Key Points: – Brent crude oil prices are rising as markets speculate on a potential Israeli strike against Iran’s oil infrastructure, particularly Kharg Island, which handles 90% of Iran’s crude exports. – A worst-case scenario would involve disruption in the Strait of Hormuz, a critical passage for 20% of the world’s crude oil exports, which could cause a dramatic spike in oil prices. – While OPEC+ has enough spare capacity to offset supply disruptions from an Israeli strike, it may struggle if Iran retaliates, adding further uncertainty to the energy markets.
Brent crude oil extended its gains today, driven by rising fears that Israel could launch a retaliatory strike on Iran’s oil infrastructure following Tehran’s recent ballistic missile attack. Markets are increasingly concerned that such an attack could disrupt the flow of oil from one of the world’s most critical regions for crude exports.
Concerns Over Key Oil Choke Points
Israel’s retaliation, though not yet clearly defined, has analysts worried about the potential impact on Iran’s oil exports, especially if Israel targets Kharg Island, where 90% of Iran’s crude oil exports pass through. A strike there would have significant consequences on global oil supply, sending prices higher. However, the worst-case scenario would involve a strike on the Strait of Hormuz, through which 20% of the world’s crude oil flows, which would cause a dramatic spike in crude prices.
U.S. President Joe Biden has urged Israel to avoid targeting Iranian oil facilities, following his previous opposition to a strike on Iran’s nuclear sites.
Oil Prices Surge on Market Speculation
Brent crude prices surged last week, marking the steepest increase since early 2023. Activity in the options market has also shown increased demand for hedging against the risk of further gains, reflecting market fears of a supply disruption. Despite these gains, Brent crude is still trading below last year’s price of $88 per barrel, when the current conflict in the Middle East began.
OPEC+ Supply and Market Outlook
As OPEC+ prepares to raise production in December following years of output cuts, analysts believe the group has enough spare capacity to offset any supply disruptions caused by an Israeli attack on Iranian oil facilities. However, concerns linger that OPEC+ could face challenges if Iran retaliates, potentially leading to further volatility in oil markets.
While some analysts see an attack on Iranian oil infrastructure as a less likely response from Israel, the broader geopolitical tensions and risks of wider conflict are adding uncertainty to the energy markets.
Crude oil prices have spiked nearly 3% as geopolitical tensions in the Middle East escalate and Libya halts its oil production. This sudden surge has caught the attention of investors worldwide, potentially signaling a shift in the energy market landscape.
West Texas Intermediate (WTI) crude jumped to over $77 per barrel, while Brent crude, the international benchmark, surpassed $80 per barrel. This sharp increase comes after a weekend of heightened tensions in the Middle East and a significant disruption in Libyan oil production.
The catalyst for this price surge appears to be twofold. First, Israel’s recent airstrike against Hezbollah’s rocket launching stations in Lebanon has exacerbated fears of a broader conflict involving Iran. The potential for Iranian military response has raised concerns about possible disruptions to global oil movements, a factor that could significantly impact supply chains and pricing.
Adding fuel to the fire, Iran-backed Houthi rebels continue their attacks on vessels in the Red Sea, with a Greek oil tanker being the latest casualty. These ongoing hostilities pose a substantial threat to one of the world’s most crucial shipping routes, potentially disrupting oil transportation and further tightening supply.
The second major factor driving oil prices higher is Libya’s decision to temporarily halt its oil production and exports. This move, prompted by a dispute over the leadership of Libya’s central bank, removes over 1 million barrels of daily crude production from the global market. The sudden supply shock has left traders scrambling to adjust their positions, contributing to the price surge.
For investors, these developments present both opportunities and risks. The energy sector, which has been under pressure due to concerns about global demand, may see a resurgence if oil prices continue their upward trajectory. Oil majors and exploration companies could benefit from higher crude prices, potentially boosting their profit margins and stock valuations.
However, the situation remains fluid. While oil prices have jumped over 5% in the past three sessions, long-term demand concerns still linger in the market. The global economic outlook, particularly in China, continues to cast a shadow over future oil demand projections.
Interestingly, despite the surge in crude prices, U.S. gasoline prices have continued their downward trend. The national average gasoline price currently hovers around $3.35 per gallon, significantly lower than both last month and last year. Industry experts attribute this to seasonal factors and expectations of reduced demand post-Labor Day.
Looking ahead, investors should keep a close eye on several key factors:
Developments in the Middle East, particularly any escalation involving Iran.
Libya’s oil production status and any potential resolution to the current dispute.
OPEC+ decisions on future production levels.
Global economic indicators, especially from major oil consumers like China and the U.S.
Hurricane season’s impact on U.S. Gulf oil production.
While the current price surge may offer short-term opportunities, prudent investors will need to weigh these against longer-term trends in oil demand and the ongoing global transition towards renewable energy sources.
As always, diversification and careful risk management remain key in navigating the volatile energy markets. With geopolitical tensions high and supply disruptions ongoing, the oil market promises to be an area of keen interest for investors in the coming weeks and months.
In a surprising turn of events, oil prices have climbed for the second consecutive session, with Brent crude settling above $85 per barrel. This uptick comes as hopes for U.S. interest rate cuts were fueled by an unexpected slowdown in inflation. The market’s reaction to these economic indicators highlights the intricate connections between macroeconomic factors and commodity prices.
The latest data from the U.S. Bureau of Labor Statistics revealed a decline in consumer prices for June. This unexpected drop has boosted expectations that the Federal Reserve might cut interest rates sooner than anticipated. Following the release of the inflation data, traders saw an 89% chance of a rate cut in September, up from 73% the day before. Slowing inflation and potential rate cuts are expected to spur more economic activity. Analysts from Growmark Energy have noted that such measures could bolster economic growth, subsequently increasing demand for oil.
Federal Reserve Chair Jerome Powell acknowledged the recent improvements in price pressures but stressed to lawmakers that more data is needed to justify interest rate cuts. His cautious approach underscores the Fed’s commitment to data-driven policy decisions. The possibility of rate cuts also impacted the U.S. dollar index, causing it to drop. A weaker dollar generally supports oil prices by making dollar-denominated commodities cheaper for buyers using other currencies. Gary Cunningham, director of market research at Tradition Energy, emphasized this point, noting that a softer dollar could enhance oil demand.
The rise in oil prices also reflects broader market dynamics. On Wednesday, U.S. data showed a draw in crude stocks and strong demand for gasoline and jet fuel, ending a three-day losing streak for oil prices. Additionally, front-month U.S. crude futures recorded their steepest premium to the next-month contract since April. This market structure, known as backwardation, indicates supply tightness. When market participants are willing to pay a premium for earlier delivery dates, it often signals that current supply isn’t meeting demand.
While current market conditions suggest strong demand, future demand forecasts from major industry players show significant divergence. The International Energy Agency (IEA) recently predicted global oil demand growth to slow to under a million barrels per day (bpd) this year and next, mainly due to reduced consumption in China. In contrast, the Organization of the Petroleum Exporting Countries (OPEC) maintained a more optimistic outlook, forecasting world oil demand growth at 2.25 million bpd this year and 1.85 million bpd next year. This discrepancy between the IEA and OPEC forecasts is partly due to differing views on the pace of the global transition to cleaner fuels.
Alex Hodes, an analyst at StoneX, noted that the divergence in demand forecasts is unusually wide, attributing it to varying opinions on how quickly the world will shift to cleaner energy sources. This uncertainty adds another layer of complexity to market predictions and planning.
The interplay between inflation data, interest rate expectations, and oil demand forecasts creates a nuanced picture for the future of oil prices. If the Federal Reserve proceeds with rate cuts, increased economic activity could boost oil demand. However, the ongoing transition to clean energy and geopolitical factors will continue to play crucial roles. For now, market participants and analysts will closely monitor economic indicators and policy decisions. The recent rise in oil prices highlights the market’s sensitivity to macroeconomic trends and the importance of timely and accurate data in shaping market expectations.
These recent movements in oil prices underscore the complex interdependencies between economic data, policy decisions, and market dynamics. As inflation shows signs of cooling and hopes for rate cuts grow, the oil market is poised for potentially significant shifts. Understanding these trends is crucial for stakeholders across the industry as they navigate the evolving landscape of global energy markets.
Escalating hostilities between Israel and Iran have injected a new wave of supply disruption fears into global oil markets, sending crude prices surging to multi-month highs. The flareup threatens to further tighten supplies at a time when producers already appear maxed out, setting the stage for another potential energy price shock.
Crude benchmarks spiked over $90 a barrel in overnight trading after Israeli missiles struck Iran overnight. The attack came in retaliation for an Iranian drone and missile barrage targeting Israel just days earlier. While Iran has downplayed the impact so far, the tit-for-tat actions raised the specter of a broader military conflict that could imperil energy shipments throughout the Middle East.
Front-month Brent futures, the global pricing benchmark, jumped as high as $92 per barrel before paring gains. U.S. West Texas Intermediate crude topped $89 per barrel. Though off their overnight peaks, both contracts remained up over 2% on the day, hitting levels not seen since late 2023.
The aerial attacks have put the market on edge over the potential for supply chokeholds out of the Persian Gulf. Any protracted disruptions in that key oil shipping chokepoint would severely crimp available exports to global markets from regional producers like Saudi Arabia, Iran, and Iraq.
With the oil market already grappling with reduced supply from Russia due to sanctions, as well as chronic underinvestment by drillers, even modest additional shortfalls could quickly drain limited spare capacity buffers. OPEC and its allies have struggled to boost output to offset losses amid the broader underinvestment cycle.
For consumers still reeling from high energy costs, another bullish jolt to oil prices is an unwelcome development. After pulling back from 2022’s dizzying peaks, U.S. gasoline prices have started rebounding in recent weeks. The current $3.67 per gallon national average is up 21 cents just over the past month, according to AAA.
Some of that increase was expected due to seasonal refinery maintenance impacts. But the renewed geopolitical turmoil could propel gasoline and other fuel prices significantly higher nationwide if the conflict engulfing Israel and Iran deteriorates further.
The energy spike compounds existing inflationary headwinds plaguing the global economy. From restricted supplies of grains and fertilizers to manufacturing disruptions, the shockwaves from Russia’s invasion of Ukraine continue to ripple far and wide over a year later. Rapidly escalating tensions in the Middle East risk aggravating those pressures at a time when central banks are still struggling to restore price stability.
While some of the risk premium prompted by the Israel-Iran conflict may already be priced into crude, the threat of escalating retaliatory actions between the two adversaries keeps bullish risks elevated. Additional supply hits to global markets from further hostilities could easily drive oil prices back towards triple-digit territory not seen since 2022.
On Wall Street, stock futures were initially rattled by the rising geopolitical tensions, though markets stabilized in early trading as Iran refrained from immediate retaliation. Still, the volatility injected reinforces the nebulous risks confronting investors from the ever-simmering Middle East powder keg.
With so much at stake for inflation outlooks, policymakers at the Federal Reserve and other central banks will be monitoring the region with hawkish vigilance. Though diplomatically challenging to resolve, an extended sectarian conflict jeopardizing the secure flow of oil could compel another crusade of aggressive interest rate hikes historically anathema to financial markets.
For both consumers and investors, the situation serves as a stark reminder that geopolitical shocks exposing vulnerabilities in tight energy markets remain an omnipresent threat overhanging the economic outlook. Whether this clash proves fleeting or portends protracted hostilities remains to be seen, but the reverberations have oil prices surging once again.
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.
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.
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.
The biggest publicly traded oil companies in the West had a clear message for investors this earnings season: We’re going to keep paying you billions in dividends and stock buybacks, no matter how much our profits fluctuate.
BP, Chevron, ExxonMobil, Shell and TotalEnergies doled out over $111 billion to shareholders in 2023, an all-time record for the group, according to a Reuters analysis. This lavish payout comes even as the companies’ combined net profits sank 37% from 2022’s windfall heights of $196 billion.
It’s a calculated move to reassure investors, particularly major institutional shareholders like pension funds, that the oil supermajors still deserve a place in their portfolios despite LAST year’s stark reminder of the sector’s persistent volatility.
For over a decade, Big Oil has seen its status as a stalwart, dividend-paying pillar of investors’ portfolios slowly erode. The energy sector’s weighting in the S&P 500 index sat at just 4.4% in January, down dramatically from 14% in 2012.
Several factors catalyzed this decline: poor capital discipline leading to wasted spending and subsequent dividend cuts, huge swings in oil and gas prices, the rise of the tech sector, and growing concerns about oil’s role in climate change.
But Russia’s invasion of Ukraine in 2023 sparked an unexpected fossil fuel rally, with Brent crude prices averaging over $100 per barrel and natural gas prices skyrocketing. The oil giants cashed in with their highest profits ever, starkly highlighting the sector’s persistent upside potential.
Now with economic headwinds buffeting energy markets, their mammoth payouts to shareholders seek to underscore oil’s reliability versus more speculative investments. “During a time of geopolitical turmoil and economic uncertainty, our objective remained unchanged: safely deliver higher returns and lower carbon,” said Chevron CEO Mike Wirth after announcing a 6% dividend increase.
Besides dividends, oil majors are channeling these record buybacks to shareholders. Exxon Mobil alone spent $35 billion last year snapping up its own shares, while Shell has vowed “complete predictability” around shareholder returns.
This focus on payouts over production indicates Big Oil has absorbed the lessons of overspending on large-scale projects with uncertain demand outlooks. After former CEO John Browne spearheaded a failed push for aggressive growth at BP, lease write-downs of $60 billion soon followed.
Now with the transition to cleaner energy casting further uncertainty over long-term oil demand, companies are tightly rationing investment. Bernstein analyst Oswald Clint said investors “absolutely remember the sins of the past investment cycles and are pretty determined not to repeat those.”
While Exxon and Chevron are still expanding oil output, others like BP and Shell plan to cut production over this decade as part of their climate strategies. But all are aligning around far greater capital discipline and what they call “high-grading” their portfolios.
Rather than chasing growth, new projects must meet stricter hurdles for returns, emissions, and regulations. Tobias Wagner of Moody’s Investors Service expects only minimal investment increases industry-wide in 2024 given the cautious outlook.
So even as society decarbonizes, the oil supermajors are making a case that their stocks can still reward shareholders through the transition. Yet it remains to be seen whether investors who have fled the sector for greener pastures like clean energy and tech will find these guarantees compelling enough to return.
Independent oil and gas producer APA Corporation has agreed to purchase rival Callon Petroleum Company in an all-stock transaction valued at approximately $4.5 billion including debt. The deal expands APA’s operations in Texas’ prolific Permian Basin as the company continues building out a diversified oil and gas portfolio.
Under the definitive agreement announced Thursday, each Callon share will be exchanged for 1.0425 shares of APA common stock. This represents a purchase price of $38.31 per Callon share based on APA’s closing stock price on January 3rd.
APA expects to issue around 70 million new shares to fund the acquisition, leaving existing APA shareholders with 81% of the combined company. Callon shareholders will own the remaining 19% once the deal closes.
Strategic Fit
According to APA CEO and President John J. Christmann IV, Callon’s Delaware Basin assets perfectly complement APA’s existing Permian footprint.
He stated the deal “fits all the criteria of our disciplined approach to evaluating external growth opportunities.” It provides additional scale across the Permian while increasing APA’s oil mix.
Notably, Callon holds nearly 120,000 net acres in the Delaware Basin, an oil-rich subsection of the larger Permian. APA’s Delaware acreage will expand by over 50% after absorbing Callon’s properties.
Meanwhile, APA’s Midland Basin presence will continue driving natural gas volumes. The combined Permian portfolio increases APA’s total company oil production mix from 37% to 43%.
Accretive Metrics
APA expects the deal will prove accretive to key financial and value metrics. Management sees over $150 million in annual overhead, operational, and cost of capital synergies resulting from the increased scale.
The company will also benefit from Callon’s inventory of short-cycle drilling opportunities in the Permian. APA believes the deal enhances its portfolio of low-risk, high-return investments.
What’s more, the transaction stands to improve APA’s credit profile. The company will retire all of Callon’s existing debt after closing, replacing it with $2 billion in APA term loan facilities. This is expected to provide flexibility for near-term debt pay-down.
Conditions and Close
The definitive agreement has received unanimous approval from the boards of directors at both companies. The deal now requires customary regulatory clearances along with a thumbs up from Callon shareholders.
APA anticipates the acquisition will close during the second quarter of 2024. Upon closing, a representative from Callon will join APA’s board of directors.
APA’s current executive team led by Christmann will continue managing the expanded company. Headquarters will remain in Houston, Texas.
Diversified Portfolio
According to Christmann, the deal aligns with APA’s strategy of maintaining a globally diversified oil and gas portfolio. The company runs both legacy and exploration assets across the United States, Egypt, the UK, and offshore Suriname.
Post-acquisition, 36% of APA’s total production will come from international plays. The remaining 64% stems from U.S. assets, with the bulk supplied by the newly expanded Permian footprint.
Callon Brings Strong Permian Position
Founded in 1950, Callon Petroleum has grown into a leading independent Permian producer. The Houston-based company focuses on acquiring, exploring, and developing high-quality assets across the prolific West Texas basin.
As of September 2022, Callon reported net production of over 106,000 barrels of oil equivalent per day. Its portfolio includes a mix of productive acreage, infrastructure, and upside opportunities in both the Midland and Delaware Basins.
According to Callon President and CEO Joe Gatto, the combination with APA will enhance value for Callon shareholders. It also provides increased capital flexibility and potential from APA’s robust Permian operations.
The proposed acquisition marks the latest move in APA’s ongoing growth strategy. The company continues positioning itself as a diversified, large-scale independent oil and gas producer able to drive value across business cycles.
Oil prices are on pace to decline around 10% in 2022, which would mark the first annual drop since the pandemic-driven crash of 2020. After a volatile year, bearish sentiment has taken hold in oil markets amid fears that surging production outside OPEC will lead to an oversupplied market.
With the global economy slowing, especially in key consumer China, demand growth is stalling. Meanwhile, output has hit new highs in the United States, Brazil, Guyana and other non-OPEC countries. This perfect storm of sluggish demand and robust non-OPEC supply has tipped the balance into surplus, putting downward pressure on prices.
West Texas Intermediate futures are trading near $72 per barrel, down from over $120 in June. The international Brent benchmark is hovering under $78, having fallen from summertime highs over $130. Despite ongoing risks, including escalating Iran-related tensions in the Middle East, oil is poised to post its first yearly decline since the Covid crisis cratered prices in 2020.
Supply Surge Outside OPEC Upsets Market Balance
Much of the extra crude swamping the market is coming from the United States. American oil output averaged 13.3 million barrels per day last week, a record high. Exceptional production growth is also happening in Brazil, Guyana, Canada and other countries.
The International Energy Agency expects this non-OPEC supply surge to continue, forecasting growth of 1.2 million barrels per day next year. That will more than satisfy the world’s modest demand growth projected at 1.1 million barrels per day in the IEA’s base case scenario.
With non-OPEC, and chiefly U.S. shale, filling demand, OPEC and its allies have lost their traditional grip on balancing the market. Despite cutting output targets substantially, OPEC+ efforts to lift prices seem futile.
Traders anticipate more discipline will be required to bring inventories down. But further significant cuts could simply provide more space for American drillers to increase production, replacing any barrels OPEC removes.
Tepid Demand Outlook Adds to Gloomy Price Forecast
On top of the supply influx, oil bulls are also contending with a deteriorating demand environment. High inflation, rising interest rates, and frequent Covid outbreaks have slowed China’s economy significantly.
With Chinese oil consumption dropping, global demand growth is expected to decelerate in 2024. Major financial institutions like Morgan Stanley see demand expanding at less than 1 million barrels per day. That’s about half the pace forecast for 2023.
Other major economies in Europe and North America are also wobbling, further dampening the demand outlook. Less robust consumption, together with the supply deluge, points to a market remaining oversupplied through next year.
In futures markets, bearish sentiment has sunk in. Both WTI and Brent futures point to prices averaging around $80 per barrel in 2023, barring a major geopolitical disruption. That would cement the first back-to-back years of oil price declines since 2015-2016.
Wildcard Risks – Can Middle East Tensions Shift Momentum?
As oversupply dominates, the greatest upside risk to prices may be conflict-driven outages that take substantial oil capacity offline. Heightened tensions between Iran and the West pose this type of wildcard geopolitical threat.
Recent attacks on oil tankers near the Strait of Hormuz and Arabian Sea occurred after the U.S. killed an Iranian commander. Iran-backed Houthi rebels in Yemen also launched missiles and drones at facilities in Saudi Arabia.
While no significant disruptions have occurred so far, direct hostilities between Iran and the U.S. or its allies could sparks clashes endangering Middle East output. Iran has threatened to blockade the Strait of Hormuz, which handles a fifth of global oil trade. Any major loss of supply through this chokepoint could upend the bearish outlook.
For now, however, the market remains fixated on bulging inventories and the supply free-for-all outside OPEC. As the world undergoes a historic shift in oil production geography, the industry faces a reckoning over whether unchecked growth risks unsustainably low prices. If the supply surge continues outpacing demand, today’s pessimism over prices could last well beyond 2024.
Oil prices fell over $1 a barrel on Thursday after Angola announced its departure from OPEC, while record US crude output and persistent worries over Red Sea shipping added further pressure.
Brent crude futures dropped $1.30 to $78.40 a barrel in afternoon trading, bringing losses to nearly 2% this week. US West Texas Intermediate (WTI) crude also slid $1.19 to $73.03 per barrel.
The declines came after Angola’s oil minister said the country will be leaving OPEC in 2024, saying its membership no longer serves national interests. While Angola’s production of 1.1 million barrels per day (bpd) is minor on a global scale, the move raises uncertainty about the unity and future cohesion of the OPEC+ alliance.
At the same time, surging US oil output continues to weigh on prices. Data from the Energy Information Administration (EIA) showed US production hitting a fresh peak of 13.3 million bpd last week, up from 13.2 million bpd.
The attacks on oil tankers transiting the narrow Bab el-Mandeb strait at the mouth of the Red Sea have forced shipping companies to avoid the area. This is lengthening voyage times and increasing freight rates, adding to oil supply concerns.
So far the disruption has been minimal, as most Middle East crude exports flow through the Strait of Hormuz. But the risks of broader supply chain headaches are mounting.
Balancing Act for Oil Prices
Oil prices have stabilized near $80 per barrel after a volatile year, as slowing economic growth and China’s COVID-19 battles dim demand, while the OPEC+ alliance constrains output.
The expected global demand rise of 1.9 million bpd in 2023 is relatively sluggish. And while the OPEC+ coalition agreed to cut production targets by 2 million bpd from November through 2023, actual output reductions are projected around just 1 million bpd as several countries struggle to pump at quota levels.
As a result, much depends on US producers. EIA predicts America will deliver nearly all new global supply growth next year, churning out an extra 850,000 bpd versus 2022.
With the US now rivaling Saudi Arabia and Russia as the world’s largest oil producer, its drilling rates are pivotal for prices. The problem for OPEC+ is that high prices over $90 per barrel incentivize large gains in US shale output.
Most analysts see Brent prices staying close to $80 per barrel in 2024, though risks are plentiful. A global recession could crater demand, while a resolution on Iranian nuclear talks could unlock over 1 million bpd in sanctions-blocked supply.
The Russia-Ukraine war also continues clouding the market, especially with the EU’s looming ban on Russian seaborne crude imports.
In announcing its departure, Angola complained that OPEC+ was unfairly reducing its production quota for 2024 despite years of over-compliance and output declines.
The country’s oil production has dropped from close to 1.9 million bpd in 2008 to just over 1 million bpd this year. A lack of investment in exploration and development has sapped its oil fields.
The OPEC+ cuts seem to have been the final straw, with Angola saying it needs to focus on national energy strategy rather than coordinating policy within the 13-member cartel.
The move makes Angola the first member to leave OPEC since Qatar exited in 2019. While it holds little sway over global prices, it does spark questions over the unity and future cohesion of OPEC+, especially if other African members follow suit.
Most analysts, however, believe the cartel will hold together as key Gulf members and Russia continue dominating policy. OPEC+ still controls over 40% of global output, giving it unrivaled influence over prices through its supply quotas.
But UBS analyst Giovanni Staunovo points out that “prices still fell on concern of the unity of OPEC+ as a group.” If more unrest and exits occur, it could chip away at the alliance’s price control power.
For now OPEC+ remains focused on its landmark deal with Russia and supporting prices through 2024. Yet US producers are the real wild card, with their response to higher prices determining whether OPEC+ can balance the market or will lose more market share in years ahead.
Endeavor Energy Partners, the top privately-held oil and gas producer in the prolific Permian Basin of west Texas and New Mexico, is considering a sale that could value the company at an astonishing $25-30 billion, according to a recent Reuters exclusive.
The news comes fresh off the heels of some absolutely massive M&A action among public oil independents, with the $60 billion tie-up between ExxonMobil and Pioneer Natural Resources followed by Chevron announcing the $50+ billion purchase of Hess Corp. Now the private players are looking to capitalize on the consolidation wave by monetizing their substantial acreage as well.
Driving the potential multi-billion dollar valuation is Endeavor’s premier 350,000 net acre position in the coveted Midland sub-basin, the sweet spot of the larger Permian. With oil prices still hovering near $80 per barrel despite recession fears, there remain plenty of companies willing to pay up for high-quality acreage that can drive efficient growth for years to come. And Endeavor’s assets definitely check those boxes.
The Visionary Behind Endeavor’s Rise
Endeavor traces its roots back 45 years when Texas oilman Autry Stephens founded the small independent. The 85-year old Stephens grew the company through shrewd acreage acquisitions and by managing costs tightly with vertically integrated services businesses.
Now with retirement on the horizon, Stephens has apparently decided that the time is right to capitalize on the current market enthusiasm and secure his life’s work’s future by selling Endeavor to one of the large public independents like an Exxon or Chevron. Certainly Stephens’ estate and early investors would realize a tremendous windfall from such a deal.
While Endeavor has reportedly considered offers before, this time the process seems to be progressing firmly with investment bankers at JP Morgan already preparing marketing materials for potential buyers. So while there’s no guarantee that Endeavor finds a buyer or completes a sale, things have moved beyond the tire-kicking stage.
Ripe for the Picking by “Big oil”
As mentioned previously, Endeavor’s footprint in the core of the Permian Basin makes the company a logical target for any number of deep-pocketed suitors from major integrateds to large E&Ps looking to expand their presence.
And most of the likeliest buyers like Exxon, Chevron, and ConocoPhillips have all recently pulled off huge, multi-billion dollar deals to consolidate acreage while still leaving their balance sheets relatively unscathed. Using their equity and maintaining strong investment grade credit ratings remains paramount for the majors.
For example, Chevron structured its takeover of Hess Corp such that the $50 billion price tag amounted to less than half of its current cash position. So the company would have no issues stepping up to buy another large, complementary Permian pure-play.
Of course Exxon is in the same boat having expertly engineered the Pioneer acquisition to be immediately accretive to earnings and cash flow. So whileAbsorbing all of Endeavor’s 350k acres might be a bridge too far for XOM, the supermajor could easily swallow a chunk of the company or join a consortium.
Not to be outdone, ConocoPhillips recently closed its buyout of existing partner Lime Rock’s 50% stake in the Canadian Surmont oil sands project proving its appetite for sizable deals remains healthy. CEO Ryan Lance has also been vocal about wanting to bulk up the company’s Permianpresence over the long term giving it both the strategic rationale and financial means to pursue Endeavor.
Each of these independent E&Ps seem well suited to provide a soft landing for founder Autry Stephens’ life work. Endeavor has quietly built up a world class asset base that now looks poised to fetch an exceptional valuation and secure a new, well-heeled owner. So investors will be following the sales process closely as a potential deal would recalibrate the consolidation environment. Of course, we will have to wait and see what 2024 ultimately has in store for one of the Permian’s great growth stories.
In a strategic move to bolster its presence in the prolific Permian Basin, Occidental Petroleum has reached an agreement to acquire CrownRock for a staggering $12 billion. This significant deal, part of a broader consolidation trend in the U.S. energy sector, positions Occidental to fortify its standing as the ninth-largest energy company in the U.S.
CrownRock, a major privately held energy producer operating in the Permian Basin, is currently developing a 100,000-acre position in the Midland Basin, a crucial segment spanning 20 counties in western Texas. The Midland Basin, contributing 15% of U.S. crude production in 2020, is a key focus for Occidental’s goal to increase its scale in the Permian.
The transaction is set to add a substantial 170,000 barrels of oil equivalent per day to Occidental’s production capabilities. Furthermore, with 1,700 undeveloped locations in the Permian, the deal positions Occidental for strategic expansion in a region vital to the nation’s energy landscape.
To finance this significant acquisition, Occidental plans to issue $9.1 billion in new debt, complemented by approximately $1.7 billion in common stock. Despite these financial obligations, Occidental remains committed to its goal of reducing its overall debt to below $15 billion, showcasing confidence in the long-term benefits of the CrownRock acquisition.
Occidental’s CEO, Vicki Hollub, emphasized the company’s dedication to managing its financial commitments. Despite a 10% drop in Occidental’s stock year-to-date, the acquisition of CrownRock marks the third major deal in the energy sector within a span of two months, highlighting Occidental’s determination to adapt and grow in a rapidly evolving industry.
Berkshire Hathaway, a major holder with about 26% of Occidental’s shares, was not involved in this particular deal. Occidental’s ticker symbol is OXY, and the company anticipates finalizing the CrownRock acquisition in the first quarter of 2024, adding another chapter to its dynamic expansion strategy.
This acquisition is a pivotal moment for Occidental Petroleum as it continues to navigate the evolving energy landscape, strategically positioning itself for future success in the Permian Basin.
Occidental Petroleum Corporation (NYSE: OXY), commonly known as Occidental, has a storied history dating back to its founding in 1920. Established in California, the company evolved from a small oil production venture into one of the largest independent oil and gas exploration and production companies globally. Over the years, Occidental has played a pivotal role in the energy industry, engaging in diverse operations such as oil and gas exploration, production, refining, and marketing. Known for its innovative technologies and strategic acquisitions, Occidental has expanded its reach across the Americas, the Middle East, and North Africa. The company’s commitment to responsible and sustainable energy practices aligns with its pursuit of operational excellence. As the ninth-largest energy company in the U.S., Occidental continues to navigate the dynamic energy landscape, adapting to industry trends and solidifying its position through strategic acquisitions, such as the recent $12 billion CrownRock deal, which reflects its dedication to growth and resilience in an ever-evolving market.
