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Research News and Market Data on IPOOF

Mar 13, 2024, 08:00 ET

CALGARY AB, March 13, 2024 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and operating results for the three and twelve months ended December 31, 2023, and the results of its independent oil and gas reserves evaluation effective December 31, 2023 (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, 2023 will be available at “www.sedarplus.ca” and our website at “www.inplayoil.com“. An updated presentation will be available soon on our website.

2023 Financial and Operations Highlights:

• Achieved average annual production of 9,025 boe/d⁽¹⁾ (58% light crude oil and NGLs) and average quarterly production of 9,596 boe/d⁽¹⁾ (59% light crude oil and NGLs) in the fourth quarter, an increase of 7% compared to 9,003 boe/d⁽¹⁾ (57% light crude oil and NGLs) in the third quarter of 2023.
• Achieved a quarterly record for light oil production of 4,142 bbl/d in the fourth quarter of 2023.
• Generated strong adjusted funds flow (“AFF”)⁽²⁾ of $91.8 million ($1.03 per basic share⁽³⁾), the second highest level ever achieved by the Company, despite WTI prices decreasing 18% and AECO natural gas prices decreasing 50% compared to 2022.
• Realized strong operating income profit margins of 58% during 2023 notwithstanding the significant benchmark commodity price decreases.
• Returned $16.5 million to shareholders through our monthly base dividend and normal course issuer bid (“NCIB”) share repurchases, representing an annual yield of 8.2% relative to year-end market capitalization. Since November 2022 InPlay has distributed $22.8 million in dividends, or $0.255 per share including dividends declared to date in 2024.
• Recorded net income of $32.7 million ($0.37 per basic share; $0.36 per diluted share). InPlay has now returned to a positive retained earnings position on the balance sheet demonstrating that the Company has generated positive earnings since inception (net of dividends paid).
• Invested $84.5 million to drill, complete and equip 12 (10.5 net) Extended Reach Horizontal (“ERH”) wells in Willesden Green, five (5.0 net) ERH wells in Pembina, one (1.0 net) multilateral Belly River well and three (0.6 net) non-operated ERH wells in Willesden Green, in addition to capital spent on two major natural gas facility upgrades to increase operated natural gas takeaway capacity for future growth.
• Exited 2023 at 0.5x net debt to earnings before interest, taxes and depletion (“EBITDA”)⁽²⁾ which is among the lower leverage ratios amongst our peers.
• Renewed our revolving Senior Credit Facility with a total lending capacity and borrowing base of $110 million, providing significant liquidity to be used for tactical capital investment and strategic acquisitions.
• Dedicated $3.3 million to the successful abandonment of 29 (23.1 net) wellbores, 114 (103.3 net) pipelines and the reclamation of 35 (29.3) wellsites.

2023 Reserve Highlights:

• An organic 2023 capital program without acquisition/disposition (“A&D”) activity resulted in:
  • Proved developed producing (“PDP”) reserves of 17,293 mboe (56% light and medium crude oil & NGLs)
  • Proved developed non-producing (“PDNP”) reserves of 1,002 mboe (76% light and medium crude oil & NGLs) are expected to move to the PDP reserve category throughout the year, with over 60% of the related wells expected to be finished and on production in the first half of 2024.
  • Total proved (“TP”) reserves of 45,919 mboe (62% light and medium crude oil & NGLs)
  • Total proved plus probable (“TPP”) reserves of 61,594 mboe (63% light and medium crude oil & NGLs)
  • On a year-over-year basis, PDP, TP and TPP reserves remained relatively unchanged.
• Reserves life index (“RLI”)⁽⁶⁾ for PDP, TP and TPP of approximately 5.2 years, 13.9 years and 18.7 years, respectively highlight a sizable drilling inventory for InPlay to sustainably develop over time.
• Delivered TPP Finding, Development and Acquisition (“FD&A”) costs (including changes in future development costs) of $23.36/boe notwithstanding $7 million in capital expenditures spent on non-recurring facility projects in 2023 to enhance our natural gas takeaway capacity. This generated a recycle ratio of 1.4x based on an operating netback of $31.61/boe.
• Achieved healthy NPV BT10 reserve values⁽⁵⁾:
  • NPV BT10:
    • PDP: $242 million
    • PDP+PDNP: $261 million
    • TP: $571 million
    • TPP: $824 million

Message to Shareholders:

InPlay had another year of solid operational and financial performance in 2023 while continuing to deliver strong returns to shareholders and maintaining a solid balance sheet. The continued development of our drilling inventory has yielded consistent and sustainable results, with our team constantly evaluating options to provide further shareholder returns.

Average 2023 production of 9,025 boe/d⁽¹⁾ generated AFF of $91.8 million ($1.03 per share). InPlay returned $16.5 million to shareholders through our monthly base dividend and normal course issuer bid (“NCIB”) share repurchases. The Company maintained its balance sheet strength with a net debt to EBITDA ratio of 0.5x and total debt capacity of $110 million, allowing the financial flexibility to take advantage of strategic opportunities and weather periods of market volatility.

InPlay achieved strong before tax estimated net present values (“NPV”) of future net revenues associated with our 2023 year-end reserves and discounted at 10% (“NPV BT10”) although impacted by weaker future commodity prices in comparison to December 31, 2022. Forecasted WTI and AECO prices used in the Reserve Report decreased by 8% and 48% in year one and 4% and 23% in year two respectively. The Company achieved NPV BT10 reserve values of $242 million (PDP), $571 million (TP) and $824 million (TPP) based on a three independent reserve evaluator average pricing, cost forecast and foreign exchange rates as at December 31, 2023 as used in the Reserve Report.

InPlay remains focused on disciplined development of our high rate of return assets with a focus on maximizing free adjusted funds flow alongside a reasonable production growth profile while maintaining conservative leverage ratios, with the ultimate goal of maximizing returns to shareholders. The Company will remain disciplined and flexible and can quickly adjust capital activity to respond to changing market conditions.

Outlook and Operations Update:

InPlay’s capital program for the first quarter of 2024 started with a two (1.9 net) ERH well pad in Willesden Green which came on production at the end of February and is in the early stages of cleanup. Drilling of three (3.0 net) Pembina Cardium ERH wells has been completed with completion operations currently underway. These wells are expected to come on production by the end of March and offset five successful wells drilled in 2023 characterized by low decline rates and high light oil and liquids weightings. An additional two (0.3 net) non-operated Willesden Green ERH wells have recently been drilled, are being completed, and are expected to come online in mid-March with another one (0.35 net) non-operated Willesden Green ERH well drilled in March and expected to be on production in the second quarter.

The Company’s first (1.0 net) multilateral Belly River horizontal well was brought on production in December. The well has been on production with no decline and is meeting internal expectations with initial production (“IP”) rates of 84 boe/d (96% light crude oil and liquids) and 89 boe/d (97% light crude oil and liquids) over its first 30 and 60 days respectively. The Belly River is characterized by high quality sweet light oil that receives premium pricing to our realized benchmark MSW commodity price.  We are encouraged by the results that we are seeing from this well and will continue to evaluate expanding the use of this technology on further potential areas in our Belly River play.

WTI prices remained volatile early in 2024 but have improved throughout the quarter to approximately US $78/bbl, exceeding the US $75/bbl assumption utilized in our previously released 2024 budget. Future differentials to WTI, including MSW , are forecasted to significantly improve by 55% – 60% throughout the balance of the year compared to the fourth quarter of 2023 and first quarter of 2024 as new pipeline capacity comes online in the second quarter. The relatively weak Canadian dollar is supportive of the Canadian crude oil price environment and is expected to continue throughout the year. Natural gas prices have been challenged with warmer than average temperatures impacting winter demand resulting in weak AECO prices forecasted through to the end of the summer. InPlay has implemented crude oil and natural gas hedges at favorable pricing levels to mitigate risk and add stability during periods of market volatility.

As previously announced, InPlay’s Board of Directors approved a 2024 capital budget of $64 – $67 million which is forecast to result in annual average production of 9,000 – 9,500 boe/d⁽¹⁾ (59% – 61% light crude oil and NGLs).  InPlay has taken a measured and disciplined approach to capital allocation for 2024 with a program focused on high return oil weighted locations driving annual oil production growth at the midpoint of guidance of approximately 7% over 2023 despite a 20% to 25% reduction in capital spending year over year. The capital program is designed to responsibly manage the pace of development, maintain operational and financial flexibility and remain focused on delivering return of capital to shareholders. The Company achieved record quarterly light oil production of 4,142 bbl/d and increased our light oil and NGLs weighting to 59% in the fourth quarter of 2023. This higher weighting of light oil and NGLs is expected to continue in 2024 as a result of our oil focused drilling program, allowing the Company to take advantage of the strong oil price environment which is the Company’s main revenue and AFF driver.

Financial and Operating Results:

(CDN) ($000’s)	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Financial
Oil and natural gas sales	47,631	58,161	179,366	238,590
Adjusted funds flow(3)	23,544	30,271	91,784	130,805
Per share – basic(4)	0.26	0.35	1.03	1.51
Per share – diluted(4)	0.26	0.33	1.01	1.44
Per boe(4)	26.67	34.19	27.86	39.36
Comprehensive income	11,576	20,736	32,702	83,896
Per share – basic	0.13	0.24	0.37	0.97
Per share – diluted	0.13	0.23	0.36	0.92
Capital expenditures – PP&E and E&E	14,632	13,647	84,466	77,603
Property acquisitions (dispositions)	–	–	327	(2)
Net Corporate acquisitions(2)	–	(321)	–	180
Net debt(3)	45,679	32,963	45,679	32,963
Shares outstanding	90,307,765	86,952,601	90,307,765	86,952,601
Basic weighted-average shares	90,257,367	87,106,339	89,072,110	86,895,314
Diluted weighted-average shares	91,749,661	91,229,513	90,615,976	91,137,173
(CDN) ($000’s)	Three months ended December 31		Year ended December 31
	2023	2022	2023	2022
Operational
Daily production volumes
Light and medium crude oil (bbls/d)	4,142	3,909	3,822	3,766
Natural gas liquids (boe/d)	1,520	1,532	1,396	1,402
Conventional natural gas (Mcf/d)	23,606	25,090	22,839	23,623
Total (boe/d)	9,596	9,623	9,025	9,105
Realized prices(4)
Light and medium crude oil & NGLs ($/bbls)	80.83	90.21	81.74	100.26
Conventional natural gas ($/Mcf)	2.55	5.63	2.84	5.74
Total ($/boe)	53.95	65.69	54.45	71.79
Operating netbacks ($/boe)(2)
Oil and natural gas sales	53.95	65.69	54.45	71.79
Royalties	(7.18)	(11.72)	(6.84)	(11.55)
Transportation expense	(1.06)	(1.26)	(0.95)	(1.18)
Operating costs	(14.99)	(14.78)	(15.05)	(13.16)
Operating netback(2)	30.72	37.93	31.61	45.90
Realized gain (loss) on derivative contracts	0.66	0.17	1.10	(1.97)
Operating netback (including realized derivative contracts)(2)	31.38	38.10	32.71	43.93

2023 Financial & Operations Overview:

Production averaged 9,025 boe/d⁽¹⁾ (58% light crude oil & NGLs) in 2023 compared to 9,105 boe/d⁽¹⁾ (57% light crude oil & NGLs) in 2022. Production averaged 9,596 boe/d⁽¹⁾ (59% light crude oil & NGLs) in the fourth quarter of 2023, a 7% increase in comparison to the third quarter of 2023. Production for 2023 was impacted by approximately 650 boe/d over the year due to extraordinary curtailments experienced from third party capacity constraints and turnarounds, Alberta wildfires, and delays in starting up our natural gas facility in the third quarter as discussed in our prior press releases.

In 2023, commodity prices decreased over 2022 levels. WTI oil prices decreased 18% predominantly as a result of increased supply and sentiment on future demand. Natural gas prices weakened due to production growth in North America with higher than normal inventory levels in North America and Europe, resulting in a 50% decrease in AECO pricing compared to 2022. These lower commodity prices resulted in a 24% decline in our realized sales price driving a decrease to AFF and netbacks compared to 2022, which was partially offset by realized hedging gains.

InPlay’s capital program for 2023 consisted of $84.5 million of development capital. The Company drilled, completed and brought on production 12 (10.5 net) Extended Reach Horizontal (“ERH”) wells in Willesden Green, five (5.0 net) ERH wells in Pembina, one (1.0 net) multilateral Belly River well and three (0.6 net) non-operated ERH well in Willesden Green. This activity amounted to the drilling of 21 gross (17.1 net) wells. Capital activity in 2023 was also focused on expanding and upgrading our natural gas facility infrastructure to accommodate future growth. InPlay completed two major facility upgrades in 2023 to increase operated natural gas takeaway capacity and to mitigate potential production issues arising from third party outages and capacity constraints. These projects have already shown value by reducing back pressure on wells and lowering declines while improving our liquids weighting with higher natural gas liquids recovery. After the completion of these projects, more consistent run times and the transportation of associated natural gas to our lower cost operated facilities has resulted in operating costs trending downward in the last quarter of 2023 which is expected to continue into 2024.

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” contained within this press release and in our most recently filed MD&A.
3.	Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
4.	Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
5.	See “Corporate Reserves Information” for detailed information from the Reserve Report and associated NPV calculations.
6.	“FD&A”, “recycle ratio”,  “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.
7.	Based on a current share price of $2.30.

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 2024.

Net Present Values of Reserves:

December 31, 2023	BTAX NPV 5%	BTAX NPV 10%
	($000’s)	($000’s)
PDP NPV(1)(2)	271,987	242,298
TP NPV(1)(2)	744,150	571,097
TPP NPV(1)(2)	1,098,195	823,589
Notes:
1.	Evaluated by Sproule as at December 31, 2023.  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, 2023.

Future Development Costs (“FDCs”):

The following FDCs are included in the 2023 Reserve Report:

($millions)			TP	TPP
2024			55.9	55.9
2025			97.5	106.6
2026			91.8	112.2
2027			105.6	115.2
Remainder			79.8	118.6
Total undiscounted FDC			430.7	508.5
Total discounted FDC at 10% per year			338.6	394.6
Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”

The $509 million of total FDC in the Reserve Report generates approximately $521 million in future net present value discounted at 10%.

Performance Measures:

	2021	2022	2023	3 Year Avg
Average WTI crude oil price (US$/bbl)	67.91	94.23	77.62	79.92
FD&A Costs(1)	70,486	76,081	83,085	76,551
Production boe/d – FY(3)	5,768	9,105	9,025	7,966
Operating netback $/boe – FY(2)	34.63	45.90	31.61	37.78
Proved Developed Producing
Total Reserves mboe	15,890	17,653	17,293	16,945
Reserves additions mboe	8,318	5,086	2,935	5,446
FD&A (including FDCs)  $/boe(1)	8.47	14.96	28.31	14.06
FD&A (excluding FDCs) $/boe(1)	8.47	14.96	28.31	14.06
Recycle Ratio(4)	4.1	3.1	1.1	2.7
RLI (years)(5)	7.5	5.3	5.2	5.8
Total Proved
Total Reserves mboe	45,891	46,464	45,919	46,091
Reserves additions mboe	26,372	3,897	2,748	11,006
FD&A (including FDCs) $/boe(1)	12.03	24.04	28.92	14.86
FD&A (excluding FDCs) $/boe(1)	2.67	19.52	30.23	6.96
Recycle Ratio(4)	2.9	1.9	1.1	2.5
RLI (years)(5)	21.8	14.0	13.9	15.9
Proved Plus Probable
Total Reserves mboe	60,640	61,842	61,594	61,359
Reserves additions mboe	29,929	4,525	3,047	12,500
FD&A (including FDCs) $/boe(1)	9.56	27.02	23.36	12.79
FD&A (excluding FDCs) $/boe(1)	2.36	16.81	27.27	6.12
Recycle Ratio(4)	3.6	1.7	1.4	3.0
RLI (years)(5)	28.8	18.6	18.7	21.1
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: 2023 TPP = ($84.5 million capital expenditures – PP&E and E&E – $1.7 million capitalized G&A – $nil of land acquisitions + $0.3 property acquisitions – $11.9 million change in FDCs) / (61,594 mboe – 61,842 mboe + 3,294 mboe) = $23.36 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” contained within this press release and our most recently filed MD&A.
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: 2023 TPP = ($31.61/$23.36) = 1.4. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
5.	RLI is calculated by dividing the reserves in each category by the 2023 average annual production. For example 2023 TPP = (61,594 mboe) / (9,025 boe/d) = 18.7 years. 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, 2023, reflected in the Reserve Report. These price and cost 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 and Sproule’s foreign exchange rate forecast at the effective date of the Reserve Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS ⁽¹⁾
as of December 31, 2023
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)
2024	73.67	92.91	93.57	2.20	29.65	47.69	96.79	0.0 %	0.0 %	0.75
2025	74.98	95.04	95.86	3.37	35.13	48.83	98.75	2.0 %	2.0 %	0.75
2026	76.14	96.07	96.46	4.05	35.43	49.36	100.71	2.0 %	2.0 %	0.76
2027	77.66	97.99	98.39	4.13	36.14	50.35	102.72	2.0 %	2.0 %	0.76
2028	79.22	99.95	100.36	4.21	36.86	51.35	104.78	2.0 %	2.0 %	0.76
2029	80.80	101.94	102.36	4.30	37.60	52.38	106.87	2.0 %	2.0 %	0.76
2030	82.42	103.98	104.41	4.38	38.35	53.43	109.01	2.0 %	2.0 %	0.76
2031	84.06	106.06	106.50	4.47	39.12	54.50	111.19	2.0 %	2.0 %	0.76
2032	85.74	108.18	108.63	4.56	39.90	55.58	113.41	2.0 %	2.0 %	0.76
2033	87.46	110.35	110.80	4.65	40.70	56.70	115.67	2.0 %	2.0 %	0.76
	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, 2023.

The payment date for InPlay’s March 2024 dividend declared on March 1, 2024 has been amended to March 28, 2024 due to Canadian banks being closed on the previously disclosed payment date of March 29, 2024.

On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support and look forward to an exciting 2024 and beyond.

For further information please contact:

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

Reader Advisories

Non-GAAP 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”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net corporate acquisitions”, “Production per debt adjusted share” and “EV / DAAFF”. Management believes these measures and ratios 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”)

Management considers FAFF an important measure to identify the Company’s ability to improve its financial condition through debt repayment and its ability to provide returns to shareholders. FAFF should not be considered as an alternative to or more meaningful than AFF as determined in accordance with GAAP as an indicator of the Company’s performance. FAFF is calculated by the Company as AFF 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 or potentially return of capital to shareholders. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast FAFF.

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. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast operating income, operating netback per boe and operating income profit margin.

(thousands of dollars)	Three Months Ended December 31		Year Ended December 31
	2023	2022	2023	2022
Revenue	47,631	58,161	179,366	238,590
Royalties	(6,339)	(10,375)	(22,516)	(38,392)
Operating expenses	(13,233)	(13,081)	(49,576)	(43,740)
Transportation expenses	(940)	(1,118)	(3,130)	(3,920)
Operating income	27,119	33,587	104,144	152,538
Sales volume (Mboe)	882.8	885.3	3,294.1	3,323.4
Per boe
Revenue	53.95	65.69	54.45	71.79
Royalties	(7.18)	(11.72)	(6.84)	(11.55)
Operating expenses	(14.99)	(14.78)	(15.05)	(13.16)
Transportation expenses	(1.06)	(1.26)	(0.95)	(1.18)
Operating netback per boe	30.72	37.93	31.61	45.90
Operating income profit margin	57 %	58 %	58 %	64 %

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. When this measure is presented quarterly, EBITDA is annualized by multiplying by four. When this measure is presented on a trailing twelve month basis, EBITDA for the twelve months preceding the net debt date is used in the calculation. 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 to the “Forward Looking Information and Statements” section for a calculation of forecast Net Debt to EBITDA.

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
	2023	2022	2023	2022
Corporate acquisitions, net of cash acquired	–	(321)	–	180
Share consideration(1)	–	–	–	–
Non-cash working capital acquired	–	–	–	–
Derivative contracts	–	–	–	–
Net Corporate acquisitions	–	(321)(1)	–	180(1)
(1)	During the year ended December 31, 2022, the acquired amount of Property, plant and equipment was adjusted by $0.2 million as a result of adjustments relating to the acquisition, with a corresponding increase in the recognized amounts of Accounts payable and accrued liabilities.

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 to be 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 to be 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 measure that is used in the calculation of EV/DAAFF. Enterprise value is calculated as the Company’s 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 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 financial statements for the year ended December 31, 2023. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. Decommissioning expenditures are adjusted from funds flow as they are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets. 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 per common share.

Net Debt

Net debt is a GAAP measure and is disclosed in the notes to the Company’s financial statements for the year ended December 31, 2023. The Company closely monitors its capital structure with the 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 volumes. 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 volumes. 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 volumes. 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 volumes. 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 Company’s business strategy, milestones and objectives; 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; the expectation that PDNP reserves will move to the PDP reserve category throughout 2023 and the timing thereof; the Company’s planned 2024 capital program including wells to be drilled and completed and the timing of the same including, without limitation, the timing of wells coming on production; 2024 guidance based on the planned capital program and all associated underlying assumptions set forth in this press release including, without limitation, forecasts of 2024 annual average 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 including the expectation that the high light oil and liquids weighting will continue into 2024; expectations regarding future commodity prices; future oil and natural gas prices including the forecast that MSW differentials to WTI are forecasted to improve through 2024; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates including the expectation that downward trending operating costs will continue into 2024; 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 2024 capital program; the amount and timing of capital projects; and methods of funding our capital program.

The internal projections, expectations, or beliefs underlying our Board approved 2024 capital budget and associated guidance are subject to change in light of, among other factors, the impact of world events including the Russia/Ukraine conflict and war in the Middle East, ongoing results, prevailing economic circumstances, volatile commodity prices, and changes in industry conditions and regulations. InPlay’s 2024 financial outlook and guidance provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions or dispositions, for such time periods based upon the key assumptions outlined herein. Readers are cautioned that events or circumstances could cause capital plans and associated results to differ materially from those predicted and InPlay’s guidance for 2024 may not be appropriate for other purposes. Accordingly, undue reliance should not be placed on same.

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 debt financing on acceptable terms; the anticipated tax treatment of the monthly base dividend; the timing and amount of purchases under the Company’s NCIB; 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; the ongoing impact of the Russia/Ukraine conflict and war in the Middle East; 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.

Without limitation of the foregoing, readers are cautioned that the Company’s future dividend payments to shareholders of the Company, if any, and the level thereof will be subject to the discretion of the Board of Directors of InPlay.  The Company’s dividend policy and funds available for the payment of dividends, if any, from time to time, is dependent upon, among other things, levels of FAFF, leverage ratios, financial requirements for the Company’s operations and execution of its growth strategy, fluctuations in commodity prices and working capital, the timing and amount of capital expenditures, credit facility availability and limitations on distributions existing thereunder, and other factors beyond the Company’s control. Further, the ability of the Company to pay dividends will be subject to applicable laws, including satisfaction of solvency tests under the Business Corporations Act (Alberta), and satisfaction of certain applicable contractual restrictions contained in the agreements governing the Company’s outstanding indebtedness.

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 Russia/Ukraine conflict and war in the Middle East; inflation and the risk of a global recession; changes in our planned 2024 capital program; changes in our approach to shareholder returns; changes in commodity prices and other assumptions outlined herein; the risk that dividend payments may be reduced, suspended or cancelled; 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; changes in our credit structure, 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 and our MD&A.

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about InPlay’s financial and leverage targets and objectives, potential dividends, share buybacks and beliefs underlying our Board approved 2024 capital budget and associated guidance, 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 reasonable 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 and strategy. 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 2023 annual guidance and a comparison to 2023 actual results are outlined below.

			Guidance FY 2023(1)	Actuals FY 2023	Variance	Variance (%)
Production	Boe/d		9,000 – 9,100	9,025	–	–
Adjusted Funds Flow	$ millions		$91 – $93	$92	–	–
Capital Expenditures	$ millions		$84.5	$84.5	–	–
Free Adjusted Funds Flow	$ millions		$6 – $8	$7	–	–
Net Debt	$ millions		$47 – $45	$46	–	–
(1)	As previously released January 29, 2024.

Risk Factors to FLI

Risk factors that could materially impact successful execution and actual results of the Company’s 2024 capital program and associated guidance and estimates include:

• volatility of petroleum and natural gas prices and inherent difficulty in the accuracy of predictions related thereto;
• the extent of any unfavourable impacts of wildfires in the province of Alberta.
• changes in Federal and Provincial regulations;
• the Company’s ability to secure financing for the Board approved 2024 capital program and longer-term capital plans sourced from AFF, bank or other debt instruments, asset sales, equity issuance, infrastructure financing or some combination thereof; and
• those additional risk factors set forth in the Company’s MD&A and most recent Annual Information Form filed on SEDAR

Key Budget and Underlying Material Assumptions to FLI

The key budget and underlying material assumptions used by the Company in the development of its 2024 guidance are as follows:

				Actuals FY 2023	Guidance FY 2023(1)	Guidance FY 2024(1)
WTI	US$/bbl			$77.62	$77.61	75.00
NGL Price	$/boe			$36.51	$36.60	$36.85
AECO	$/GJ			$2.50	$2.50	$2.35
Foreign Exchange Rate	CDN$/US$			0.74	0.74	0.74
MSW Differential	US$/bbl			$3.25	$3.25	$4.45
Production	Boe/d			9,025	9,000 – 9,100	9,000 – 9,500
Revenue	$/boe			54.45	54.00 – 55.00	51.25 – 56.25
Royalties	$/boe			6.84	6.50 – 7.00	5.90 – 7.40
Operating Expenses	$/boe			15.05	14.50 – 15.50	12.75 – 15.75
Transportation	$/boe			0.95	0.90 – 1.05	0.85 – 1.10
Interest	$/boe			1.65	1.50 – 1.70	1.50 – 2.00
General and Administrative	$/boe			3.13	3.00 – 3.30	2.50 – 3.25
Hedging loss (gain)	$/boe			(1.10)	(1.00) – (1.25)	0.00 – 0.15
Decommissioning Expenditures	$ millions			$3.3	$3.5 – $4.0	$4.0 – $4.5
Adjusted Funds Flow	$ millions			$92	$91 – $93	$89 – $96
Dividends	$ millions			$16	$16	$16 – $17
			Actuals FY 2023	Guidance FY 2023(1)	Guidance FY 2024(1)
Adjusted Funds Flow	$ millions		$92	$91 – $93	$89 – $96
Capital Expenditures	$ millions		$84.5	$84.5	$64 – $67
Free Adjusted Funds Flow	$ millions		$7	$6 – $8	$22 – $32

			Actuals FY 2023	Guidance FY 2023(1)	Guidance FY 2024(1)
Revenue	$/boe		54.45	54.00 – 55.00	51.25 – 56.25
Royalties	$/boe		6.84	6.50 – 7.00	5.90 – 7.40
Operating Expenses	$/boe		15.05	14.50 – 15.50	12.75 – 15.75
Transportation	$/boe		0.95	0.90 – 1.05	0.85 – 1.10
Operating Netback	$/boe		31.61	31.00 – 32.00	29.50 – 34.50
Operating Income Profit Margin			58 %	58 %	59 %
			Actuals FY 2023	Guidance FY 2023(1)	Guidance FY 2024(1)
Adjusted Funds Flow	$ millions		$92	$91 – $93	$89 – $96
Interest	$/boe		1.65	1.50 – 1.70	1.50 – 2.00
EBITDA	$ millions		$98	$97 – $99	$95 – $102
Net Debt	$ millions		$46	$45 – $47	$37 – $44
Net Debt/EBITDA			0.5	0.5	0.4 – 0.5

			Actuals FY 2023	Guidance FY 2023(1)
Production	Boe/d		9,025	9,000 – 9,100
Opening Net Debt	$ millions		$33	$33
Ending Net Debt	$ millions		$46	$45 – $47
Weighted avg. outstanding shares	# millions		89.1	89.1
Assumed Share price	$		2.65(3)	2.65
Prod. per debt adj. share growth(2)(5)			(8 %)	(7%) – (9%)
			Actuals FY 2023	Guidance FY 2023(1)
Share outstanding, end of year	# millions		91.1	91.1
Assumed Share price	$		2.21(4)	2.21
Market capitalization	$ millions		$201	$201
Net Debt	$ millions		$46	$45 – $47
Enterprise value	$millions		$247	$246 – $248
Adjusted Funds Flow	$ millions		$92	$91 – $93
Interest	$/boe		1.65	1.50 – 1.70
Debt Adjusted AFF	$ millions		$98	$97 – $99
EV/DAAFF(5)			2.5	2.6 – 2.5

(1)	As previously released January 29, 2024.
(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. Future share prices are assumed to be consistent with the current share price.
(3)	Weighted average share price throughout 2023.
(4)	Ending share price at December 31, 2023.
(5)	The Company has withdrawn its 2024 and 2025 production per debt adjusted share and EV/DAAFF forecast for 2024 and 2025. The Company believes that these metrics can be quite variable and hard to reasonably estimate given the volatility in the Company’s share price, which is a material assumption used in the calculation of these metrics.
(6)	Continued commodity price volatility and current weak industry sentiment has resulted in the Company taking a conservative and disciplined approach to capital allocation in 2024 and future years.  Preliminary estimates and plans for 2025 and beyond will be dependent on the stability of commodity prices and industry sentiment balancing manageable growth and ensuring the long term sustainability of our return of capital to shareholder strategy. As a result, the Company previously withdrew its preliminary estimates and plans for 2025.
• 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 the years presented above.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information

Our oil and gas reserves statement for the year ended December 31, 2023, 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.sedarplus.com on or before March 31, 2024.  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”, 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“).

Production Breakdown by Product Type

Disclosure of production on a per boe basis in this document 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 2022 Average Production	3,909	1,532	25,090	9,623
2022 Average Production	3,766	1,402	23,623	9,105
Q4 2023 Average Production	4,142	1,520	23,606	9,596
2023 Average Production	3,822	1,396	22,839	9,025
2023 Annual Guidance	3,840	1,390	22,920	9,050(1)
2024 Annual Guidance	4,090	1,395	22,590	9,250(2)
Notes:
1.	This reflects the mid-point of the Company’s 2023 production guidance range of 9,000 to 9,100 boe/d.
2.	This reflects the mid-point of the Company’s 2024 production guidance range of 9,000 to 9,500 boe/d.

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. 

Initial Production Rates

References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Accordingly, the Company cautions that the test results should be considered to be preliminary.

SOURCE InPlay Oil Corp.