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.
General Motors (GM) announced Wednesday its largest investment yet to lock up critical raw materials needed for its ambitious electric vehicle (EV) production plans. The Detroit automaker said it will spend $19 billion over the next decade to source cathode materials from South Korean supplier LG Chem.
The materials—including nickel, cobalt, manganese and aluminum—are key ingredients for the lithium-ion batteries that power EVs. Under the agreement spanning 2026-2035, LG Chem will ship over 500,000 tons of cathode materials to GM’s joint battery cell plants with LG spinoff Ultium Cells in the United States.
GM stated this is enough supply for approximately 5 million EVs with an estimated range of over 300 miles per charge. The materials will come from an LG Chem plant currently under construction in Tennessee.
For GM, signing a long-term purchase agreement helps mitigate risks around securing sufficient future EV battery supplies amid intensifying competition. As automakers collectively invest billions to shift their lineups to mostly EVs by 2030, critical mineral shortages could constrain production plans.
“This contract builds on GM’s commitment to create a strong, sustainable battery EV supply chain to support our fast-growing EV production needs,” said Jeff Morrison, GM vice president of global purchasing and supply chain.
The LG Chem deal ranks among the largest—if not the largest—EV supply contract inked by GM to date. It highlights an urgency by the company to lock up raw materials as the global auto industry accelerates its electric shift. GM aspires to exclusively sell EVs by 2035.
However, the 14-year LG Chem agreement also implies GM may be adapting its EV strategy to account for adoption happening slower than anticipated. The original pact was scheduled to expire in 2030, but GM extended it another five years.
After initially forecasting aggressive EV sales growth, GM has pulled back on targets amid steeping battery costs and strained consumer budgets. “We’re also being a little bit prudent about the pace at which the transition occurs,” said CEO Mary Barra.
Nonetheless, GM remains laser-focused on its EV future. It recently announced a $650 million investment to expand production of its profitable full-size SUVs—but as electric versions only by 2024. “We have the manufacturing flexibility to build EVs at scale,” said Barra.
For investors, GM’s major bet on EVs represents an opportunity to capitalize on the immense growth projected in the electric vehicle market over the next decade. Research firm IDTechEx forecasts the EV market will balloon from $287 billion in 2021 to over $1.3 trillion by 2031 as adoption accelerates globally. GM’s plan to phase out gas-powered cars and transition to an all-electric lineup positions it as a leading EV player in this booming new automotive era.
Meanwhile, LG Chem said it aims to “bolster cooperation with GM in the North American market” through the expanded cathode materials agreement. The supplier has jockeyed with China’s CATL for the title of world’s top EV battery maker.
For both LG and GM, ensuring cathode supply security with a US-based plant mitigates geopolitical risks. President Biden’s Inflation Reduction Act requires automakers to source critical minerals domestically or from allies to qualify for EV tax credits.
While the road to an all-electric future remains bumpy, GM’s huge bet on sourcing vital battery ingredients shows its commitment to phasing out the internal combustion engine. As Barra stated, “We’re on our way to an all-electric portfolio.”
CALGARY, AB, Feb. 1, 2024 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to confirm that its Board of Directors has declared a monthly cash dividend of $0.015 per common share payable on February 29, 2024, to shareholders of record at the close of business on February 15, 2024. The monthly cash dividend is expected to be designated as an “eligible dividend” for Canadian federal and provincial income tax purposes.
About InPlay Oil Corp.
InPlay is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.
SOURCE InPlay Oil Corp.
For further information: please contact: Doug Bartole, President and Chief Executive Officer, InPlay Oil Corp., Telephone: (587) 955-0632, www.inplayoil.com; Darren Dittmer, Chief Financial Officer, InPlay Oil Corp., Telephone: (587) 955-0634
Electric vehicle technology firm Exro Technologies is acquiring e-mobility drivetrain maker SEA Electric in an all-stock $300 million deal. The strategic merger combines two complementary electric propulsion platforms, setting the stage to disrupt the surging commercial EV space.
For investors, the transaction provides Exro with enhanced scale, revenue, and a clear path to profitability. With SEA’s major OEM customers like Volvo and Toyota, over 1,000 EV system orders are forecast for 2024 generating above $200 million sales.
The consolidated entity targets delivery of complete, next-gen propulsion solutions demanded by fleet operators and manufacturers transitioning to electric. Significant synergies, cross-selling opportunities, and cost savings are expected from the integration of the companies’ technologies.
Massive Addressable Market
Exro’s battery control electronics and SEA’s full electric drive systems together optimize EV power, efficiency, and costs. This unique, end-to-end capability unlocks a share of the enormous global commercial EV market.
Market research firm IDTechEx sees the medium and heavy commercial EV market reaching over $140 billion annually by 2031. With increasingly stringent emissions regulations worldwide, electrifying trucks, buses, construction equipment and beyond offers massive potential.
Exro and SEA aim to be at the forefront of this shift providing the integrated propulsion technologies enabling OEMs to electrify their offerings at scale.
Key Customer Wins
A huge value driver is SEA Electric’s multi-year supply agreements with heavy-duty truck leaders Mack and Hino for thousands of initial EV systems. This provides the merged Exro with committed volumes and Tier 1 auto relationships to leverage.
SEA’s proven proprietary technology underwent extensive validation by the major OEMs. Having signed binding long-term deals, SEA Electric immediately thrusts Exro into a commanding competitive position and cash flow generation.
Clear Path to Profitability
Beyond the technology and growth synergies, the transaction offers investors a profitability catalyst for Exro. Management estimates achieving positive cash flow within 12 months post-close given the ramping order book.
This would mark a key inflection point in Exro’s maturation toward becoming a fully self-sustaining EV enterprise. Profitability could further enhance access to capital to fuel expansion efforts.
The merger is subject to shareholder greenlighting, but the strategic fit and near-term income opportunity make a compelling case. With Polestar and others vying in electric commercial vehicles, Exro seizes pole position through its SEA Electric deal.
InPlay Oil is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Management updated its 2023 guidance. The adjustment reflects a drop in production expectations. New guidance is significantly below the 9,700 boe/d production flow reported from the field on November 9, 2023. The decline may represent a sharper decline rate from initial production rates than had previously been expected by management. The drop in production lead to a sharp reduction in projected Adjusted Funds Flow and Free Funds Flow.
Management also sharply reduced its 2024 production estimates. New guidance calls for 2024 production that is only slightly higher than newly revised 2023 guidance despite the drilling of 14-15 new wells and an expected reduction in curtailment. While it is possible that management is simply being conservative, it may also reflect well decline rates as discussed above.
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*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
CALGARY, AB, Jan. 29, 2024 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) is pleased to announce that its Board of Directors have approved a capital program of $64 – $67 million for 2024.
2024 Capital Program Highlights
InPlay’s 2024 exploration and development capital program of $64 – $67 million is forecast to deliver the following(5):
Annual average production of 9,000 – 9,500 boe/d (59% – 61% light crude oil and NGLs);
Drilling program focused on high return oil weighted locations driving annual oil production growth at the midpoint of guidance of 7% over 2023;
Operating income profit margin(2) of approximately 59%;
Reduction in capital spending of 20% – 25% compared to 2023 including reduced facilities and infrastructure spending by over 50% providing strong capital efficiencies;
Adjusted Funds Flow (“AFF”)(4) of $89 – $96 million;
Free Adjusted Funds Flow (“FAFF”)(2) of $22 – $32 million;
Net debt(4) of $37 – $44 million with a net debt to EBITDA ratio(2) of 0.4 – 0.5 times which is among the lower leverage ratios amongst our peers;
Base dividend of $16 – $17 million at the current monthly dividend rate of $0.015/share ($0.18/share annualized) which represents approximately an 8% yield at the current share price; and
Significant unutilized financial liquidity which can be used to pursue potential tactical capital investments.
The table below highlights our 2024 guidance:
2024(5)
WTI (US$/bbl)
75.00
Production (boe/d) (1)
9,000 – 9,500
Capital ($ millions)
64 – 67
Net wells
14.0 – 15.0
AFF ($ millions) (4)
89 – 96
FAFF ($ millions) (2)
22 – 32
Net Debt at Year-end ($ millions) (4)
(44) – (37)
Annual Net Debt / EBITDA (2)
0.4 – 0.5
Dividend ($ millions)
16 – 17
The amounts above do not include potential future purchases through the Company’s normal course issuer bid (“NCIB”).
With continued commodity price volatility, specifically weak natural gas fundamentals, and current low investor sentiment, InPlay has taken a measured and disciplined approach to capital allocation for 2024, seeking to maximize capital efficiencies, AFF(2), and FAFF(2) supporting strong returns to shareholders with a priority on maintaining our pristine balance sheet. Despite a 20% to 25% reduction in capital spending year over year, InPlay is forecasting to deliver approximately 7% growth in our oil volumes as we focus on higher oil weighted assets that deliver greater returns. The capital program is designed to responsibly manage the pace of development, maintain flexibility and remain focused on delivering return of capital to shareholders.
Given the higher rate of return of InPlay’s oil weighted properties, the Company plans to direct its 2024 capital budget towards oil weighted drilling in the Cardium and Belly River. Plans are to drill approximately 11 – 12 net Extended Reach Horizontal (“ERH”) Cardium wells in Willesden Green and Pembina. Also, 3.0 net wells are planned in the Belly River taking advantage of the very high oil weighting of approximately 90%. These Belly River wells exhibit increasing oil rates over the first three quarters of production and a low decline rate thereafter. Our two most recent horizontal wells drilled in the Belly River, which came online in November 2022, have delivered operating netbacks of approximately $71.25/boe since being brought on production. Our higher oil weighted locations are characterized by strong light oil rates with lower total boe/d rate relative to wells with higher natural gas weightings. The Company’s 2024 drilling program plans on drilling fewer wells in 2024 compared to 2023, as a result of our cautious, disciplined capital approach for the year and is structured to take advantage of improving differentials starting in the second quarter of 2024 and throughout the balance of the year. Facility capital in 2024 is forecasted to be approximately $6.4 million less than 2023 due to the reduced drilling program and significant capital spent on two major natural gas plant upgrades completed in 2023.
InPlay’s first quarter of 2024 drilling program consists of five (4.9 net) ERH Cardium wells and three (0.7 net) non-operated ERH Cardium wells. Drilling has started on a two well (1.9 net) pad in Willesden Green which is expected to come on production in February. Capital activity will then move to Pembina to drill three (3.0 net) Cardium ERH wells. These wells will offset our five successful wells drilled in 2023 characterized by low decline rates and high light oil and liquids weighting with average initial production (“IP”) rates of 257 boe/d (89% light crude oil and liquids), 265 boe/d (86% light crude oil and liquids) and 239 boe/d (82% light crude oil and liquids) over their first 30, 60 and 180 days respectively.
InPlay made significant investments in 2023 to increase operated natural gas takeaway capacity for future growth in Willesden Green and to mitigate potential production issues arising from third party outage and capacity constraints. These projects have already shown their value by reducing back pressure on wells, lowering declines and providing more consistent runtimes while improving our liquids weighting with a higher natural gas liquids recovery. To further enhance our natural gas takeaway capabilities, InPlay has entered into a long term Gas Handling Agreement with an industry partner guaranteeing access to natural gas takeaway and processing capacity in the Company’s Pembina area where we were initially curtailed by approximately 6 mmcfd and associated oil and liquids starting on February 15, 2023 with the gradual reduction in curtailments and the full resumption of production in September 2023. This contract will allow InPlay to restart with certainty of capacity the development of this prolific and strong rate of return growth area where drilling activity has not occurred since the spring of 2022. InPlay plans on drilling a three (3.0 net) ERH Cardium well pad in this area in the third quarter of 2024. The Company projects fewer operated and non-operated turnarounds and other infrastructure issues during 2024 after an unprecedented high level of disruptions in 2023.
To mitigate risk and add stability during periods of market volatility, commodity hedges have been secured through 2024 and into 2025 as summarized below.
Q1/24
Q2/24
Q3/24
Q4/24
Q1/25
Natural Gas AECO Swap (mcf/d)
–
1,900
1,900
640
–
Hedged price ($AECO/mcf)
–
2.00
2.00
2.00
–
Natural Gas AECO Costless Collar (mcf/d)
4,870
3,790
3,790
5,050
3,790
Hedged price ($AECO/mcf)
2.48 – 3.82
2.08 – 2.77
2.08 – 2.77
2.27 – 3.04
2.48 – 3.46
Crude Oil Costless Collar (bbl/d)
–
1,000
–
–
–
Hedged price ($USD WTI/bbl)
–
72.00 – 80.25
–
–
–
Crude Oil Costless Collar (bbl/d)
330
–
–
–
–
Hedged price ($CAD WTI/bbl)
95.00 – 110.00
–
–
–
–
Crude Oil WTI Three-way Collar (bbl/d) (7)
–
–
1,000
1,000
–
Low sold put price ($USD WTI/bbl)
–
–
64.00
64.00
–
Mid bought put price ($USD WTI/bbl)
–
–
74.00
74.00
–
High sold call price ($USD WTI/bbl)
–
–
82.48
82.48
–
InPlay will continue to prudently allocate capital resources and adjust its capital plans in consideration of commodity prices, inflationary cost pressures and other aspects impacting our business. Should commodity prices improve and stabilize, InPlay will remain disciplined and flexible and can quickly adjust capital activity to respond to changing market conditions.
2023 Update
InPlay’s fourth quarter capital program consisted of drilling two (1.6 net) ERH wells in Willesden Green that were brought on production in November. Also, the company drilled its first (1.0 net) multilateral Belly River horizontal well which was brought on production in December. The well has been on production for approximately one month and is still in its initial stages of cleanup and early production results are meeting our internal expectations with oil cuts increasing, consistent with offsetting wells.
The increase in North American natural gas production coupled with a warm start to winter has natural gas storage inventories at very high levels resulting in weaker than expected natural gas prices during the fourth quarter that continued into 2024. Crude oil differentials began to weaken in November and widened throughout the quarter which impacted realized oil pricing during this period. Higher differentials are extending into the first quarter of 2024 but forward indices show them improving and narrowing starting in the second quarter of 2024 and throughout the remainder of the year.
Annual average production for 2023 is forecast to be approximately 9,050 boe/d(1) (58% light crude oil & NGLs) which 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 from delays in starting up our natural gas facility in the third quarter as discussed in our prior press releases.
The table below highlights our updated forecasted 2023 guidance:
2023(3)
WTI (US$/bbl)
77.61
Production (boe/d) (1)
9,000 – 9,100
Capital ($ millions)
84.5
Net wells
17.1
AFF ($ millions) (4)
91 – 93
FAFF ($ millions) (2)
6 – 8
Net Debt at Year-end ($ millions) (4)
(45) – (47)
Dividend ($ millions)
16
See Reader Advisories for previous guidance and underlying assumptions.
As commented on above, continued commodity price volatility and current weak industry sentiment has resulted in the Company taking a conservative, disciplined approach to capital allocation in 2024. 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 withdraws its preliminary estimates and plans for 2025.
We look forward to the profitable development of our high rate of return asset base and continuing to provide strong returns to shareholders through 2024 and beyond. On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support.
For further information please contact:
Doug Bartole President and Chief Executive Officer InPlay Oil Corp. Telephone: (587) 955-0632
See “Reader Advisories – Production Breakdown by Product Type”
2.
Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release.
3.
Based on estimated, unaudited year-end 2023 results. See “Reader Advisories – Forward Looking Information and Statements” for underlying assumptions related to our estimated, unaudited year-end 2023 results.
4.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
5.
See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2024 capital program and associated guidance.
6.
Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
7.
The WTI three-way collars are a combination high priced sold call, low priced sold put and a mid-priced bought put. The high sold call price is the maximum price the Company will receive for the contract volumes. The mid bought put price is the minimum price InPlay will receive, unless the market price falls below the low sold put strike price, in which case InPlay receives market price plus the difference between the mid bought put price minus the low sold put price.
Reader Advisories
Non-GAAP and Other Financial Measures
Throughout this press release and other materials disclosed by the Company, InPlay uses certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under GAAP and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with GAAP as indicators of the Company performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze InPlay’s business performance against prior periods on a comparable basis.
Non-GAAP Financial Measures and Ratios
Included in this document are references to the terms “free adjusted funds flow”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “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
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 to the “Forward Looking Information and Statements” section for a calculation of operating income, operating netback per boe and operating income profit margin.
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.
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 is a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Production per debt adjusted share.
EV / DAAFF
InPlay uses “enterprise value to debt adjusted AFF” or “EV/DAAFF” as a key performance indicator. EV/DAAFF is calculated by the Company as enterprise value divided by debt adjusted AFF for the relevant period. Debt adjusted AFF (“DAAFF”) is calculated by the Company as adjusted funds flow plus financing costs. Enterprise value is a capital management 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 ending December 31, 2022 and the most recently filed quarterly financial statements. 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 ending December 31, 2022 and the most recently filed quarterly financial statements. 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 production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized NGL price” is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company’s NGL production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized natural gas price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized commodity price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Adjusted funds flow per weighted average basic share” is comprised of adjusted funds flow divided by the basic weighted average common shares.
“Adjusted funds flow per weighted average diluted share” is comprised of adjusted funds flow divided by the diluted weighted average common shares.
“Adjusted funds flow per boe” is comprised of adjusted funds flow divided by total production.
Preliminary Financial Information
The Company’s expectations set forth in the updated forecasted 2023 guidance are based on, among other things, the Company’s anticipated financial results for the three and twelve month periods ended December 31, 2023. The Company’s anticipated financial results are unaudited and preliminary estimates that: (i) represent the most current information available to management as of the date of hereof; (ii) are subject to completion of audit procedures that could result in significant changes to the estimated amounts; and (iii) do not present all information necessary for an understanding of the Company’s financial condition as of, and the Company’s results of operations for, such periods. The anticipated financial results are subject to the same limitations and risks as discussed under “Forward Looking Information and Statements” below. Accordingly, the Company’s anticipated financial results for such periods may change upon the completion and approval of the financial statements for such periods and the changes could be material.
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; all estimates and guidance related to the year ended 2023 results; the Company’s planned 2024 capital program including wells to be drilled and completed and the timing of the same; 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; expectations regarding future commodity prices; future oil and natural gas prices; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our planned 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.
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.
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.
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 2023 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.
Risk Factors to FLI
Risk factors that could materially impact successful execution and actual results of the Company’s 2023 and 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 current and previous 2023 guidance and 2024 guidance are as follows:
The change in production per debt adjusted share growth between previous and updated guidance is primarily due to 2023 production being impacted by approximately 650 boe/d as a result of curtailments, Alberta wildfires, natural gas facility startup delays as discussed in the body of this press release.
(1)
As previously released August 14, 2023.
(2)
As previously released November 9, 2023.
(3)
As previously released January 18, 2023.
(4)
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.
(5)
Weighted average share price throughout 2022 and 2023.
(6)
Ending share price at December 31, 2022 and December 31, 2023.
(7)
The change in the 2023 forecasted results from prior guidance results from an increase in capital expenditures and decrease in adjusted funds flow as a result of a reduction to production, a higher natural gas weighting of total production and lower AECO natural gas prices than previously forecasted.
(8)
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.
(9)
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 withdraws 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.
Production Breakdown by Product Type
Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51–101 and their respective quantities disclosed in the table below:
Notes:
1.
This reflects the mid-point of the Company’s 2023 updated production guidance range of 9,000 to 9,100 boe/d.
2.
This reflects the mid-point of the Company’s 2023 previous production guidance range of 9,100 to 9,500 boe/d.
3.
This reflects the mid-point of the Company’s 2024 production guidance range of 9,000 to 9,500 boe/d.
4.
This reflects the midpoint of the Company’s annual production previous preliminary estimate range.
5.
With respect to forward–looking production guidance, product type breakdown is based upon management’s expectations based on reasonable assumptions but are subject to variability based on actual well results.
References to crude oil, light oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 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.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
Hemisphere Energy reported 2024-4Q production results. Hemisphere Energy reported production of 3,375 boe/d, a 16% increase over the same period in 2022 and an 11% increase over 2023-3Q results. Production for the most recent quarter surpassed the 3,325 boe/d rate we had been using in our models.
Management gives initial 2024 production, pricing, and cost guidance. Management gave initial 2024 production, cash flow and capital expenditure guidance. Guidance was largely in line with our expectations.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
In the investing world, money often rotates between different sectors over time. After a long period of technology stocks dominating, we may now be entering a new cycle where mining and natural resource stocks start to outperform other industries and sectors. There are several compelling reasons mining could be the next big thing for investors.
First, demand is soaring for the critical minerals and metals used in electric vehicles, batteries, and clean energy. Metals like lithium, nickel, cobalt, and copper are essential for manufacturing electric car batteries, solar panels, wind turbines, and other green technologies. With many countries pushing for faster adoption of EVs and renewable power, demand for these key minerals is skyrocketing. Major automakers have announced ambitious electric vehicle plans, which requires secure access to raw materials. This imbalance between booming demand and limited supply bodes well for mining firms.
Additionally, the pandemic exposed risks of relying on a few countries for critical minerals. It revealed the need for domestic mining capacity to ensure stable access to essential inputs like lithium. For instance, the U.S. aims to boost domestic production of strategic minerals and reduce dependence on China. The EU also has a new plan to secure rare earth supplies within Europe. This focus on mineral independence is a plus for miners in North America and Europe.
Rising inflation and gold prices also bolster the case for mining stocks. With central banks printing huge amounts of money, many investors see gold as an inflation hedge. This has helped push gold prices to an 8-month high around $1900/ounce. Higher inflation tends to lift gold and silver prices as people flock to hard assets. Many miners produce both precious metals alongside base metals. They benefit from rising gold and silver prices.
Additionally, gold often rises when risks are high, like the current Russia-Ukraine and Israel-Gaza crises. Its safe haven appeal attracts buyers during geopolitical tensions. Between high inflation and geopolitical uncertainty, the macroeconomic environment seems favorable for both precious metal and base metal prices. This could kickstart a broad recovery across the mining sector.
The recent wave of mergers and acquisitions in mining also signals a positive shift. . In November 2023, Newmont Corporation completed its acquisition of Newcrest Mining Limited to create a leading global gold mining company with robust copper production. Just this month, Rio Tinto announced an $825 million lithium project purchase to support its battery materials business. These deals indicate big miners are positioning to capitalize on the electric vehicle revolution. Other companies like Century Lithium Corp. aim to produce lithium for the electric vehicle and battery storage market.
Additionally, mining stocks have held up well compared to the broader market’s decline. The global lithium stock index has surged over 110% in the past year. Many mining stocks linked to EVs have shown resilience amidst the tech stock plunge. This relative strength highlights the bullish outlook for miners enabling the energy transition. Noble Capital Markets’ investment banker Francisco Penafiel shared that “In the recent past, battery minerals have been getting the attention from investors, especially critical metals such as lithium and cobalt. However, base metals like copper and nickel should also gain a healthy traction from the investment community, narrowing the existing valuation gap for junior miners, due to the expected increase in their market demand as those are essential in the creation process of more efficient battery technologies”.
After years of underperformance, mining stocks also look attractive relative to potential growth. For instance, the price-to-earnings ratio for diversified mining giant Glencore is under 6x, a bargain compared to high-flying tech stocks. While mining is volatile, long-term investors could be rewarded handsomely for their patience. The time seems ripe for mining stocks to revert upward after years of neglect.
Of course, risks exist like policy changes, permitting issues, cost inflation, and ESG concerns. But the overarching trend toward electrification seems unstoppable. While mining is cyclical, we appear to be entering an upcycle driven by underinvestment in new supply and exploding demand for the minerals needed to power the green transition.
Noble Capital Markets’ Senior Research Analyst, Mark Reichman states, “Our outlook for the mining sector remains favorable, particularly for the precious metals mining sub-sector. We believe growing electrification among developed nations and increased infrastructure spending bodes well for the long-term outlooks for metals such as copper, lithium, rare earths, and nickel. We think M&A activity will continue as large mining, energy, car manufacturers, and battery makers seek to de-risk their long-term strategies by ensuring long-term supplies of raw materials.”
In summary, mining stocks check many important boxes right now – strong demand drivers, favorable macro conditions, M&A activity, and reasonable valuations after a prolonged slump. The long-overlooked mining space seems poised for a renaissance, offering investors exciting opportunities. The winds appear to be shifting in favor of mining stocks as we embark on the new year and beyond. After years stuck in the doldrums, mining finally looks set to retake the spotlight.
The energy sector experienced a major shakeup today as Sunoco LP announced it will acquire NuStar Energy in an all-stock deal valued at approximately $7.3 billion including debt. The blockbuster acquisition aims to create a more diversified and vertically integrated energy company with an expanded footprint across the value chain.
For Sunoco, the deal provides a number of key benefits that will strengthen its operations and financial position. Most notably, it will gain NuStar’s extensive pipeline and storage terminal network which spans over 9,500 miles across the United States. This will provide greater scale and diversification to Sunoco’s current focus on fuel distribution and retail. As pipeline assets generate steady contracted revenues, the acquisition is expected to add stability and predictability to cash flows.
The larger cash flow base will also improve Sunoco’s credit profile and enhance its financial flexibility. This will enable accelerated deleveraging while also supporting steady distribution growth. Management estimates the deal will be immediately accretive to distributable cash flow per unit by 10%+ within three years. Ongoing synergies of $150 million annually will also boost the bottom line.
Vertically integrating NuStar’s transportation and storage activities with Sunoco’s strengths in distribution and retail is another major strategic benefit. This will help optimize operations across the integrated value chain and lead to further efficiency gains over time. Cost savings are forecasted at $50 million per year.
For the energy sector overall, the deal also has important implications. The combined entity will control critical infrastructure delivering refined products across the United States. With its expanded footprint, Sunoco will play an even more pivotal role ensuring energy supplies are reliably transported to end-users nationwide.
The acquisition also arrives at a challenging time for the industry. Many energy companies are facing pressure from the transition towards renewable power. By combining forces, Sunoco and NuStar can cut costs, leverage their size and scale, and invest in new growth opportunities. This will ultimately strengthen their competitiveness and staying power.
However, the deal does raise some regulatory concerns. With its extensive control over pipelines and storage capacity, the merged company could potentially restrict competitors’ access. Watchdogs will want to ensure open access at fair rates. Still, management emphasized the acquisition will have a positive financial outlook and support continued distribution growth. This should benefit both sets of unitholders if the deal is approved as expected.
Looking ahead, the acquisition positions Sunoco and NuStar to play a pivotal role in the future of US energy infrastructure. Their integrated network will be crucial for delivering traditional and renewable fuels as the industry evolves. With enhanced financial strength and flexibility, the combined giants now have greater capacity to adapt and seize new opportunities in the years ahead.
Chesapeake Energy is making a massive bet on the future of natural gas with its just-announced $7.4 billion all-stock acquisition of rival Southwestern Energy. The deal, announced Thursday morning, will create a natural gas behemoth and make Chesapeake the largest natural gas producer in the United States.
The deal reflects Chesapeake’s bullish outlook on natural gas amid a wave of consolidation in the U.S. energy sector. Major players like Exxon and Chevron have recently snapped up Permian Basin leaders like Pioneer Natural Resources and Hess Corporation with multi-billion dollar deals. Now Chesapeake is looking to cement its dominance in natural gas production through its purchase of Southwestern’s assets primarily located in the Haynesville basin of Louisiana and the Appalachian shale formations.
Chesapeake itself emerged from bankruptcy just two years ago in 2021 and has been aggressively rebuilding under CEO Nick Dell’Osso. It has honed in on natural gas assets and production, believing gas will play an integral role in the global energy transition away from dirtier fossil fuels. Natural gas emits 50-60% less carbon dioxide when combusted compared to coal, but still faces criticism from environmentalists.
The Southwestern deal doubles down on this gas-focused strategy. The combined company will churn out a mammoth 7.9 billion cubic feet per day of natural gas production. That is enough to rocket Chesapeake past EQT Corporation as the top natural gas producer based on volume. Chesapeake already boosted its gas position last year with the $2.5 billion purchase of Chief E&D.
Chesapeake is offering Southwestern shareholders $6.69 per share, representing a slight 3% discount to Southwestern’s last closing share price. The deal values Southwestern at around $7.4 billion. Chesapeake shareholders will own approximately 60% of the merged entity, with Southwestern shareholders owning the remaining 40%.
Southwestern gives Chesapeake key positions in two of the most prolific U.S. natural gas plays. Its Marcellus Shale assets in Pennsylvania and West Virginia dovetail perfectly with Chesapeake’s existing Northeast presence. Southwestern also brings over 700,000 Haynesville acres, solidifying Chesapeake’s status as the dominant player in the basin.
The merger is expected to unlock $350-400 million in annual cost synergies within the first two years, a major boost to cash flows. Chesapeake predicts the deal will be accretive to all relevant 2023 per-share metrics. The combined company will retain Chesapeake’s investment grade credit rating and chop net debt to EBITDAX from 1.5x to under 1.3x in 2023.
Chesapeake CEO Dell’Osso will stay on as chief executive of the merged entity. He called the deal “highly compelling” and said it will “further enhance free cash flow growth and return of capital to shareholders.”
Natural gas prices face near-term headwinds, having plunged over 60% last year due to ballooning inventory levels and mild winter weather. But long-term projections remain bullish, especially if more coal generation is retired and replaced by gas. LNG export facilities continue expanding along the Gulf Coast, offering producers prime access to higher-priced global markets.
Chesapeake is betting big that natural gas will retain a substantial role in the global energy mix even as zero-carbon sources like wind and solar grow. If gas demand rises as expected, Chesapeake will be sitting pretty as the largest U.S. producer. But execution risks remain, as the two companies integrate operations and work through the challenges of joining two complex businesses.
The deal is expected to close in Q2 2024, pending shareholder and regulatory approval. But Chesapeake is already taking a victory lap, believing the tie-up cements its status as a premier U.S. natural gas producer for decades to come.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
As indicated in our recent energy industry report, energy prices were weak in the quarter ended December 21, 2023. WTI oil prices averaged $78.41/bbl. below our $80/bbl. estimate. Henry Hub natural gas prices averaged $2.74/mcf. versus our $3.25/mcf estimate due to warm weather. The C$ to US$ exchange rate was 1.35 times versus our 1.33 estimate.
We are adjusted our estimates modestly to reflect updated energy price and exchange rate numbers. We now project December quarter revenues of C$27.1 million, down from C$27.7 million. Our EBITDA estimate for the quarter is now C$16.7 million versus C$17.2 million and our Adjusted Fund Flow estimate is C$13.2 million versus C$13.4 million. Our earnings per share estimate remains $0.11. We have not made any changes to our 2024 estimates.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
InPlay Oil is a junior oil and gas exploration and production company with operations in Alberta focused on light oil production. The company operates long-lived, low-decline properties with drilling development and enhanced oil recovery potential as well as undeveloped lands with exploration possibilities. The common shares of InPlay trade on the Toronto Stock Exchange under the symbol IPO and the OTCQX Exchange under the symbol IPOOF.
Michael Heim, Senior Vice President, Equity Research Analyst, Energy & Transportation, Noble Capital Markets, Inc.
Refer to the full report for the price target, fundamental analysis, and rating.
As indicated in our last energy industry report, oil and natural gas prices were weak in the December quarter. WTI oil prices averaged $78.40/bbl. in the quarter, below our previous estimate of $80/bbl. Henry Hub natural gas prices average $2.74/mcf., below our previous estimate of $3.25/mcf. due to warm weather. The C$ to US$ exchange rate was 1.35 times, slightly higher than our 1.33 estimate. We have adjusted our InPlay models to reflect updated results.
We are fine tuning our estimates to reflect lower energy prices and a higher exchange rate. Our revenue estimate for the 2023 December quarter has been lowered to C$44.7 million from C$47.2 million. Our EBITDA estimate for the quarter is now C$23.3 million, down from C$25.5 million and our Adjusted Fund Flow estimate is C$18.9 million, down from C$20.6 million. Our EPS estimate for the quarter drops to C$0.08 from C$0.09. We have not made any changes to our 2024 estimates. With this report, we are initiating 2024 quarterly estimates.
Equity Research is available at no cost to Registered users of Channelchek. Not a Member? Click ‘Join’ to join the Channelchek Community. There is no cost to register, and we never collect credit card information.
This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).
*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision.
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.
