Motorists across the nation are once again feeling the pinch at the gas pump as oil prices have climbed sharply in recent months. After a brief reprieve earlier this year, the national average price for a gallon of regular gasoline has risen over 18 cents in just the last month to around $3.40 according to AAA data. Experts warn that prices could jump another 10-15 cents over the next couple of weeks alone.
The primary culprit behind the surge is the rising cost of crude oil. Both the U.S. benchmark West Texas Intermediate and the global Brent crude have seen prices spike, with WTI crude now hovering around $79 per barrel and Brent north of $83 per barrel. Just a few months ago, WTI started 2024 just over $70 a barrel.
As crude gets more expensive for refiners to purchase, the costs get passed along to consumers in the form of higher gasoline prices. Tighter supplies and seasonal factors are also contributing to price increases at the pump.
“This week, Gulf Coast refiners began transitioning to more expensive summer blend gasoline, which accounts for nearly 50% of the nation’s refining capacity,” said Andy Lipow of Lipow Oil Associates. “That switch means higher prices are ahead.”
California drivers are being hit particularly hard, with the statewide average price per gallon already at a lofty $4.88 as of Wednesday. Refinery maintenance, lower inventory levels, and the changeover to summer blends have caused California gas prices to jump around 25 cents in recent weeks according to Lipow.
The overall lower supply situation is being exacerbated by disruptions at some key refineries. For example, BP’s massive Whiting refinery in Indiana, the largest in the Midwest, is still recovering from a recent power outage caused by cold weather that impacted production.
Historically, spring represents the start of the annual rise in gas prices as refiners transition to summer blends and demand picks up with more drivers hitting the road after the winter months. Consumer demand typically peaks during summer’s peak driving season.
While higher energy costs were one of the main factors driving an unexpected increase in inflation in February, rising gas prices take an oversized toll on household budgets. The latest Consumer Price Index data showed the gasoline index spiked 3.8% last month alone after declining in January.
Analysts caution there is likely more pain at the pump on the horizon with the summer driving season still ahead. Unless crude oil prices reverse course or refining capacity increases, American drivers can expect gasoline to remain unusually expensive compared to this time last year.
“With the industry having less refining capacity and the economy remaining relatively strong, I expect retail gasoline prices to set new records across the nation in the coming months,” Lipow stated.
Whether taking a road trip for spring break or commuting to and from work and activities, consumers have little choice but to absorb the impact of elevated gas prices cutting into other spending. Budgets will be further squeezed if crude oil costs remain stubbornly high and gasoline supply remains tight.
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.
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/$23.36) = 1.4. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
5.
RLI is calculated by dividing the reserves in each category by the 2023 average annual production. For example 2023 TPP = (61,594 mboe) / (9,025 boe/d) = 18.7 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
Pricing Assumptions:
The following tables set forth the benchmark reference prices, as at December 31, 2023, reflected in the Reserve Report. These price and cost assumptions were an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast and Sproule’s foreign exchange rate forecast at the effective date of the Reserve Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1) as of December 31, 2023 FORECAST PRICES AND COSTS
Year
WTICushingOklahoma($US/Bbl)
CanadianLight Sweet40o API($Cdn/Bbl)
CromerLSB 35o API($Cdn/Bbl)
Natural Gas AECO- C Spot($Cdn/MMBtu)
NGLsEdmonton Propane($Cdn/Bbl)
NGLs Edmonton Butanes($Cdn/Bbl)
EdmontonPentanesPlus($Cdn/Bbl)
Operating Cost Inflation Rates%/Year
Capital Cost Inflation Rates%/Year
Exchange Rate (2)($Cdn/$US)
Forecast(3)
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
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.
Vancouver, British Columbia–(Newsfile Corp. – March 12, 2024) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce highlights from its independent reserves evaluation (the “Reserve Report”), prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) and effective as at December 31, 2023.
In 2023, Hemisphere invested $16 million to drill eight successful Atlee Buffalo wells, upgrade facilities in Atlee Buffalo, purchase land and seismic, and pre-purchase some of the materials for its 2024 development program. With the Company’s capital additions, corporate production in 2023 increased by more than 10% year-over-year, to 3,124 boe/d (99% heavy oil). Production is currently trending over 3,450 boe/d (99% heavy oil, based on field estimates between February 10 – March 10, 2024), after significant downtime experienced in January and early February due to extreme cold weather and equipment failure.
During the year, Hemisphere also distributed $13.1 million in base and special dividends, purchased 3.2 million shares under its normal course issuer bid (“NCIB”) for a total price of $4.0 million (at an average price of $1.25/share), and exited the year in a cash position with working capital1 of over $3 million.
The Company’s continued success in the development of its enhanced oil recovery projects was recognized again by McDaniel in the Reserve Report. In the Proved Developed Producing (“PDP”) category, Hemisphere replaced 104% of 2023 production and increased reserve value by 9% to $248 million NPV10 BT. Hemisphere also grew Proved (“1P”) reserve value to $325 million NPV10 BT and Proved plus Probable (“2P”) reserve value to $416 million NPV10 BT.
The Company’s new Saskatchewan lands currently account for only 5% of 1P and 7% of 2P reserves, while making up only 3% of 1P and 5% of 2P NPV10 BT valuations of Hemisphere’s reserves. Significant reserve upside remains on Hemisphere lands if the play proves successful over the course of 2024 and beyond.
Consistent with McDaniel’s 2022 year-end evaluation, the Reserve Report incorporates full corporate abandonment, decommissioning, and reclamation costs (“ADR”) in the PDP category. Hemisphere has always been cautious of acquiring additional wellbore and facility liabilities. A direct result of this strategy is that Hemisphere’s reserves retain more comparative value per barrel than companies with additional ADR liabilities that must be deducted from their base valuations. Management estimates that total undiscounted and uninflated existing ADR is $8.3 million ($2.3 million NPV10 BT, with costs inflated at 2%/yr), which includes all ADR associated with both active and inactive wells, pipelines, and facilities regardless of whether such wells, pipelines, and facilities had any attributed reserves. Based on public information, Hemisphere stands out among its industry peers as being within the top 8% of Alberta oil and gas operators for its industry-leading liability management ratio (“LMR”) of 17, resulting in Hemisphere having less than 1% of its PDP net present value impaired by ADR.
Hemisphere’s low decline, long life, and high value reserves are a sign of the tremendous resource the Company has been developing over the past number of years. These valuable assets are the backbone of Hemisphere and are expected to generate significant free cash flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques.
2023 Reserve Highlights
Proved Developed Producing (“PDP”) Reserves
NPV10 BT of $248 million, an increase of 9% over year-end 2022 and equivalent to $2.49 per basic share.
Replaced 104% of 2023 production through organic development.
Maintained reserve volumes year-over-year at 8.2 MMboe (99.6% heavy crude oil).
Achieved a 2-year FD&A cost of $9.30/boe (including changes in future development capital (“FDC”)) for a recycle ratio of 5.4.
RLI of 7.2 years based on 2023 production.
Proved (“1P”) Reserves
NPV10 BT of $325 million, an increase of 5% over year-end 2022 and equivalent to $3.27 per basic share.
Replaced 90% of 2023 production through organic development.
Maintained reserve volumes year-over-year at 12.1 MMboe (99.4% heavy crude oil).
Achieved a 2-year FD&A cost of $14.82/boe (including changes in FDC) for a recycle ratio of 3.4.
RLI of 10.6 years based on 2023 production.
NAV of $3.18 per fully diluted share based on Reserve Report pricing assumptions.
NAV of $3.28 and $4.27 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.
Proved plus Probable (“2P”) Reserves
NPV10 BT of $416 million, an increase of 5% over year-end 2022 and equivalent to $4.19 per basic share.
Replaced 125% of 2023 production through organic development.
Maintained reserve volumes at 16.3 MMboe (99.4% heavy crude oil).
Achieved a 2-year FD&A cost of $14.91/boe (including changes in FDC) for a recycle ratio of 3.4.
RLI of 14.3 years based on 2023 production.
NAV of $4.03 per fully diluted share based on Reserve Report pricing assumptions.
NAV of $4.12 and $5.36 per fully diluted share based on Reserve Report run internally at McDaniel’s pricing sensitivities of US$80 and US$100 WTI flat pricing.
2023 Independent Qualified Reserve Evaluation
The reserves data set forth below is based upon an independent reserves evaluation prepared by McDaniel dated March 11, 2024 with an effective date of December 31, 2023, and is in accordance with definitions, standards, and procedures contained within COGEH 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 Hemisphere’s Annual Information Form which will be filed on SEDAR+ on or before April 30, 2024. Due to rounding, certain totals in the columns may not add in the following tables. All dollar values are in Canadian dollars, unless otherwise noted.
Pricing Assumptions
McDaniel’s independent evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. (the “3-Consultant Average Price Forecast”) at January 1, 2024, with the following table detailing pricing and foreign exchange rate assumptions. Hemisphere’s corporate production historically averages a discount of approximately $4.50 to WCS pricing. When compared to last year’s 3-Consultant Average Price Forecast dated January 1, 2023, the current WCS pricing outlook is down approximately 1% in 2024, and up 1% thereafter over the next 15-year period. The 2024 3-Consultant Average Price Forecast uses a 5-year 2024-28 WTI price of US$76.33/bbl and WCS price of Cdn$81.11/bbl.
3-Consultant Average Price Forecast January 1, 2023
3-Consultant Average Price Forecast January 1, 2024
WTI Crude Oil ($US/bbl)
Edmonton Light Crude Oil ($Cdn/bbl)
Western Canadian Select WCS Crude Oil ($Cdn/bbl)
AECO Spot Price ($Cdn/MM Btu)
Inflation (%)
US/Cdn Exchange Rate ($US/$Cdn)
WTI Crude Oil ($US/bbl)
Western Canadian Select WCS Crude Oil ($Cdn/bbl)
Edmonton Light Crude Oil ($Cdn/bbl)
AECO Spot Price ($Cdn/MM Btu)
Inflation (%)
US/Cdn Exchange Rate ($US/$Cdn)
2024
78.50
97.74
77.75
4.40
2.3
0.765
2024
73.67
92.91
76.74
2.20
0
0.745
2025
76.95
95.27
77.55
4.21
2
0.768
2025
74.98
95.04
79.77
3.37
2
0.765
2026
77.61
95.58
80.07
4.27
2
0.772
2026
76.14
96.07
81.12
4.05
2
0.768
2027
79.16
97.07
81.89
4.34
2
0.775
2027
77.66
97.99
82.88
4.13
2
0.772
2028
80.74
99.01
84.02
4.43
2
0.775
2028
79.22
99.95
85.04
4.21
2
0.775
2029
82.36
100.99
85.73
4.51
2
0.775
2029
80.80
101.94
86.74
4.30
2
0.775
2030
84.00
103.01
87.44
4.60
2
0.775
2030
82.42
103.98
88.47
4.38
2
0.775
2031
85.69
105.07
89.20
4.69
2
0.775
2031
84.06
106.06
90.24
4.47
2
0.775
2032
87.40
106.69
91.11
4.79
2
0.775
2032
85.74
108.18
92.04
4.56
2
0.775
2033
89.15
108.83
92.93
4.88
2
0.775
2033
87.46
110.35
93.89
4.65
2
0.775
2034
90.93
111.00
94.79
4.98
2
0.775
2034
89.21
112.56
95.77
4.74
2
0.775
2035
92.75
113.22
96.69
5.08
2
0.775
2035
90.99
114.81
97.68
4.84
2
0.775
2036
94.61
115.49
98.62
5.18
2
0.775
2036
92.81
117.10
99.64
4.94
2
0.775
2037
96.50
117.80
100.59
5.29
2
0.775
2037
94.67
119.45
101.63
5.03
2
0.775
2038
98.43
120.16
102.60
5.40
2.00
0.78
2038
96.56
121.83
103.66
5.14
2.00
0.78
Summary of Reserves(1)
Heavy Oil
Conventional Natural Gas
Total
Reserves Category
(Mbbl)
(MMcf)
(Mboe)
Proved
Developed Producing
8,196
173
8,225
Developed Non-Producing
34
7
35
Undeveloped
3,756
250
3,798
Total Proved
11,987
429
12,058
Probable
4,231
188
4,262
Total Proved plus Probable
16,217
617
16,320
Note:
(1)Reserves are presented as “gross reserves” which are the Company’s working interest reserves before royalty deductions and without including any royalty interests.
Summary of Net Present Value of Future Net Revenue, Before Tax (“NPV BT”) (1)(2)
NPV BT (M$, except per share amount)
Discounted at (% per Year)
Reserves Category
0%
5%
10%
Proved
Developed Producing
363,872
295,324
247,832
Developed Non-Producing
720
603
513
Undeveloped
126,954
97,757
76,777
Total Proved
491,546
393,685
325,121
Probable
190,663
126,483
91,337
Total Proved plus Probable
682,209
520,168
416,458
Per basic share(3)
Proved Developed Producing
3.66
2.97
2.49
Proved
4.95
3.96
3.27
Proved plus Probable
6.87
5.24
4.19
Notes: (1)Based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. at January 1, 2024, as outlined in the table herein entitled “Pricing Assumptions”. (2)It should not be assumed that the estimates of net present value of future net revenues presented in this table represent the fair market value of Hemisphere’s reserves. (3)Based on there being 99,340,339 issued and outstanding shares of the Company as of December 31, 2023.
Future Development Costs (“FDC”)
The following summarizes the development costs deducted in the estimation of the net present value of the future net revenue attributable to 1P and 2P reserves.
Forecast Costs (M$)
1P
2P
2024
16,410
16,410
2025
22,959
28,051
2026
7,087
12,648
2027
3,501
3,501
Subsequent years
–
–
Total Undiscounted
49,956
60,609
Total Discounted at 10%
43,568
52,209
Finding, Development and Acquisition Costs (“FD&A”) Costs and Recycle Ratios(1)(2)
2023
2-Year Totals/Average
FD&A
PDP
1P
2P
PDP
1P
2P
Exploration, development and acquisition capital (M$)(3)(4)
14,543
31,570
Total changes in FDC (M$)
-528
4,869
10,094
-2,527
2,191
9,888
Total FD&A Capital, including changes in FDC (M$)
14,015
19,412
24,637
29,044
33,762
41,458
FD&A Reserve additions, including revisions (Mboe)
1,181
1,027
1,425
3,123
2,278
2,780
FD&A costs(5), including changes in FDC ($/boe)
11.87
18.90
17.28
9.30
14.82
14.91
Recycle Ratio(6)
3.8
2.4
2.6
5.4
3.4
3.4
Notes: (1)All financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which have not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors. (2)See “Oil and Gas Advisories” and “Oil and Gas Metrics”. (3)Exploration, development and acquisition capital excludes capitalized administration costs. (4)The aggregate of the exploration, development and acquisition capital incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding, development and acquisition costs related to reserve additions for that year. (5)FD&A costs are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (FDC) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis, and 2023 production of 3,124 boe/d. (6)Recycle ratio is calculated as Operating field netback divided by FD&A costs. Operating field netback is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similarmeasures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”. The Company‘s estimated operating field netback in 2023 was $45.41/boe (unaudited) and 2-year 2022/23 average operating field netback was $50.67/boe.
Reserve Life Index (“RLI”)
As of December 31, 2023(1)
PDP
7.2
1P
10.6
2P
14.3
Note: (1)Calculated as the applicable reserves volume divided by Hemisphere’s average 2023 production of 3,124 boe/d.
Net Asset Value (“NAV”)(1)
As at December 31, 2023
(MM$ except share amounts)
3-Consultant Average Price Forecast
US$80 WTI
US$100 WTI
1P NPV10 BT(2)
325
336
441
2P NPV10 BT(2)
416
426
558
Undeveloped Land and Seismic(3)
3
Proceeds from Stock Options
9
Working Capital(4)
3
Million Shares Outstanding (fully diluted)
107
1P NAV per share (fully diluted)
$3.18
$3.28
$4.27
2P NAV per share (fully diluted)
$4.03
$4.12
$5.36
Notes: (1)Calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from and stock options, plus working capital(4), and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecast used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials, respectively, and 1.37 USD/CAD FX. (2)100% of existing and future corporate ADR has been included in the McDaniel Reserve Report. Total corporate ADR accounted for in the 2023 reserve report, including that for future development, amounts to $3.0 million NPV10 BT in the 1P category and $3.1 million NPV10 BT in the 2P category. (3)Based on an internal evaluation by management of Hemisphere as of December 31, 2023, with an average value of $75.87 per acre for 31,295 undeveloped net acres, and $0.55 million for seismic. (4)Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the section “Non-IFRS and Other Specified Financial Measures”. All financial information as at December 31, 2023 is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which has not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to changes as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors.
About Hemisphere Energy Corporation
Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through water and polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.
For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:
Don Simmons, President & Chief Executive Officer Telephone: (604) 685-9255 Email: info@hemisphereenergy.ca
Definitions and Abbreviations
bbl
barrel
US$
United States dollar
Mbbl
thousands of barrels
Cdn$
Canadian dollar
MMbbl
millions of barrels
M$
thousand dollars
boe
barrel of oil equivalent
MM
million
boe/d
barrel of oil equivalent per day
NPV BT
Net Present Value of future net revenue, before tax
Mboe
thousands of barrels of oil equivalent
NPV10 BT
NPV BT, discounted at 10%
MMboe
millions of barrels of oil equivalent
FX
Foreign Exchange
MMcf
million cubic feet
FDC
Future Development Costs
MMbtu
million British Thermal Unit
FD&A
Finding, Development and Acquisition
AECO
Alberta Energy Company
NAV
Net Asset Value
WCS
Western Canadian Select
RLI
Reserve Life Index
WTI
West Texas Intermediate
Forward-Looking 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” 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 expectations that its assets are expected to generate significant free funds flow as they continue to grow with planned additional development and optimization of enhanced oil recovery techniques; the volumes of Hemisphere’s oil and gas reserves and the estimated net present values of the future net revenues of such reserves; the Company’s estimates of ADR; and the Company’s anticipated filing date for its annual information form for the year ending December 31, 2023; upside potential on Hemisphere’s Saskatchewan properties in 2024 and beyond. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
The estimates of Hemisphere’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Hemisphere which have been used to develop such statements and information, but which may prove to be incorrect. Although Hemisphere 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 Hemisphere 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: that Hemisphere will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities are consistent with past operations; the quality of the reservoirs in which Hemisphere operates and continued performance from existing wells; inflation rates and cost escalations; the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Hemisphere’s reserve volumes; certain commodity price and other cost assumptions; continued availability of debt and equity financing and cash flow to fund Hemisphere’s current and future plans and expenditures; the impact of increasing competition; the general stability of the economic and political environment in which Hemisphere operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Hemisphere 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 Hemisphere has an interest in to operate the field in a safe, efficient and effective manner; the ability of Hemisphere 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 expansion and the ability of Hemisphere to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Hemisphere operates; and the ability of Hemisphere to successfully market its oil and natural gas products.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; regulatory risks, including penalties or other remedial action; the ability of the Company to maintain legal title to its properties; changes to, or restrictions of, labour, supplies, and infrastructure as a result of COVID-19; changes in the demand for or supply of Hemisphere’s products, the early stage of development of some of the evaluated areas and zones; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Hemisphere or by third party operators of Hemisphere’s properties; changes in budgets; increased debt levels or debt service requirements; inaccurate estimation of Hemisphere’s oil and gas reserve volumes; limited, unfavourable 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 Hemisphere’s public disclosure documents, (including, without limitation, those risks identified in this news release and in Hemisphere’s annual information form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Hemisphere 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.
Oil and Gas Advisories
All reserve references in this news release are “gross” or “Company interest reserves”. Such reserves are the Company’s total working interest reserves before the deduction of any royalties and without including any royalty interests of the Company.
It should not be assumed that the net present value of the estimated net revenues presented in this news release represent 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 reserve estimates of Hemisphere’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Estimates of net present value and future net revenue contained herein do not necessarily represent fair market value. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions in evaluating Hemisphere’s reserves will be attained and variances could be material.
All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs and abandonment and reclamation costs and are stated prior to provision for interest and general and administrative expenses. Future net revenues have been presented in this news release on a before tax basis.
“Boe” means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe’s 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. In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Oil and Gas Metrics
This news release contains metrics commonly used in the oil and natural gas industry, such as finding, development and acquisition (“FD&A”) costs, “recycle ratio”, “operating field netback” and “reserve life index (“RLI”)”. These terms do not have a standardized meaning and the Company’s calculation of such metrics may not be comparable to the calculation method used or presented by other companies for the same or similar metrics, and therefore should not be used to make such comparisons.
“Finding, development and acquisition costs” or “FD&A costs” are calculated as the sum of exploration, development and acquisition capital plus the change in future development capital (“FDC”) for the period divided by the change in reserves for the period, including on acquisition lands. FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the exploration, development and acquisition costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total FD&A costs related to reserves additions for that year. Management uses FD&A costs as a measure of capital efficiency for organic reserves development.
“Exploration, development and acquisition capital” means the aggregate exploration, development and acquisition costs incurred in the financial year, and excludes capitalized administration costs.
“Recycle ratio” is a Non-IFRS ratio calculated as the Operating field netback divided by the FD&A cost per boe for the year.Operating field netback is a non-IFRS financial measure (refer to the section “Non-IFRS and Other Specified Financial Measures”). Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.
“Reserve life index” is calculated as total company interest reserves divided by annual production, for the year indicated.
“NAV per fully diluted share” is calculated using the respective net present values of 1P and 2P reserves, before tax and discounted at 10%, plus internally valued undeveloped land & seismic and proceeds from warrants and stock options, plus working capital, and divided by fully diluted outstanding shares. Net present values are shown at various price forecasts including the 3-Consultant Average Price Forecasts used in the McDaniel Reserve Report, as well as sensitivities run internally at McDaniel’s flat WTI price forecasts of US$80 and US$100 WTI paired with US$19.32 and US$23.45 WCS differentials respectively, and 1.37 USD/CAD FX. Management uses NAV per share as a measure of the relative change of Hemisphere’s net asset value over its outstanding common shares over a period of time.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.
Financial Information
Certain financial information included in this news release is per Hemisphere’s preliminary unaudited financial statements for the year ended December 31, 2023, which have not yet been approved by the Company’s Audit Committee or Board of Directors and therefore represents management’s estimates. Readers are advised that these financial estimates may be subject to change as a result of the completion of the independent audit on Hemisphere’s financial statements for the year ended December 31, 2023, and the review and approval of same with the Company’s Audit Committee and Board of Directors. All amounts are expressed in Canadian dollars unless otherwise noted.
Non-IFRS and Other Specified Financial Measures
Certain measures commonly used in the oil and natural gas industry referred to herein, including “Working Capital” and “Operating field netback”, do not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other companies. These non-IFRS measures are further described and defined below. Investors are cautioned that these measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of Hemisphere’s performance. Set forth below are descriptions of the non-IFRS financial measures used in this news release.
“Working Capital” is closely monitored by the Company to ensure that its capital structure is maintained by a strong balance sheet to fund the future growth of the Company. Working Capital is used in this document in the context of liquidity and is calculated as the total of the Company’s bank debt plus current assets, less current liabilities, excluding the fair value of financial instruments, lease and decommissioning liabilities.
($MM)
Twelve Months Ended December 31, 2022 (unaudited)
Bank debt
$
–
Current assets
13.3
Current liabilities
(9.9
)
Working Capital
$
3.4
“Operating field netback” is calculated as oil and gas sales, less royalties, operating expenses, and transportation costs on an absolute and per barrel of oil equivalent basis. Operating netback per boe and Operating field netback per boe are calculated by dividing the respective terms by the applicable barrels of oil equivalent of production. A reconciliation of Operating netback and Operating field netback per boe to the most directly comparable measure calculated and presented in accordance with IFRS is as follows:
($/boe)
Twelve Months Ended December 31, 2022 (unaudited)
Average realized sales
$
74.05
Royalties
(14.89
)
Operating and transportation expenses
(13.75
)
Operating field netback
$
45.41
The Company has provided additional information on how these measures are calculated in the Management’s Discussion and analysis for the year ended December 31, 2022 and for the three and nine month periods ended September 30, 2023, which are available under the Company’s SEDAR+ profile at www.sedarplus.ca.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
1 Working Capital is a non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to the sections “Non-IFRS and Other Specified Financial Measures” and “Financial Information”.
In a major development in the uranium mining sector, ATHA Energy Corp. and Latitude Uranium Inc. announced the successful completion of their merger on March 7, 2024. Through this strategic transaction, ATHA has acquired 100% of the outstanding common shares of Latitude Uranium, making the latter a wholly-owned subsidiary.
The merger brings together two promising uranium players, combining their complementary assets and expertise to create a formidable force in the industry. Latitude Uranium shareholders received 0.2769 ATHA common shares for each share held, resulting in ATHA issuing approximately 64.4 million new shares.
This deal marks a significant milestone for ATHA, adding historical resources to its portfolio and expanding its reach across multiple high-grade uranium jurisdictions. The combined company now boasts a diverse range of exploration catalysts, including the Angilak and CMB uranium discoveries, with historical resource estimates of 43.3 million lbs and 14.5 million lbs U3O8, respectively.
Moreover, ATHA now holds the largest cumulative exploration package in both the Athabasca Basin and Thelon Basin, two of the world’s most prominent basins for uranium discoveries, with a total of 6.5 million acres. Additionally, the company has a 10% carried interest in a portfolio of claims in the Athabasca Basin operated by industry leaders NexGen Energy Ltd. and IsoEnergy Ltd.
Troy Boisjoli, CEO of ATHA, expressed enthusiasm about the merger, stating, “This acquisition marks a significant milestone for the Company by adding historical resource to our portfolio and enabling us to expand the reach of our robust balance sheet across a diverse range of exploration catalysts.”
The Resurgence of Uranium Mining
The ATHA-Latitude Uranium merger comes at a time when the uranium mining industry is experiencing a resurgence, driven by the global push towards clean energy and the pivotal role of nuclear power in achieving carbon neutrality goals.
As countries around the world seek to reduce their reliance on fossil fuels and transition to more sustainable energy sources, the demand for uranium is expected to increase significantly. Nuclear power plants, which generate electricity without emitting greenhouse gases, are attracting renewed interest as a viable solution to meet energy needs while addressing climate change concerns.
This resurgence has sparked a flurry of activity in the uranium mining sector, with companies scrambling to secure promising exploration projects and develop new mines to meet the anticipated demand. Established players and emerging companies alike are vying for a share of this lucrative market, fueled by the potential for substantial returns on investment.
However, the uranium mining industry is not without its challenges. Stringent regulations, environmental concerns, and the need for significant capital investment present hurdles that companies must navigate cautiously. Responsible exploration and mining practices, combined with robust risk management strategies, are crucial for long-term success in this sector.
Nonetheless, the ATHA-Latitude Uranium merger positions the combined entity as a formidable player in the uranium mining landscape. With a diverse portfolio of assets, historical resources, and strategic partnerships, the company is well-positioned to capitalize on the growing demand for uranium and contribute to the global transition towards a more sustainable energy future.
As the world grapples with the twin challenges of meeting energy needs and addressing climate change, the uranium mining industry is poised to play a pivotal role. Companies like ATHA, armed with extensive resources and a solid growth strategy, may emerge as key players in this exciting and rapidly evolving sector.
CALGARY, AB, March 5, 2024 /CNW/ – Alvopetro Energy Ltd. (TSXV: ALV) (OTCQX: ALVOF) announces February 2024 sales volumes of 1,477 boepd including natural gas sales of 8.3 MMcfpd, associated natural gas liquids sales from condensate of 72 bopd and oil sales of 19 bopd, based on field estimates. February sales volumes were impacted by reduced nominations from our offtaker, Bahiagás mainly in the latter half of February. Effective March 1, 2024 deliveries to Bahiagás have increased back to over 10.6 MMcfpd.
Natural gas, NGLs and crude oil sales:
February2024
January 2024
Natural gas (Mcfpd), by field:
Caburé
7,875
9,305
Murucututu
449
382
Total Company natural gas (Mcfpd)
8,324
9,687
NGLs (bopd)
72
75
Oil (bopd)
19
9
Total Company (boepd)
1,477
1,699
Corporate Presentation
Alvopetro’s updated corporate presentation is available on our website at:
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Abbreviations:
boepd
=
barrels of oil equivalent (“boe”) per day
bopd
=
barrels of oil and/or natural gas liquids (condensate) per day
Mcf
=
thousand cubic feet
Mcfpd
=
thousand cubic feet per day
MMcfpd
=
million cubic feet per day
NGLs
=
natural gas liquids
BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the expected natural gas price, natural gas sales and natural gas deliveries under the Company’s long-term gas sales agreement. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, the success of future drilling, completion, and testing, equipment availability, the timing of regulatory licenses and approvals, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of global pandemics and other significant worldwide events, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR+ profile at www.sedarplus.ca. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Oil prices have staged a strong rally over the last few trading sessions, with both Brent and West Texas Intermediate (WTI) crude futures settling above $80 and $83 per barrel respectively on Friday. This marks the highest level for oil prices since November 2023. The recent surge has been driven by growing signs of tightness in global oil supplies along with heightened geopolitical risks in the Middle East.
For investors in the oil and gas sector, the combination of bullish supply and demand fundamentals and rising geopolitical tensions point to potential upside in oil prices through 2024. Here are some of the key factors driving the latest rally:
Supply Fundamentals Point to Tightness
On the supply side, oil prices are being lifted by OPEC+’s continued restraint on production increases. The group of major oil producers is expected to extend production cuts beyond their planned exit in March, tightening global supplies. Additionally, near-term futures contracts are trading at a premium to later dated contracts, a condition known as backwardation which signals tight supplies.
Asia Demand Exceeding Expectations
At the same time, oil demand has proved resilient, especially in Asia. Demand out of Asia has exceed expectations in recent months, even as parts of Europe remain locked down. With economies reopening as vaccine rollouts accelerate, pent-up travel demand in Asia is set to further boost oil consumption over 2023. The combination of robust demand growth and limited supply increases has led to a rapid drawdown of global oil inventories since the start of the year.
Middle East Tensions Creating Geopolitical Risk Premium
On top of bullish market fundamentals, ongoing tensions in the Middle East are layering fears of potential supply disruptions. Attacks on oil tankers transiting through the critical Red Sea route has rerouted tanker traffic and added to insurance costs. Escalating violence between Israel and Hamas has raised concerns over stability in the region.
Most importantly, oil prices could spike dramatically if Iran-backed Houthis were to target vessels travelling through the Strait of Hormuz. This critical passageway between Oman and Iran handles around 30% of all seaborne-traded crude oil globally. Any military clashes or outright closure of the Strait would severely constrain global oil flows and lead to a price spike.
Upside Risks Outweigh Downsides for Oil Prices
In summary, investors should be aware of the multitude of upside risks supporting higher oil prices as we progress through 2024. While oil demand may moderate as economies eventually normalize post-pandemic, OPEC+ restraint and the risk of supply disruptions look set to keep the market tight.
As leading investment banks like Goldman Sachs have noted, their base case forecast of $70-90 per barrel for Brent could easily see upside, with geopolitics posing the main risk. For investors, oil exploration and production companies as well as oil services firms stand to benefit most from higher prices. Integrated majors may lag on share price gains though due to their downstream refining exposure. Overall, oil markets appear set to tighten further, making the case for investors to overweight the energy sector.
CALGARY, AB, Feb. 26, 2024 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV) (OTCQX: ALVOF) announces our reserves as at December 31, 2023 with total proved plus probable (“2P”) reserves of 8.7 MMboe and a before tax net present value discounted at 10% (“NPV10”) of $309.7 million, risked best estimate contingent resources of 5.4 MMboe (NPV10 $126.1 million) and risked best estimate prospective resources of 9.6 Mmboe (NPV10 $184.9 million). The reserves and resources data set forth herein is based on an independent reserves and resources assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated February 26, 2024 with an effective date of December 31, 2023 (the “GLJ Reserves and Resources Report”).
The GLJ Reserves and Resources Report incorporates Alvopetro’s working interest share of remaining recoverable reserves held by Alvopetro in the Caburé and Murucututu natural gas fields and the Bom Lugar and Mãe-da-lua oil fields as well as Alvopetro’s working interest share of remaining recoverable resources held by Alvopetro in the Murucututu natural gas field. With respect to Murucututu, Bom Lugar, and Mãe-da-lua, Alvopetro’s working interest share is 100%. With respect to the unitized area (the “Unit”) which includes our Caburé and Caburé Leste fields (collectively referred to as “Caburé” in this news release) and two fields held by our third-party partner in the Unit, Alvopetro’s working interest share as of December 31, 2023 was 49.1%, with the remaining 50.9% held by our partner. As previously announced by the Company, the first redetermination of the working interests to each party commenced in the fourth quarter of 2023. The parties engaged an independent expert (the “Expert”) to evaluate the redetermination. Pursuant to the provisions of the UOA, where an Expert is engaged, the Expert’s determination shall be made using what is commonly referred to as the “pendulum” method of dispute resolution. Under this method, the Expert is not required or permitted to provide their own interpretation but is required to select the single Final Proposal (between the two partner’s respective Final Proposals), which, in the Expert’s opinion, provides the most technically justified result of the application of the relevant information and data and material provided to the Expert consistent with the UOA and all related documents. As of the date of this news release, the outcome of the Expert’s decision and the resulting working interest to Alvopetro following the decision is uncertain. The resulting impact on Alvopetro’s reserves and future cash flows may be material and may have a material adverse effect on Alvopetro. The impact on Alvopetro’s working interest will be effective on the first calendar day of the second month following the date of the decision of the Expert, subject to any government approvals that may be required. The decision of the Expert is expected near the end of the first quarter of 2024. The GLJ Reserves and Resource Report and the references included herein are based on the 49.1% interest in Caburé, Alvopetro’s working interest share as of December 31, 2023. The reserves data included in this news release and in the GLJ Reserves and Resources Report may be materially impacted following the Expert’s decision.
All references herein to $ refer to United States dollars, unless otherwise stated.
December 31, 2023 GLJ Reserves and Resource Report:
Proved reserves (“1P”) decreased 30% to 2.7 MMboe Proved reserves mainly due to 2023 production and technical revisions related to the 197-1 and 183-1 Murucututu wells. Alvopetro is working to enhance production from these wells with optimizations in 2024.
2P reserves decreased 4% from 9.0 to 8.7 MMboe after 0.8 MMboe of production in 2023. Production in 2023 was offset by improved recovery factors at Caburé due to the agreed Unit development plan and new additions associated with the discovery at the 183-A3 well in the Caruaçu Formation.
Proved plus Probable plus Possible reserves (“3P”) increased to 15.2 MMboe from 14.4 MMboe as a result of additions associated with the discovery at the 183-A3 well in the Caruaçu Formation.
2P NPV10 decreased 11% to $309.7 million due to changes in forecast natural gas prices and 2023 production offset mainly by additional value associated with discovered zones in the Caruaçu Formation on our Murucututu natural gas field.
Risked best estimate contingent resources increased from 2.9 MMboe to 5.4 MMboe at December 31, 2023 with a NPV10 of $126.1 million, increases from December 31, 2022 of 84% and 103% respectively. The increases were associated with the discovery at the 183-A3 well in the Caruaçu Formation.
Risked best estimate prospective resources decreased from 12.5 MMboe to 9.6 MMboe with a NPV10 of $184.9 million, decreases of 23% and 29% respectively from December 31, 2022. The decrease was due primarily to adjustments to the probabilistic models incorporating the logs results for the Gomo zone at the 183-A3 well.
SUMMARY
December 31, 2023 Gross Reserve and Gross Resource Volumes: (1)(2)(3)(4)(5)(6)
See ‘Footnotes’ section at the end of this news release
PRICING ASSUMPTIONS – FORECAST PRICES AND COSTS
GLJ employed the following pricing and inflation rate assumptions as of January 1, 2024 in the GLJ Reserves and Resources Report in estimating reserves and resources data using forecast prices and costs.
Year
Brent Blend Crude Oil FOB North Sea ($/Bbl)
National Balancing Point (UK)($/MMBtu)
NYMEX Henry HubNear Month Contract($/MMBtu)
Alvopetro-Bahiagas Gas Contract$/MMBtu(Current Year)
As of February 1, 2024, Alvopetro’s contracted natural gas price under the terms of our long-term gas sales agreement is based on the ceiling price within the contract. Pricing is forecast to stay slightly below the ceiling for future price adjustments. The ceiling price incorporates assumed US inflation of 2%.
GLJ RESERVES AND RESOURCES REPORT
The GLJ Reserves and Resources Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) that are consistent with the standards of National Instrument 51-101 (“NI 51-101”). GLJ is a qualified reserves evaluator as defined in NI 51-101. The GLJ Reserves and Resources Report was an evaluation of all reserves of Alvopetro including our working interest share as of December 31, 2023 of the Unit (referred to herein as the Caburé natural gas field), our Murucututu natural gas project, as well as our Bom Lugar and Mãe-da-lua oil fields. The GLJ Reserves and Resources Report also includes an evaluation of the gas resources of our Murucututu natural gas field. In addition to the reserves assigned to our Murucututu field, contingent resource was assigned to the area in proximity to our existing Murucututu reserves, deemed to be discovered. The area mapped by 3D seismic west and north of the area defined as contingent was assigned prospective resource. Additional reserves and resources information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2023 fiscal year which will be filed on SEDAR+ (www.sedarplus.ca) by April 30, 2024.
December 31, 2023 Reserves Information:
Summary of Reserves (1)(2)(3)
Light & Medium Oil
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
Company Gross
Company Net
Company Gross
Company Net
Company Gross
Company Net
Company Gross
Company Net
(Mbbl)
(Mbbl)
(MMcf)
(MMcf)
(Mbbl)
(Mbbl)
(Mboe)
(Mboe)
Proved
Producing
8
7
11,460
11,000
122
117
2,039
1,957
Developed Non-Producing
142
133
–
–
–
–
142
133
Undeveloped
–
–
2,951
2,818
54
52
546
522
Total Proved
150
140
14,411
13,818
176
169
2,727
2,612
Probable
302
285
31,175
29,859
486
465
5,983
5,726
Total Proved plus Probable
451
425
45,586
43,677
662
634
8,711
8,338
Possible
224
211
34,253
32,785
565
540
6,497
6,215
Total Proved plus Probable plus Possible
675
635
79,839
76,462
1,226
1,174
15,208
14,553
See ‘Footnotes’ section at the end of this news release
Summary of Before Tax Net Present Value of Future Net Revenue – $000s(1)(2)(3)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Proved
Producing
114,762
106,922
100,204
94,364
89,230
Developed Non-Producing
6,337
5,157
4,257
3,570
3,040
Undeveloped
18,155
14,371
11,425
9,181
7,467
Total Proved
139,254
126,450
115,886
107,115
99,738
Probable
391,202
263,064
193,771
151,218
122,597
Total Proved plus Probable
530,456
389,514
309,657
258,333
222,335
Possible
538,835
271,641
172,416
124,475
96,580
Total Proved plus Probable plus Possible
1,069,291
661,155
482,073
382,808
318,915
See ‘Footnotes’ section at the end of this news release
Summary of After Tax Net Present Value of Future Net Revenue – $000s(1)(2)(3)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Proved
Producing
107,434
100,320
94,209
88,886
84,200
Developed Non-Producing
5,623
4,552
3,728
3,098
2,613
Undeveloped
14,191
11,454
9,192
7,412
6,022
Total Proved
127,248
116,326
107,129
99,396
92,834
Probable
297,522
205,240
153,457
120,748
98,250
Total Proved plus Probable
424,769
321,565
260,586
220,145
191,085
Possible
388,926
204,696
133,885
98,386
77,076
Total Proved plus Probable plus Possible
813,695
526,262
394,471
318,531
268,160
See ‘Footnotes’ section at the end of this news release
Future Development Costs (1)(2)(3)(7)(8)
The table below sets out the total development costs deducted in the estimation of future net revenue attributable to proved reserves, proved plus probable reserves and proved plus probable plus possible reserves (using forecast prices and costs), by field, in the GLJ Reserves and Resources Report. Total development costs include capital costs for drilling and completing wells and for facilities but excludes abandonment and reclamation costs.
The future development costs for the Caburé field include Alvopetro’s working interest share (49.1%) for three development wells in the proved category and an additional two development wells in the probable and possible categories. Also included in future development costs for Caburé are costs associated with a facilities upgrade planned at the field for compression of natural gas to be delivered to Alvopetro’s natural gas processing facility. In prior years, Alvopetro reflected all equipment rental payments associated with our Gas Treatment Agreement with Enerflex Ltd. as part of future development costs; however in 2023, such costs are now incorporated within operating expense along with other operating costs associated with the agreement. The future costs associated with equipment rental are also reflected as a capital lease obligation on our financial statements.
The future development costs for the Murucututu field in the proved category include one development well and stimulation costs for the 183-1 and 183-A3 wells and one project to improve recovery from the 197(1) well. The probable category also includes an additional two development wells along with additional stimulation projects at the 183-1 and 183-A3 wells. The possible category includes one additional well.
The future development costs for Bom Lugar in the proved category include costs to stimulate the BL-06 well drilled by Alvopetro in 2023. Costs in the probable category also include one development well and costs for facilities upgrade. Future development costs at the Mãe-da-lua field relate to a stimulation of the existing producing well.
Alvopetro’s share of future development costs are summarized as follows:
$000s, Undiscounted
2024
2025
2026
2027
2028
Remaining
Total
Proved
Caburé Natural Gas Field
6,993
–
–
–
–
–
6,993
Murucututu Gas Field
2,050
6,885
–
–
–
–
8,935
Bom Lugar Oil Field
–
510
–
–
–
–
510
Mãe-da-lua Oil Field
–
551
–
–
–
–
551
Total Proved
9,043
7,946
–
–
–
–
16,989
Proved Plus Probable
Caburé Natural Gas Field
6,993
2,504
–
–
–
–
9,497
Murucututu Gas Field
3,950
20,655
–
–
–
–
24,605
Bom Lugar Oil Field
–
6,059
–
–
–
–
6,059
Mãe-da-lua Oil Field
–
551
–
–
–
–
551
Total Proved Plus Probable
10,943
29,769
–
–
–
–
40,712
Proved Plus Probable Plus Possible
Caburé Natural Gas Field
6,993
2,504
–
–
–
–
9,497
Murucututu Gas Field
3,950
27,540
–
–
–
–
31,490
Bom Lugar Oil Field
–
6,059
–
–
–
–
6,059
Mãe-da-lua Oil Field
–
551
–
–
–
–
551
Total Proved Plus Probable Plus Possible
10,943
36,654
–
–
–
–
47,597
See ‘Footnotes’ section at the end of this news release
Reconciliation of Alvopetro’s Gross Reserves (Before Royalty) (1)(2)(3)(8)
Proved(Mboe)
Probable(Mboe)
Proved Plus Probable(Mboe)
Possible(Mboe)
Proved plusProbable plus Possible(Mboe)
December 31, 2022
3,909
5,128
9,037
5,345
14,382
Discoveries
–
1,398
1,398
2,488
3,886
Extensions
–
148
148
(148)
–
Technical Revisions
(400)
(690)
(1,090)
(1,188)
(2,278)
Production
(782)
–
(782)
–
(782)
December 31, 2023
2,727
5,983
8,711
6,497
15,208
See ‘Footnotes’ section at the end of this news release.
December 31, 2023 Murucututu Contingent Resources Information:
Summary of Unrisked Company Gross Contingent Resources (1)(2)(5)(6)
Development Pending Economic Contingent Resources
Low Estimate
Best Estimate
High Estimate
Conventional natural gas (MMcf)
20,952
32,062
35,433
Natural gas liquids (Mbbl)
386
591
653
Oil equivalent (Mboe)
3,878
5,935
6,559
See ‘Footnotes’ section at the end of this news release.
Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Contingent Resources- $000s (1)(2)(5)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
279,201
146,114
91,400
63,327
46,651
Best Estimate
470,246
226,624
139,760
97,612
73,016
High Estimate
540,860
246,103
148,348
102,781
76,691
See ‘Footnotes’ section at the end of this news release.
The GLJ Contingent Resource Report for Murucututu assumes capital deployment starting in 2025 for the drilling and completion of wells with total project costs of $20.8 million and first commercial production in 2025. The information presented herein is based on company net project development costs. The recovery technology assumed for purposes of the estimate is based on established technologies utilized repeatedly in the industry.
There can be no certainty that the project will be developed on the timelines discussed herein. The project is based on a pre-development study. Development of the project is dependent on several contingencies as further described in this news release. Significant positive factors relevant to the estimate include existing production in close proximity, proximity to infrastructure, existing long-term gas sales agreement and corporate commitment to the project. Significant negative factors relevant to the estimate include reservoir performance and the economic viability of the project (with sensitivity to low commodity prices), access to and amount of capital required to develop resources at an acceptable cost, and regulatory approvals for planned activities including stimulations and new infrastructure developments.
Summary of Development Pending Risked Company Gross Contingent Resources(1)(2)(5)(6)
The GLJ Reserves and Resources Report estimates the Chance of Development as the product of two main contingencies associated with the project development, which are: 1) the probability of corporate sanctioning, which GLJ estimates at 95%; 2) the probability of finalization of a development plan, which GLJ estimates at 95%. The product of these two contingencies is 90%. As there is no risk related to discovery, the Chance of Commerciality for the contingent resource is therefore 90% which is the risk factor that has been applied to the Development Risked company gross contingent resources and the net present value figures reported below.
Low Estimate
Best Estimate
High Estimate
Conventional natural gas (MMcf)
18,909
28,936
31,978
Natural gas liquids (Mbbl)
349
533
590
Oil equivalent (Mboe)
3,500
5,356
5,919
See ‘Footnotes’ section at the end of this news release.
Summary of Development Pending Risked Before Tax Net Present Value of Future Net Revenue of Contingent Resources- $000s(1)(5)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
251,978
131,868
82,489
57,153
42,102
Best Estimate
424,397
204,528
126,134
88,095
65,897
High Estimate
488,126
222,108
133,884
92,760
69,214
See ‘Footnotes’ section at the end of this news release.
December 31, 2023 Murucututu Prospective Resources Information:
Summary of Unrisked Company Gross Prospective Resources (1)(2)(4)(6)
Prospective Resources
Low
Best
High
Conventional natural gas (MMcf)
31,903
64,251
101,392
Natural gas liquids (Mbbl)
588
1,184
1,869
Oil equivalent (Mboe)
5,905
11,893
18,768
See ‘Footnotes’ section at the end of this news release.
Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Prospective Resources – $000s (1)(4)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
395,126
179,911
96,052
56,094
34,354
Best Estimate
959,658
413,788
227,919
142,785
96,201
High Estimate
1,628,234
680,308
376,039
240,051
165,845
See ‘Footnotes’ section at the end of this news release.
The GLJ Reserves and Resources Report for Murucututu prospective resources assumes capital deployment starting in 2026 for the drilling and completion of wells and pipeline expansion costs, with total project costs of $75.8 million and first commercial production in 2026. The information presented herein is based on company project development costs. The recovery technology assumed for purposes of the estimate is based on established technologies utilized repeatedly in the industry.
There can be no certainty that the project will be developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release. The project is based on a conceptual study. Significant positive factors relevant to the estimate include existing production in close proximity, proximity to infrastructure, existing long-term gas sales agreement and corporate commitment to the project. Significant negative factors relevant to the estimate include reservoir performance and the economic viability of the project (with sensitivity to low commodity prices), access to and amount of capital required to develop resources at an acceptable cost, and regulatory approvals for planned activities including stimulations and new infrastructure developments.
Summary of Development Risked Company Gross Prospective Resources(1)(2)(4)(6)
The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.
Low
Best
High
Conventional natural gas (MMcf)
25,876
52,112
82,237
Natural gas liquids (Mbbl)
477
961
1,516
Oil equivalent (Mboe)
4,790
9,646
15,222
See ‘Footnotes’ section at the end of this news release.
Summary of Development Risked Before Tax Net Present Value of Future Net Revenue of Prospective Resources- $000s(1)(4)(6)(7)(8)
Undiscounted
5 %
10 %
15 %
20 %
Low Estimate
320,477
145,922
77,906
45,497
27,864
Best Estimate
778,356
335,614
184,859
115,810
78,027
High Estimate
1,320,623
551,782
304,997
194,700
134,513
See ‘Footnotes’ section at the end of this news release.
Upcoming 2023 Results and Live Webcast
Alvopetro anticipates announcing its 2023 fourth quarter and year-end results on March 19, 2024 after markets close and will host a live webcast to discuss the results at 8:00am Mountain time, on March 20, 2024. Details for joining the event are as follows:
The webcast will include a question-and-answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to socialmedia@alvopetro.com.
References to Company Gross reserves or Company Gross Resources means the total working interest share of remaining recoverable reserves or resources held by Alvopetro before deductions of royalties payable to others and without including any royalty interests held by Alvopetro. With respect to the Caburé natural gas field, Alvopetro’s working interest was 49.1% as of December 31, 2023 but is subject to redetermination, the first of which is currently underway. The outcome of this redetermination is unknown and the resulting impact on the reserves presented herein may be material.
(2)
The tables above are a summary of the reserves of Alvopetro and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Reserves and Resources Report based on forecast price and cost assumptions. The tables summarize the data contained in the GLJ Reserves and Resources Report and as a result may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
(3)
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
(4)
Prospective Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery as described in footnote 6.
(5)
Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates as described in footnote 6 and may be subclassified based on project maturity and/or characterized by their economic status. The Contingent Resources estimated in the GLJ Reserves and Resources Report are classified as “economic contingent resources”, which are those contingent resources that are currently economically recoverable. All such resources are further sub-classified with a project status of “development pending”, meaning that resolution of the final conditions for development are being actively pursued. The recovery estimates of the Company’s contingent resources provided herein are estimates only and there is no guarantee that the estimated resources will be recovered. There is uncertainty that it will be commercially viable to produce any portion of the resources. Actual recovered resource may be greater than or less than the estimates provided herein.
(6)
Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
(7)
The net present value of future net revenue attributable to Alvopetro’s reserves and resources are stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, well abandonment and reclamation costs for only those wells assigned reserves and material dedicated gathering systems and facilities. The net present values of future net revenue attributable to Alvopetro’s reserves and resources estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve and resource estimates of the Company’s reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves and resources will be recovered. Actual reserves and resources may be greater than or less than the estimates provided herein.
(8)
GLJ’s January 1, 2024 escalated price forecast is used in the determination of future gas sales prices under Alvopetro’s long-term gas sales agreement and for all forecasted oil sales and natural gas liquids sales. See https://www.gljpc.com/sites/default/files/pricing/Jan24.pdf for GLJ’s price forecast.
Alvopetro Energy Ltd.’svision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this news release are in United States dollars, except as otherwise noted.
Abbreviations:
1P
=
proved reserves
2P
=
proved plus probable reserves
3P
=
proved plus probable plus possible reserves
Mbbl
=
thousands of barrels
Mboe
=
thousand barrels of oil equivalent
MMbtu
=
million British Thermal Units
MMcf
=
million cubic feet
MMboe
=
million barrels of oil equivalent
$000s
=
thousands of U.S. dollars
Oil and Natural Gas Advisories
Oil and Natural Gas Reserves
The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company’s reserves as at December 31, 2023 will be included in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024. The GLJ Reserves and Resources Report incorporates Alvopetro’s working interest share of remaining recoverable reserves and resources. With respect to the Caburé natural gas field, Alvopetro’s working interest was 49.1% as of December 31, 2023 but is subject to redetermination, the first of which is currently underway. The outcome of this redetermination is unknown and the resulting impact on the reserves and the net presented value of future net revenue attributable to such reserves as presented herein may be material.
All net present values in this press release are based on estimates of future operating and capital costs and GLJ’s forecast prices as of December 31, 2023. The reserves definitions used in this evaluation are the standards defined by COGEH reserve definitions and are consistent with NI 51-101 and used by GLJ. The net present values of future net revenue attributable to the Alvopetro’s reserves estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Contingent Resources
This news release discloses estimates of Alvopetro’s contingent resources and the net present value associated with net revenues associated with the production of such contingent resources as included in the GLJ Reserves and Resources Report. There is no certainty that it will be commercially viable to produce any portion of such contingent resources and the estimated future net revenues do not necessarily represent the fair market value of such contingent resources. Estimates of contingent resources involve additional risks over estimates of reserves. Full disclosure with respect to the Company’s contingent resources as at December 31, 2023 will be contained in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024.
Prospective Resources
This news release discloses estimates of Alvopetro’s prospective resources included in the GLJ Reserves and Resources Report. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Estimates of prospective resources involve additional risks over estimates of reserves. The accuracy of any resources estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While resources presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Full disclosure with respect to the Company’s prospective resources as at December 31, 2023 will be contained in the Company’s annual information form for the year ended December 31, 2023 which will be filed on SEDAR+ (www.sedarplus.ca) on or before April 30, 2024.
Boe Disclosure
The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.
Forward-Looking Statements and Cautionary Language
This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the redetermination and Alvopetro’s working interest share of the unitized area and the potential impact of the redetermination on Alvopetro, plans relating to the Company’s operational activities, proposed development activities and the timing for such activities, capital spending levels and future capital costs, the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement. The forward‐looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to expectations and assumptions concerning the timing of regulatory licenses and approvals, equipment availability, the success of future drilling, completion, testing, recompletion and development activities, the performance of producing wells and reservoirs, well development and operating performance, expectations regarding Alvopetro’s working interest and the outcome of any redeterminations, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the outlook for commodity markets and ability to access capital markets, foreign exchange rates, general economic and business conditions, the impact of the COVID-19 pandemic, weather and access to drilling locations, the availability and cost of labour and services, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR+ profile at www.sedarplus.ca). The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Energy Fuels is a leading U.S.-based uranium mining company, supplying U3O8 to major nuclear utilities. Energy Fuels also produces vanadium from certain of its projects, as market conditions warrant, and is ramping up commercial-scale production of REE carbonate. Its corporate offices are in Lakewood, Colorado, near Denver, and all its assets and employees are in the United States. Energy Fuels holds three of America’s key uranium production centers: the White Mesa Mill in Utah, the Nichols Ranch in-situ recovery (“ISR”) Project in Wyoming, and the Alta Mesa ISR Project in Texas. The White Mesa Mill is the only conventional uranium mill operating in the U.S. today, has a licensed capacity of over 8 million pounds of U3O8 per year, has the ability to produce vanadium when market conditions warrant, as well as REE carbonate from various uranium-bearing ores. The Nichols Ranch ISR Project is on standby and has a licensed capacity of 2 million pounds of U3O8 per year. The Alta Mesa ISR Project is also on standby and has a licensed capacity of 1.5 million pounds of U3O8 per year. In addition to the above production facilities, Energy Fuels also has one of the largest NI 43-101 compliant uranium resource portfolios in the U.S. and several uranium and uranium/vanadium mining projects on standby and in various stages of permitting and development. The primary trading market for Energy Fuels’ common shares is the NYSE American under the trading symbol “UUUU,” and the Company’s common shares are also listed on the Toronto Stock Exchange under the trading symbol “EFR.” Energy Fuels’ website is www.energyfuels.com.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Energy Fuels reported financial results for the quarter and the year that were largely expected. Earnings for 2024 were $99.8 million or $0.62 per share. However, the positive results were due to a $119 million or $0.73 per share nonrecurring gain on the sale of property. Excluding the sale, the company would have reported a $20 million or $0.12 per share loss for the year. Quarterly losses were slightly higher than expected on limited sales.
Energy Fuel’s liquidity position has grown dramatically in recent quarters. As of December 31, 2023, the company had $222.34 million of working capital and no debt. With such a large liquidity position, the company is well positioned to expand operations without seeking external financing. This includes restarting uranium mining operations but could also fund all or most of the proposed REE Oxide circuit expansion.
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This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
Vancouver, British Columbia–(Newsfile Corp. – February 21, 2024) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce that it has been named as one of the top performers on the TSX Venture Exchange (“TSXV”) for the third consecutive year.
The 2024 TSXV 50 showcases the top 50 of over 1,600 TSXV issuers across five sectors: energy, mining, clean technology, life sciences, diversified industries, and technology. The ranking is an equal weighting of each company’s performance during 2023 across three key indicators: market capitalization growth, share price appreciation, and trading volume. More details can be found at the following link: www.tsx.com/venture50.
“We are proud to earn a ranking on the 2024 TSXV Venture 50 list for the third consecutive year,” said Don Simmons, President and Chief Executive Officer of Hemisphere. “The Company has continued to take great strides in growing its operations over the past year while maintaining a strong balance sheet and focusing heavily on return of capital to its shareholders.”
About Hemisphere Energy Corporation
Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.
For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
The uranium spot price has crossed a major threshold, surging past $100/lb in January 2024 to reach $106.51/lb in early February. This long-awaited milestone marks the first time uranium has hit triple digits since the bull run leading up to the 2008 financial crisis.
The implications of breaching $100/lb are significant for the uranium market. Prices at this level indicate the serious supply and demand imbalances that have characterized the market for years are finally coming to a head. With demand outpacing available supply from mines, traders see uranium poised for further gains still.
The main driver behind January’s price spike was a cut to production forecasts from Kazatomprom, the world’s largest uranium miner. The company stunned the market by announcing lower guidance for 2024 and 2025 due to shortages of a key chemical and construction delays. This reversal came just months after Kazatomprom had planned to boost output to meet rising demand. The supply uncertainty led uranium prices to immediately jump over 8%.
For investors, Kazatomprom’s about-face signals that the supply response to uranium’s bull run may proceed slower than expected. Mine expansions and restarts are lagging, with not enough incentive yet for substantial new production. The supply picture is further complicated by uncertainty around Niger’s uranium exports following a coup there last year.
Junior uranium miners have been the biggest winners from the bullish momentum. With less exposure to long-term contracts than larger producers, juniors are benefiting from the full upside of rising spot prices. Many have announced restarts of idled capacity to take advantage of the favorable pricing environment. Their outsized gains indicate investors see juniors playing a key role in bridging future supply shortfalls.
Reaching the $100/lb mark is a psychological victory for uranium bulls who have waited years for prices to reflect positive fundamentals. Nuclear energy demand is on the rise again amid its role in carbon-free baseload power. With most forecast models predicting large supply deficits opening up over the next decade, there is a growing sense $100/lb is just the beginning.
Past experience shows reaching this triple-digit territory is when utilities truly start getting worried about security of supply. The last time uranium crossed above $100/lb in 2007, it sparked a frenzy of long-term contracting not seen before or since. While contracting volumes picked up last year, they remain below levels to fully cover global reactor requirements.
Many see $100/lb as the price needed to incentivize meaningful new mine production. Bringing large-scale conventional projects online takes over a decade when factoring in permitting and construction. Even smaller ISR operations can take several years to expand. With demand projected to outstrip supply for years to come, prices above $100/lb may be the new normal rather than an unsustainable spike.
For investors, uranium crossing $100/lb should serve as a wake-up call that a structural bull market is unfolding. Uranium has significantly outperformed most other commodity sectors over the past several years. With demand still rising and enormous lead times for new projects, supply shortfalls won’t be reversed overnight.
Now is the time for investors to gain exposure before uranium potentially keeps running toward new highs. Uranium equities offer upside well beyond movements in the underlying commodity price. Juniors in particular stand to see valuations explode higher if they can continue locking in contracts above $100/lb.
While nothing moves up forever, the fundamentals underpinning uranium’s surge past $100/lb look here to stay. Nuclear reactors need reliable fuel supply. Achieving net-zero carbon emissions globally depends on nuclear generation ramping up. With mines struggling to keep pace, all signs point to the uranium bull market having ample room left to run at these levels and beyond.
The mining sector has experienced boom and bust cycles throughout history, but current trends suggest we may be entering a new era of growth and opportunity. With the world transitioning to clean energy and electric vehicles, demand is surging for key minerals like lithium, cobalt, nickel and copper. This creates an attractive investment case for the mining sector.
Historic Trends
Looking back, the mining industry has gone through periods of rapid expansion and painful contraction. During economic expansions and commodity bull markets, mining companies ramp up exploration, development and production to capitalize on high prices. This leads to oversupply and when demand eventually weakens, the cycle turns downward.
We saw this play out in dramatic fashion over the past decade. High prices in the 2000s encouraged massive investment in new mines and supply capacity. But when Chinese growth began to slow around 2012, demand weakened and prices collapsed. The mining sector was forced to drastically cut back on production and capital investment.
Many mining companies barely stayed afloat during this bust period. But this reduction in supply helped set the stage for the next upcycle. Now, after years of underinvestment, mines are depleting reserves faster than they are being replenished. With commodity demand picking up again, conditions are ripe for the next mining boom.
Current Market Trends
Several key trends suggest we are now in the early stages of a new mining upcycle:
Electric vehicle revolution – EV adoption is accelerating around the world, dramatically increasing demand for lithium, cobalt, nickel, copper and other key minerals. Total EV sales increased 70% in 2021 and are projected to rise more than 5-fold by 2030. This will require a massive increase in mineral supply.
Renewable energy expansion – Solar, wind and other renewables are seeing surging growth as countries aim to cut carbon emissions. This further increases metals demand for batteries, transmission lines, wiring and other components.
Supply chain vulnerabilities – The pandemic and geopolitics have exposed risks of relying on a few key countries for critical mineral supply. Governments are now focused on developing domestic mining capacity to ensure supply security.
Decarbonization efforts – Reaching net zero emissions will require a staggering volume of minerals for clean energy infrastructure buildout. Models estimate needing 30 times more lithium and 15 times more cobalt by 2040.
These trends all point to a pending boom in mining investment and production. The demand outlook has fundamentally shifted in a more positive direction.
For investors, this macro backdrop presents an opportunity to capitalize on the coming mining supercycle. Some ways to gain exposure include:
Lithium mining stocks – Lithium prices have skyrocketed 10-fold in the past two years as demand for electric vehicle batteries has soared. Leading lithium miners like Albemarle, SQM and Livent are seeing their earnings multiply. They are investing heavily to aggressively expand production capacity to ride the lithium boom. Their stocks still may have substantial upside given the tight supply and surging demand forecasts.
Nickel and cobalt miners – Clean energy technologies like batteries require vast amounts of nickel and cobalt. Both metals face looming supply deficits. Miners expanding production such as Glencore, Sherritt International and Giga Metals stand to benefit enormously from surging demand and higher prices over the coming decade. These miners offer some of the best leverage to capitalize on the EV battery revolution.
Copper miners – Copper is essential for global electrification and will be required by the millions of tons for EV charging networks, power grids, wiring and electronics. Leading copper miners like Freeport McMoRan, Southern Copper and First Quantum Minerals offer direct exposure to higher copper prices. Many are expanding production while also paying healthy dividends.
Diversified mining majors – Large diversified miners like BHP, Rio Tinto and Vale mine a broad mix of commodities from copper and iron ore to coal and potash. Their diversification provides stability while still benefiting from the overall minerals boom. These global giants pay some of the highest dividends in the market.
Junior mining stocks – Earlier stage mining companies developing new projects provide extreme upside potential leverage but also greater risk. Conduct thorough due diligence on management track record, finances, permitting status and feasibility studies before investing.
Physical gold and silver – Precious metals like gold and silver can provide a hedge against market volatility. Buying physical coins and bars or investing in ETFs offers exposure. Just a small allocation of 5-10% can help balance a portfolio.
Mining ETFs – Funds like the Global X Lithium ETF (LIT), VanEck Vectors Gold Miners ETF (GDX) and SPDR Metals & Mining ETF (XME) provide diversified exposure to mining stocks and commodities. This simplifies investing in the sector.
With mining poised to boom, investors have many options to position for the coming supercycle. As with any investment, proper due diligence and risk management remain critical. But the macro trends point to a bright future for mining stocks. For investors, now may be the ideal time to position for the coming mining supercycle.
Oil prices are on track to post gains this week, driven higher by geopolitical tensions in the Middle East despite ongoing concerns about still high inflation and a cloudy demand outlook.
West Texas Intermediate crude futures have risen approximately 2% week-to-date and were trading around $78 per barrel on Friday. Brent crude, the international benchmark, was up 1.8% on the week to $83 per barrel.
According to analysts, speculative traders and funds are bidding up oil futures based on worries that simmering conflicts in the Middle East could disrupt global supplies. Volatility and uncertainty in the region tends to spur speculative trading in oil markets.
“This is geopolitics with flashing flights, it points right to specs taking advantage of the situation,” said Bob Yawger, managing director at Mizuho America. “They’re rolling the dice expecting something will happen.”
Tensions have escalated on the border between Israel and Lebanon after Israel conducted airstrikes in southern Lebanon this week in retaliation for rocket attacks from the area. The powerful Lebanese militia Hezbollah has vowed to strike back against Israel in response.
There are worries the Israel-Lebanon clashes could spread to a wider conflict, potentially including Israel’s ongoing offensive in Gaza. This could disrupt oil production or transit through the critical Suez Canal. The Middle East accounted for nearly 30% of global oil production last year.
Prices Shake Off Demand Worries
Notably, crude prices have shaken off downward pressure this week from stubbornly high inflation as well as forecasts for weaker demand growth in 2024.
US consumer and wholesale inflation reports this week came in hotter than expected. Persistently high inflation reduces the chances of the Federal Reserve pivoting to interest rate cuts this year which could otherwise boost oil demand.
Demand outlooks for 2024 have also been murky. The International Energy Agency (IEA) downwardly revised its 2024 oil demand growth forecast to 1.2 million barrels per day, half of 2023’s pace. It sees supply growth outpacing demand this year.
However, OPEC offered a more bullish view in its latest report, projecting world oil demand will increase by 2.2 million barrels per day in 2024. The cartel sees demand growth exceeding non-OPEC supply growth.
Investors Shake Off Bearish Signals
Given the conflicting demand forecasts, the resilience of oil prices likely reflects investor optimism over tightening fundamentals outweighing potentially bearish signals.
“There is and has been a yawning chasm in demand estimates,” said Tamas Varga, analyst at PVM brokerage. “The difference of opinions in global oil consumption for this year and the individual quarters, even for the current one, is clearly puzzling.”
Ultimately, lingering Middle East geopolitical risks appear to be overshadowing inflation and demand concerns in driving investor sentiment. With tensions still elevated, investors seem positioned for further volatility and potential price spikes on any supply disruptions.
The diverging demand forecasts and data points mean uncertainty persists around whether markets will tighten as much as OPEC expects or remain oversupplied per the IEA outlook. But with inventories still low by historical standards, prices have room to run higher on any bullish shocks.
What’s Next For Oil Markets
Looking ahead, Middle East tensions, China’s reopening, and the extent of Fed rate hikes will be key drivers of oil price trends. Any military escalation or supply disruptions from the Israel-Lebanon tensions could send crude prices spiking higher.
China’s demand recovery as it exits zero-Covid policies will also remain in focus. Signs of China’s crude imports and manufacturing activity reviving could offer a bullish boost to prices.
At the same time, stubborn inflation likely keeps the Fed on track for further rate hikes in the near term. Only clear signs of slowing price growth might promptdiscussion of rate cuts to stimulate growth. For now, Fed policy looks set to weigh on oil demand and limit significant upside.
Overall, investors should brace for continued volatility in oil markets in 2024. While prices may trend higher on tight supplies, lingering demand uncertainties and geo-political tensions look set to drive choppy price action. Nimble investors able to capitalize on price spikes and dips may find opportunities. But those with a lower risk tolerance may wish to stay on the sidelines until fundamentals stabilize.
Texas-based Diamondback Energy announced Monday that it will purchase Endeavor Energy Partners, the largest privately held oil and gas producer in the prolific Permian Basin, in a cash-and-stock deal valued at approximately $26 billion including debt.
The deal represents one of the largest energy sector acquisitions announced so far in 2024 and highlights the ongoing consolidation in the Permian as companies seek scale and improved efficiencies. Once completed, the merged company will be the third-largest producer in the basin behind only oil majors ExxonMobil and Chevron.
“Diamondback has proven itself to be a premier low-cost operator in the Permian Basin over the last 12 years, and this combination allows us to bring this cost structure to a larger asset base and allocate capital to a stronger pro forma inventory position,” said Travis Stice, CEO of Diamondback, in a statement.
The combined company is projected to pump 816,000 barrels of oil equivalent per day (boepd), with Diamondback estimating $550 million in annual cost savings. Diamondback shareholders will own approximately 60.5% of the new entity, while Endeavor owners will hold the remaining 39.5% stake.
The Permian Basin is located in West Texas and southeastern New Mexico. Technological advances in hydraulic fracturing and horizontal drilling have transformed the Permian into the most prolific oil field in the United States, responsible for about 40% of the country’s crude output.
Endeavor operates in the Midland sub-basin on the Texas side of the Permian, with its acreage located adjacent to existing Diamondback properties. This geographic overlap should allow for significant synergies as the companies integrate operations, infrastructure and drilling inventory.
Diamondback management highlighted Endeavor’s status as one of the Permian’s lowest-cost producers as a key rationale behind the acquisition. Folding Endeavor’s assets into Diamondback’s portfolio should lower overall expenses and boost cash flow on a per-share basis.
The merged company will hold approximately 1.1 million net acres in the Permian Basin and control over 2 billion barrels of recoverable oil equivalent resources. This expanded footprint provides enhanced scale for Diamondback to fund further development.
“This combination allows us to bring this cost structure to a larger asset base and allocate capital to a stronger pro forma inventory position,” noted Stice.
While offering enticing synergies, the partnership also carries risks if oil prices decline significantly from current levels near $80 per barrel. Diamondback is assuming roughly $7 billion of Endeavor’s debt as part of the transaction.
However, the substantial cost efficiencies and expanded production capacity position the newly merged business well for strong free cash flow generation, even in a lower price environment.
The deal is expected to close in Q4 2024 after customary approvals. Shares of Diamondback were up nearly 3% in Monday morning trading on news of the acquisition. The transaction continues the consolidation wave among Permian Basin independents as companies strive to improve margins and gain scale.
For Diamondback, the bold bet on Endeavor represents an opportunity to solidify its status as a Permian leader, while acquiring premium assets that should drive growth for years to come. The combined corporation will boast immense resources, significant capital flexibility and a management team with a proven track record in the basin.
