

471,100

416,690

179.2

Probable developed producing

1,467.2

713.3

9,611

3,782.3

39,024

8

-

Probable developed non-producing

153.9

74.1

867

372.6

4,298

-

-

Probable undeveloped

6,159.6

1,260.0

19,048

10,594.3

171,090

57,533

25.8

Total probable

7,780.6

2,047.5

29,526

14,749.2

214,412

57,541

25.8

Total proved plus probable(6)

28,753.0

9,302.6

135,505

60,639.9

685,513

474,232

205.0

Notes:

  1. Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.

  2. Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021, as outlined in the table herein entitled “Pricing Assumptions”.

  3. It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

  4. All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.

  5. The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2021 reserve NPV values are also inclusive of currently enacted carbon taxes.

  6. Totals may not add due to rounding.

Net Asset Value:

December 31, 2021

BTAX NPV 5%

BTAX NPV 10%

($000’s)

$/share(6)

($000’s)

$/share(6)

PDP NPV(1)(2)

226,629

2.63

206,481

2.39

Undeveloped acreage(3)

33,474

0.39

33,474

0.39

Net debt(4)(5)

(80,196

)

(0.93

)

(80,196

)

(0.93

)

Net Asset Value (basic)

179,907

2.09

159,759

1.85


December 31, 2021

BTAX NPV 5%

BTAX NPV 10%

($000’s)

$/share(6)

($000’s)

$/share(6)

TP NPV(1)(2)

608,756

7.06

471,100

5.46

Undeveloped acreage(3)

33,474

0.39

33,474

0.39

Net debt(4)(5)

(80,196

)

(0.93

)

(80,196

)

(0.93

)

Net Asset Value (basic)

562,034

6.52

424,378

4.92


December 31, 2021

BTAX NPV 5%

BTAX NPV 10%

($000’s)

$/share(6)

($000’s)

$/share(6)

TPP NPV(1)(2)

904,526

10.49

685,513

7.95

Undeveloped acreage(3)

33,474

0.39

33,474

0.39

Net debt(4)(5)

(80,196

)

(0.93

)

(80,196

)

(0.93

)

Net Asset Value (basic)

857,804

9.95

638,791

7.41

Notes:

  1. Evaluated by Sproule as at December 31, 2021. The estimated NPV does not represent fair market value of the reserves.

  2. Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021.

  3. Duvernay land holdings attributed a value of $19.9 million ($847/acre) for 23,440 net acres based on internal valuations. The remaining undeveloped acreage is based on an internal valuation totaling $13.6 million ($256/acre) for 53,159 net acres. These internal valuations are based on land sale results in the area.

  4. Net debt as at December 31, 2021.

  5. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.

  6. Based upon 86,214,751 common shares outstanding as at December 31, 2021.


Future Development Costs (“FDCs”):

FDCs increased by $246.9 million on a Total Proved basis and $215.7 million on a Total Proved plus Probable basis.

Future Development Capital Costs (amounts in $million)

Total Proved

Total Proved + Probable

2022

58.9

66.6

2023

99.2

111.7

2024

100.5

114.0

2025

95.3

110.5

Remainder

62.7

71.4

Total undiscounted FDC

416.7

474.2

Total discounted FDC at 10% per year

332.4

377.8

Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”

Performance Measures:

2019

2020

2021

3 Year Avg

Average WTI crude oil price (US$/bbl)

57.02

39.40

67.91

54.78

Capital expenditures – PP&E and E&E ($000’s)(1)

30,689

22,213

33,434

-

Production boe/d – FY(3)

5,000

3,985

5,768

4,918

Production boe/d – Q4(3)

4,998

4,259

6,687

5,315

Operating netback $/boe – FY(2)

22.75

11.45

34.63

24.32

Proved Developed Producing

Total Reserves mboe

8,718

9,677

15,890

11,428

Reserves additions mboe

2,195

2,418

8,318

12,930

FD&A (including FDCs) $/boe(1)

13.98

9.85

8.47

9.67

FD&A (excluding FDCs) $/boe(1)

13.98

9.85

8.47

9.67

Recycle Ratio(4)

1.6

1.2

4.1

2.5

Reserves Replacement(5)

120%

166%

395%

240%

RLI (years)(6)

4.8

6.6

7.5

6.4

Total Proved

Total Reserves mboe

18,573

21,624

45,891

28,696

Reserves additions mboe

1,540

4,509

26,372

32,421

FD&A (including FDCs) $/boe(1)

7.92

5.86

12.03

10.98

FD&A (excluding FDCs) $/boe(1)

19.93

5.28

2.67

3.86

Recycle Ratio(4)

2.9

2.0

2.9

2.2

Reserves Replacement(5)

84%

309%

1,253%

602%

RLI (years)(6)

10.2

14.8

21.8

16.0

Proved Plus Probable

Total Reserves mboe

27,295

32,816

60,640

40,250

Reserves additions mboe

2,057

6,980

29,929

38,965

FD&A (including FDCs) $/boe(1)

7.82

8.21

9.56

9.23

FD&A (excluding FDCs) $/boe(1)

14.92

3.41

2.36

3.21

Recycle Ratio(4)

2.9

1.4

3.6

2.6

Reserves Replacement(5)

113%

479%

1,422%

723%

RLI (years)(6)

15.0

22.5

28.8

22.4

In 2021, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $12,583 per boe/d and a three year average of $15,354 per boe/d.(7)

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: 2021 TPP = ($33.4 million E&D - $1.2 million capitalized G&A - $nil million of land acquisitions + $38.2 million net acquisition/disposition capital + $215.8 million FDC) / (60,640 mboe – 32,816 mboe + 2,105 mboe) = $9.56 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

  2. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”

  3. See “Reader Advisories - Production Breakdown by Product Type”

  4. Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2021 TPP = ($34.63/$9.56) = 3.6. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

  5. 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: 2021 TPP = (60,640 mboe – 32,816 mboe + 2,105 mboe) / 2,105 mboe = 1422%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

  6. RLI is calculated by dividing the reserves in each category by the 2021 average annual production. For example 2021 TPP = (60,640 mboe) / (5,768 boe/day) = 28.8 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

  7. Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate of 29% over the course of the year, calculated as follows: ($33.4 million E&D - $1.2 million capitalized G&A - $nil million of land acquisitions - $0.1 million net acquisition/disposition capital + $9.2 million of 2020 capital adding reserves in 2021 - $3.0 million of capital not adding reserves in 2021) / (Q4/2021 production of 6,687 boe/d – Q4/2020 production of 4,259 boe/d + 2021 declined production at 29% of 1,218 boe/d – Q4/2021 Prairie Storm production of 600 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.

Pricing Assumptions:

The following tables set forth the benchmark reference prices, as at December 31, 2021, reflected in the Reserve Report. These price assumptions were an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at the effective date of the Reserve Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1)
as of December 31, 2021
FORECAST PRICES AND COSTS

Year

WTI
Cushing
Oklahoma
($US/Bbl)

Canadian
Light Sweet
40o API
($Cdn/Bbl)

Cromer
LSB 35o
API
($Cdn/Bbl)

Natural Gas AECO-C Spot
($Cdn/
MMBtu)

NGLs
Edmonton Propane
($Cdn/Bbl)

NGLs Edmonton Butanes
($Cdn/Bbl)

Edmonton
Pentanes
Plus
($Cdn/Bbl)

Operating Cost Inflation Rates
%/Year

Capital Cost Inflation Rates
%/Year

Exchange Rate (2)
($Cdn/$US)

Forecast(3)

2022

72.83

86.82

87.30

3.56

43.38

57.49

91.85

0.0%

0.0%

0.80

2023

68.78

80.73

82.30

3.21

35.92

50.17

85.53

2.3%

2.3%

0.80

2024

66.76

78.01

79.69

3.05

34.62

48.53

82.98

2.0%

2.0%

0.80

2025

68.09

79.57

81.29

3.11

35.31

49.50

84.63

2.0%

2.0%

0.80

2026

69.45

81.16

82.92

3.17

36.02

50.49

86.33

2.0%

2.0%

0.80

2027

70.84

82.78

84.50

3.23

36.74

51.50

88.05

2.0%

2.0%

0.80

2028

72.26

84.44

86.27

3.30

37.47

52.53

89.82

2.0%

2.0%

0.80

2029

73.70

86.13

87.99

3.36

38.22

53.58

91.61

2.0%

2.0%

0.80

2030

75.18

87.85

89.75

3.43

38.99

54.65

93.44

2.0%

2.0%

0.80

2031

76.68

89.61

91.55

3.50

39.77

55.74

95.32

2.0%

2.0%

0.80

2032

78.21

91.40

93.38

3.57

40.56

56.86

97.22

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, 2021.

Environmental, Social and Governance (“ESG”) Update

InPlay’s commitment to ESG is evident through its operational track record, corporate culture and strong governance. The Company is pleased to announce that it expects to release its inaugural sustainability report this summer. InPlay looks forward to sharing the Company’s strategy and governance related to ESG and reporting ESG related metrics with shareholders.

The Company completed an active abandonment and reclamation program throughout 2021, spending $2.3 million on the abandonment of 75 wellbores and the reclamation of 22 well sites. This resulted in a reduction to our Abandonment and Reclamation obligation of 3% during 2021. Efficient field operations resulted in a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.

Included in our 2022 forecast is a commitment to materially reducing the Company’s abandonment and reclamation obligations. Approximately 30 abandonment operations and 20 reclamations are currently planned for 2022, which is estimated to result in a $3 million or 3% reduction to our ARO and a projected improvement in our Liability Management Rating (“LMR”) to 2.85.

We look forward to continuing to deliver returns to our shareholders and thank all of those that have supported InPlay since the Company’s inception. The future for InPlay and the industry are very promising and we will continue to operate the Company in a prudent, sustainable and responsible manner.

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


Reader Advisories

Non-GAAP and Other Financial Measures

Throughout this press release and other materials disclosed by the Company, InPlay uses certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under GAAP and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with GAAP as indicators of the Company performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze InPlay’s business performance against prior periods on a comparable basis.

Non-GAAP Financial Measures and Ratios

Included in this document are references to the terms “free adjusted funds flow”, “free adjusted funds flow per share”, “FAFF Yield”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net corporate acquisitions”, “Debt adjusted production per share” and “EV / DAAFF”. 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 “profit (loss) before taxes”, “profit (loss) and comprehensive income (loss)”, “adjusted funds flow”, “capital expenditures”, “corporate acquisitions, net of cash acquired”, “net debt”, “weighted average number of common shares (basic)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position.

Free Adjusted Funds Flow / FAFF per share

Management considers free adjusted funds flow and free adjusted funds flow per share important measures to identify the Company’s ability to improve its financial condition through debt repayment, which has become more important recently with the introduction of second lien lenders, on an absolute and weighted average per share basis. Free adjusted funds flow should not be considered as an alternative to or more meaningful than adjusted 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 exploration and development capital expenditures and property dispositions (acquisitions) and is a measure of the cashflow remaining after capital expenditures before corporate acquisitions that can be used for additional capital activity, corporate acquisitions, repayment of debt or decommissioning expenditures. Free adjusted funds flow per share is calculated by the Company as free adjusted funds flow divided by weighted average outstanding shares. Refer below for a calculation of free adjusted funds flow, free adjusted funds flow per share and a reconciliation of free adjusted funds flow to the nearest GAAP measure, adjusted funds flow.

(thousands of dollars)

Three Months Ended
December 31

Year Ended
December 31

2021

2020

2021

2020

Adjusted funds flow

17,149

3,291

47,028

7,436

Exploration and dev. capital expenditures

(6,024

)

(10,633

)

(33,434

)

(23,134

)

Property dispositions (acquisitions)

-

(1,875

)

84

(1,610

)

Free adjusted funds flow

11,125

(9,217

)

13,678

(17,308

)

Weighted average outstanding shares

74.3

68.3

69.8

68.3

FAFF per share

0.15

(0.14

)

0.20

(0.25

)

Free Adjusted Funds Flow Yield

InPlay uses “free adjusted funds flow yield” as a key performance indicator. Free adjusted funds flow is calculated by the Company as free adjusted funds flow divided by the market capitalization of the Company. Management considers FAFF yield to be an important performance indicator as it demonstrates a Company’s ability to generate cash to pay down debt and provide funds for potential distributions to shareholders. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast 2022 free adjusted funds flow yield.

Operating Income/Operating Netback per boe/Operating Income Profit Margin

InPlay uses “operating income”, “operating netback per boe” and “operating income profit margin” as key performance indicators. 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 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 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. Refer below for a calculation of operating income, operating netback per boe and operating income profit margin.

(thousands of dollars)

Three Months Ended
December 31

Year Ended
December 31

2021

2020

2021

2020

Revenue

37,255

12,829

113,854

41,934

Royalties

(4,632

)

(697

)

(11,595

)

(2,924

)

Operating expenses

(7,695

)

(5,622

)

(27,009

)

(21,043

)

Transportation expenses

(673

)

(314

)

(2,346

)

(1,271

)

Operating income

24,255

6,196

72,904

16,696

Sales volume (Mboe)

615.2

391.8

2,105.1

1,458.5

Per boe

Revenue

60.56

32.74

54.08

28.75

Royalties

(7.53

)

(1.78

)

(5.51

)

(2.00

)

Operating expenses

(12.51

)

(14.35

)

(12.83

)

(14.43

)

Transportation expenses

(1.09

)

(0.80

)

(1.11

)

(0.87

)

Operating netback per boe

39.43

15.81

34.63

11.45

Operating income profit margin

65

%

48

%

64

%

40

%

Net Debt to EBITDA
Management considers Net Debt to EBITDA an important measure as it is a key metric to identify the Company’s ability to fund financing expenses, net debt reductions and other obligations. 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 Senior Credit Facility. Net Debt to EBITDA is calculated as Net Debt divided by EBITDA. Refer below for a calculation of Net Debt / EBITDA.

(thousands of dollars)

Year Ended
December 31

2021

2020

Net debt

80,196

73,681

Adjusted funds flow

47,028

7,436

Interest expense (Credit Facility and other)

5,594

3,523

Interest expense (Lease liabilities)

20

47

Earnings before interest, taxes and depletion (“EBITDA”)

52,642

11,006

Net Debt to EBITDA

1.5

6.7


Net Corporate Acquisitions
Management considers Net corporate acquisitions an important measure as it is a key metric to evaluate the corporate acquisition in comparison to other transactions using the negotiated consideration value and ignoring changes to the fair value of the share consideration between the signing of the definitive agreement and the closing of the transaction. Net corporate acquisitions should not be considered as an alternative to or more meaningful than “Corporate acquisitions, net of cash acquired” as determined in accordance with GAAP as an indicator of the Company’s performance. Net corporate acquisitions is calculated as total consideration with share consideration adjusted to the value negotiated with the counterparty, less working capital balances assumed on the corporate acquisition. Refer below for a calculation of Net corporate acquisitions and reconciliation to the nearest GAAP measure, “Corporate acquisitions, net of cash acquired”.

(thousands of dollars)

Three Months Ended
December 31

Year Ended
December 31

2021

2020

2021

2020

Corporate acquisitions, net of cash acquired

29,277

-

29,277

-

Share consideration(1)

9,985

-

9,985

-

Non-cash working capital acquired

(1,156

)

-

(1,156

)

-

Derivative contracts

181

-

181

-

Net Corporate acquisitions

38,287

-

38,287

-


(1)

For purposes of the corporate acquisition, the share consideration had a negotiated value of $1.20 per share. For accounting purposes in accordance with IFRS 3, the shares issued as consideration have been valued at $2.07 per share, based on the closing price of InPlay shares on November 29, 2021.

(2)

Net working capital acquired equals the fair value of cash and cash equivalents, accounts receivable and accrued liabilities, prepaid expenses and deposits, inventory, accounts payable and accrued liabilities and derivative contracts acquired as disclosed in note 5 of the Company’s consolidated financial statements.

Production per Debt Adjusted Share

InPlay uses “Production per debt adjusted share” as a key performance indicator. Debt adjusted shares should not be considered as an alternative to or more meaningful than common shares as determined in accordance with GAAP as an indicator of the Company’s performance. Debt adjusted shares is a non-GAAP measure used in the calculation of Production per debt adjusted share and is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company's current trading price on the TSX, converting net debt to equity. Debt adjusted shares should not be considered as an alternative to or more meaningful than weighted average number of common shares (basic) as determined in accordance with GAAP as an indicator of the Company’s performance. Management considers Debt adjusted share is a key performance indicator as it adjusts for the effects of capital structure in relation to the Company’s peers. Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Management considers Production per debt adjusted share is a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Production per debt adjusted share.

EV / DAAFF
InPlay uses “enterprise value to debt adjusted AFF” or “EV/DAAFF” as a key performance indicator. EV/DAAFF is calculated by the Company as enterprise value divided by debt adjusted AFF for the relevant period. Debt adjusted AFF (“DAAFF”) is calculated by the Company as adjusted funds flow plus financing costs. Enterprise value is a capital management measures that is used in the calculation of EV/DAAFF. Enterprise value is calculated as the Company’s market capitalization plus net debt. Enterprise value is calculated as market capitalization plus net debt. Management considers enterprise value a key performance indicator as it identifies the total capital structure of the Company. Management considers EV/DAAFF a key performance indicator as it is a key metric used to evaluate the sustainability of the Company relative to other companies while incorporating the impact of differing capital structures. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast 2022 EV/DAAFF.

Capital Management Measures

Adjusted Funds Flow

Management considers adjusted funds flow to be an important measure of InPlay’s ability to generate the funds necessary to finance capital expenditures. Adjusted funds flow is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. 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 and transaction costs are non-recurring costs for the purposes of an acquisition, making the exclusion of these items relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. The Company also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit (loss) per common share.

Net Debt

Net debt is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021. The Company closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (bank debt plus accounts payable and accrued liabilities less accounts receivables and accrued receivables, prepaid expenses and deposits and inventory) as an alternative measure of outstanding debt. Management considers net debt an important measure to assist in assessing the liquidity of the Company.

Supplementary Measures

"Average realized crude oil price" is comprised of crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company's crude oil production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

"Average realized NGL price" is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company's NGL production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

"Average realized natural gas price" is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company's natural gas production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

"Average realized commodity price" is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company's production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

"Adjusted funds flow per weighted average basic share" is comprised of adjusted funds flow divided by the basic weighted average common shares.

"Adjusted funds flow per weighted average diluted share" is comprised of adjusted funds flow divided by the diluted weighted average common shares.

"Adjusted funds flow per boe" is comprised of adjusted funds flow divided by total production.

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; the Company’s planned 2022 capital program including wells to be drilled and completed and the timing of the same; 2022 guidance based on the planned capital program including forecasts of 2022 annual average production levels, debt adjusted production levels, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin, and Management’s belief that the Company can grow some or all of these attributes and specified measures; light crude oil and NGLs weighting estimates; expectations regarding future commodity prices; 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 2022 capital program; the amount and timing of capital projects; forecasted spending on decommissioning; the expectation that the reserve additions from the Prairie Storm acquisition will generate strong production and FAFF growth; the expectation that InPlay will be in a positive net cash position in the fourth quarter of 2022 using a pricing scenario of US $90 WTI and positive working capital position by 2022 year end; that 2022 will be another record year for the Company; the expectation that the Company will experience inflationary cost pressures in the second half of 2022; the expectation that costs will begin to normalize later in 2022; the Company’s planned 2022 abandonment and reclamation program, including the abandonments and reclamations to be completed, forecasted spending on these activities, reduction to our ARO and forecasted LMR rating; the expectation that the Company will start the second quarter capital program early; the planned release of InPlay’s inaugural sustainability report prior to June 30, 2022 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; that various conditions to a shareholder return strategy can be satisfied; 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 2022 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 or strategies of InPlay or by third party operators of our properties; increased debt levels or debt service requirements; inaccurate estimation of our light crude 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 2022 capital budget, associated guidance and corporate outlook for 2022 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 2022 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 2022 and beyond including, without limitation, the potential impact of any shareholder return strategy that may be implemented in the future. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted and InPlay's 2022 guidance and outlook may not be appropriate for other purposes.

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.

InPlay’s 2021 annual guidance and a comparison to 2021 actual results are outlined below.

2021 Guidance(1)

2021 Actual

Variance

Variance (%)

Production(6)

Boe/d

5,750 – 6,000

5,768

-

-

Adjusted Funds Flow(7)

$ millions

$51.0 - $54.0

$47.0

($5)(3)

(7%)

Capital Expenditures

$ millions

$32.5(2)

$33.4

$1(4)

3%

Free Adjusted Funds Flow(8)

$ millions

$17.5 - $20.5

$13.6

($4)(3)(4)

(20%)

Net Debt(6)

$ millions

$76.5 - $79.5

$80.2

$1(3)(4)(5)

1%


Notes:

  1. As previously released September 28, 2021.

  2. As previously released November 30, 2021 (previously $32.5 - $34.5 million on September 28, 2021).

  3. This variance is due to the following:

    • Lower fourth quarter sales volumes due to operational downtime caused by extreme cold, third party processing facility mechanical shut downs, a larger build in period ending oil inventories of approximately 9,000 barrels, and the later than initially expected drilling of the two well pad drilled in the fourth quarter of 2021. In addition, new production from the 2021 drilling program had a slightly higher gas weighting and lower NGL yield than forecasted.

    • The effect of shorter royalty incentive periods for recently drilled wells in the improved pricing environment and higher trucking costs on new wells.

    • Significant improvements in the Company’s share price in the later portion of 2021, resulting in additional expenses incurred from the vesting and revaluation of deferred share units, and the accelerated vesting of certain DSUs.

    • Increased hedging losses as a result of higher annual average WTI prices of US $1.06/bbl.

  4. This variance is due to the acceleration of the start of the 2022 capital program at the end of 2021 through the initiation of lease construction and starting drilling activities on a three well pad in Pembina due to optimal conditions and availability of services.

  5. This net debt variance is due to the higher positive net debt assumed on the Prairie Storm acquisition in addition to additional proceeds from the over-allotment option being exercised on the bought deal financing which both contributed to an additional $3 million positive net debt impact, net of the $4 million reduction to free adjusted funds flow.

  6. See “Reader Advisories - Production Breakdown by Product Type”

  7. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.

  8. Non-GAAP financial measure or ratio that 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 and Other Financial Measures”

The key budget and underlying material assumptions used by the Company in the development of its 2022 guidance including forecasted production, operating income, capital expenditures, adjusted funds flow, free adjusted funds flow, FAFF yield, Net Debt, Net Debt/EBITDA, EV/DAAFF, production per debt adjusted share growth are as follows:

Actuals
FY 2021

Previous Guidance
FY 2022(1)

Updated Guidance
FY 2022

WTI

US$/bbl

$67.91

$72.50

$90.00

NGL Price

$/boe

$37.79

$42.75

$52.35

AECO

$/GJ

$3.44

$3.30

$4.30

Foreign Exchange Rate

CDN$/US$

0.80

0.78

0.80

MSW Differential

US$/bbl

$3.88

$3.50

$3.00

Production

Boe/d

5,768

8,900 – 9,400

8,900 – 9,400

Royalties

$/boe

5.51

5.25 – 5.75

9.80 – 10.60

Operating Expenses

$/boe

12.83

10.00 – 13.00

10.00 – 13.00

Transportation

$/boe

1.11

0.85 – 1.10

0.85 – 1.10

Interest

$/boe

2.67

0.85 – 1.25

0.75 – 1.15

General and Administrative

$/boe

2.83

2.00 – 2.60

2.00 – 2.60

Hedging loss

$/boe

6.20

0.00 – 0.20

0.35 – 0.65

Decommissioning Expenditures

$ millions

$1.4

$2.0 - $2.5

$2.0 - $2.5

Adjusted Funds Flow

$ millions

$47.0

$111.0 - $117.0

$141 - $150

Weighted average outstanding shares

# millions

69.8

86.2

86.2

Adjusted Funds Flow per share

$/share

0.67

1.28 – 1.36

1.64 – 1.75


Actuals
FY 2021

Previous Guidance
FY 2022

Updated Guidance
FY 2022

Adjusted Funds Flow

$ millions

$47.0

$111.0 - $117.0

$141 - $150

Capital Expenditures

$ millions

$33.3

$58.0

$58.0

Free Adjusted Funds Flow

$ millions

$13.6

$53.5 - $59.5

$83 - $92

Share outstanding, end of year

# millions

86.2

86.2

Assumed Share price

$

2.18(3)

3.06

Market capitalization

$ millions

$188

$264

FAFF Yield

%

7%

N/A(5)

31% - $35%


Actuals
FY 2021

Previous Guidance
FY 2022(1)

Updated Guidance
FY 2022

Adjusted Funds Flow

$ millions

$47.0

$111.0 - $117.0

$141 - $150

Interest

$/boe

2.67

0.85 – 1.25

0.75 – 1.15

EBITDA

$ millions

$52.6

$115.0 - $120.0

$144 - $153

Net Debt/(Positive working capital, in excess of debt)

$ millions

$80.2

$22.0 - $28.0

($1) – ($10)

Net Debt/EBITDA

1.5

0.2 – 0.3

0.0 – 0.1


Actuals
FY 2021

Previous Guidance
FY 2022(1)

Updated Guidance
FY 2022

Production

Boe/d

5,768

8,900 – 9,400

8,900 – 9,400

Opening Net Debt

$ millions

$73.7

$76.5 - $79.5

$80.2

Ending Net Debt/(Pos. working capital, in excess of debt)

$ millions

$80.2

$22.0 - $28.0

($1) – ($10)

Weighted average outstanding shares

# millions

69.8

86.2

86.2

Assumed Share price

$

1.16(4)

2.18

3.06

Production per debt adjusted share growth(2)

31%

76% - 86%

85% - 95%


Actuals
FY 2021

Previous Guidance
FY 2022

Updated Guidance
FY 2022

Share outstanding, end of year

# millions

86.2

86.2

Assumed Share price

$

2.18(3)

3.06

Market capitalization

$ millions

$188

$264

Net Debt/(Positive working capital, in excess of debt)

$ millions

$80.2

($1) – ($10)

Enterprise value

$millions

$268.2

$253 - $261

Adjusted Funds Flow

$ millions

$44.1

$141 - $150

Interest

$/boe

2.67

0.75 – 1.15

Debt Adjusted AFF

$ millions

$49.7

$144 – $153

EV/DAAFF

5.4

N/A(5)

1.6 – 1.8


(1)

As previously released January 12, 2022.

(2)

Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company's current trading price on the TSX, converting net debt to equity. Share price at December 31, 2022 is assumed to be consistent with the share price at December 31, 2021.

(3)

Ending share price at December 31, 2021.

(4)

Weighted average share price throughout 2021.

(5)

Guidance had not been previously released for this measure.

  • See “Production Breakdown by Product Type” below

  • Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above

  • Changes in working capital are not assumed to have a material impact between Dec 31, 2021 and Dec 31, 2022.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
Our oil and gas reserves statement for the year ended December 31, 2021, 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, 2022. 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 crude 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
Crude oil
(bbls/d)

NGLS
(boe/d)

Conventional Natural gas
(Mcf/d)

Total
(boe/d)

Q4 2019 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

Q4 2021 Average Production

3,156

933

15,590

6,687

2021 Average Production

2,981

782

12,030

5,768

2022 Annual Guidance

4,332

1,312

21,035

9,150(1)

Tuck-in Acquisition Q4 2021 Avg. Prod

1,452

302

6,815

2,900

Current Corporate Average Production

4,019

1,455

21,464

9,050

Note:

  1. This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.

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

References to crude 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").

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.