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.
Vancouver, British Columbia–(Newsfile Corp. – December 18, 2023) – Hemisphere Energy Corporation (TSXV: HME) (OTCQX: HMENF) (“Hemisphere” or the “Company”) is pleased to announce the appointment of Ashley Ramsden-Wood as Chief Development Officer.
Ms. Ramsden-Wood has served as Vice President of Engineering at Hemisphere since 2014 and has been instrumental in the successful growth and development of the Company. Along with her technical engineering strengths, Ms. Ramsden-Wood provides invaluable contributions to corporate affairs, capital planning, business development, strategic growth initiatives, and financial performance analysis.
Additionally, in accordance with the Company’s stock option plan, the Company has granted incentive stock options to purchase up to 1.37 million common shares to directors, officers, and investor relations personnel at an exercise price of $1.27 per share until December 15, 2028.
About Hemisphere Energy Corporation
Hemisphere is a dividend-paying Canadian oil company focused on maximizing value per share growth with the sustainable development of its high netback, low decline conventional heavy oil assets through polymer flood enhanced recovery methods. Hemisphere trades on the TSX Venture Exchange as a Tier 1 issuer under the symbol “HME” and on the OTCQX Venture Marketplace under the symbol “HMENF”.
For further information, please visit the Company’s website at www.hemisphereenergy.ca to view its corporate presentation or contact:
Don Simmons, President & Chief Executive Officer Telephone: (604) 685-9255 Email: info@hemisphereenergy.ca
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
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.
Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.
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.
Alvopetro released November production volumes that accelerated its recent upward trend. Alvopetro reported November gas production of 12.9 mmcfe/day (up from 10.6 mmcfe/day in October), oil production of 15 boe/day (vs. 8 boe/day), and NGL production of 105 boe/day (up from 67 boe/day). Production was depressed over the summer due to allocation issues with a joint venture partner and demand issues from Bahia Gas, Alvopetro’s primary natural gas customer. Total production was 2,264 boe/day in November.
Total production remains below peak levels but is approaching that level quickly. Production peaked at 2,771 MBOE/day in the quarter ended March 31, 2023. However, with production rising 425 MBOE/day in the most recent month, it is quickly returning to past production levels. Importantly, oil and natural gas production is the fastest growing component of Alvopetro energy portfolio providing additional diversification and lessening its reliance on Bahia Gas.
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.
As the next pivotal United Nations climate change conference quickly approaches, the COP28 summit to be held in Dubai has already attracted controversy before it even begins. Critics argue the UAE’s plans to use its host status to lobby for oil and gas deals creates an irreconcilable conflict of interest. This brewing scandal underscores risks for the energy investment community in navigating the global green transition.
Leaked documents revealed the summit’s president, Sultan Al-Jaber, intends to meet with officials from over a dozen countries to promote fossil fuel projects. As CEO of Abu Dhabi National Oil Company (ADNOC), the world’s 12th largest oil producer, Al-Jaber seemingly represents business as usual in the hydrocarbon sector – precisely as climate scientists urge rapid movement away from planet-warming emissions. This dual role as OPEC’s former president alongside COP28 president epitomizes the conference’s core tension.
While the UAE defends Al-Jaber’s energy background as an asset for summit leadership, others see an fox guarding the henhouse. Renewable energy interests hope COP meetings accelerate emissions cuts to open investment opportunities and meet targeted market shares. In contrast, unchecked fossil fuel dominance could strand assets and leave oil-rich economies behind. For financial institutions, balancing these competing interests grows increasingly complex.
As the global community seeks alignment on climate policy, COP28 takes on heightened importance after last year’s loss of momentum in Egypt. But with Al-Jaber pushing liquefied natural gas deals behind the scenes, the summit’s bold ambitions appear under threat – before even officially starting next week. This risks paralyzing investors betting on meaningful multilateral progress from the 12-day affair.
Rather than showcasing global unity, the conference could further fragment cooperative efforts. Those banking on strengthened commitments and standardized transparency may be severely disappointed. An already divided energy landscape would only become more fractured and filled with uncertainties.
While surging energy prices have boosted oil and gas profits recently, leaving firms cash rich for transitions, alerts sound over stranded asset dangers in the longer run. Without reliable political tailwinds, capital allocation planning swims in obscurity. Investors may continue clinging to the devil they know, slowing sustainability spending despite rhetorical Net Zero pledges.
ESG fund managers face particularly hard choices weighing reputational concerns with fiduciary obligations, as greenwashing allegations persist. Index providers must carefully contemplate emissions-heavy exposure amid heightening transition materiality. Even hydrocarbon majors pursuing renewables see climate credibility doubly damaged by COP28 coziness with embedded fossil fuel agendas.
In effect, the UAE’s COP28 aspirations throw harsh light on the messy entanglements linking energy incumbents to global cooperation imperatives. This summit was envisioned for closing gaps to carbon neutrality – not leveraging elite access for oil field services contracts or petrochemical exports. Dubai’s shone vision as progressive climate broker now sees tarnish.
While Al-Jaber resides at the controversy’s core, larger questions confront energy interests worldwide. How can multinational forums effectively drive sustainability without undermining diverse domestic interests or economic lifelines? Does climate progress rely on energy industrialists gradually conceding ground? Regardless of COP28’s impact, these dilemmas will persist in boardrooms everywhere industries collide with ecological boundaries.
For anxious energy investors, perhaps the greatest risk is policy paralysis. Without milestone markers implemented, capital deployment floats ambiguously while net-zero targets linger out of reach. Until political will consolidates around winding down emissions directly, bankers and shareholders face accumulating uncertainty handicapping strategic decision-making.
Of course, COP meetings have always brought thorny issues to the surface divisions easy to ignore otherwise. But the solution remains clear even if the path does not: economics needs ecology for human prosperity’s endurance. For financial players, that means sustained stakeholder value depends on sustainable business practices without exception. What hangs in the balance moving forward is how smoothly the global energy complex can stick that critical landing.
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.
2023-2Q production rose as expected with new wells coming online. A robust summer of drilling resulted in higher production. Post-quarter flow rates allow us to bump up future production estimates.
Realized prices came in better than expected. The basin discount was reduced adding to the rise in oil index prices. Management added swaps at attractive prices in response to higher oil prices.
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.
Oil markets were thrown into turmoil on Wednesday after the OPEC+ alliance unexpectedly postponed a critical meeting to determine production levels. Prices promptly plunged over 5% as hopes for additional output cuts to stabilize crude markets were dashed, at least temporarily.
The closely-watched meeting was originally slated for December 3-4. But OPEC+, which includes the 13 member countries of the Organization of Petroleum Exporting Countries along with Russia and other non-members, said the summit would now take place on December 6 instead, offering no explanation for the delay.
The last-minute postponement fueled speculation that the group is struggling to build consensus around boosting production cuts aimed at reversing oil’s steep two-month slide. Disagreements apparently center on Saudi dissatisfaction with other nations flouting their output quotas. Compliance has emerged as a major flashpoint as oil revenue pressures intensify amid rising recession fears.
Prices Rally on Cut Hopes
In recent weeks, oil had rebounded from mid-October lows on mounting expectations that OPEC+ would intervene to tighten supply and put a floor under prices once more.
The alliance has already removed over 5 million barrels per day since 2023 through unilateral Saudi production cuts and collective OPEC+ reductions. But crude has continued drifting lower, with Brent plunging below $80 per barrel last week for the first time since January.
Demand outlooks have deteriorated significantly, especially in China where crude imports fell in October to their lowest since 2007. At the same time, releases from strategic petroleum reserves and resilient non-OPEC production have expanded inventories, exacerbating the supply glut.
Output Quotas Trigger Internal Rifts
Energy analysts widely anticipate that OPEC+ will finalize plans at next week’s rescheduled talks to extend existing production cuts until mid-2024. Saudi Arabia and Russia, the alliance’s de factor leaders, both support additional trims.
However, firming up commitments from the broader group may prove challenging. Crude exports are critical to the economies of many member nations. With government budgets squeezed by weakened prices, some countries have little incentive to curb production.
Unconfirmed reports suggest that Saudi Arabia demanded Iraq and several other laggards bolster compliance with quotas before it agrees to further output reductions. But getting all parties in line with their assigned targets has long confounded the alliance.
Where Oil Goes Next
For now, oil markets are in limbo awaiting next Thursday’s OPEC+ gathering. Prices could see added volatility until the cartel unveils its plans.
Most analysts still expect that additional cuts will emerge, possibly in the 500,000 barrels per day range. That may be enough to place a temporary floor under the market and keep Brent crude from approaching $70 per barrel.
But if internal dissent paralyzes OPEC+ from reaching an agreement, or one that falls significantly short of projections, another downward spiral is probable. Pressure would only escalate on the alliance to take more drastic actions to stabilize prices in 2024 as economic storm clouds gather.
Oklahoma City-based Mach Natural Resources LP announced Monday that it has agreed to acquire oil and gas assets in Oklahoma’s Anadarko Basin from Paloma Partners IV, LLC for $815 million. The deal marks a significant expansion for Mach as it looks to increase production and proved reserves.
The acquisition includes approximately 62,000 net acres concentrated in the core counties of Canadian and Grady, along with recent production of around 32,000 barrels of oil equivalent per day. Mach cited substantial proved developed producing (PDP) reserves of 75 million barrels of oil equivalent and over a decade’s worth of drilling inventory supporting the transaction.
Mach was attracted to the assets’ high margin oil production and potential for further development. The company said the purchase advances its strategy of focusing on distributions, disciplined acquisitions, maintaining low leverage, and keeping the reinvestment rate under 50%. According to Mach, the deal is accretive to cash available for distribution and cash distribution per unit.
The properties change hands with one rig currently running in Grady County and plans for 6 more wells to be completed before the expected December 29 closing. Post-acquisition, Mach intends to add another rig, continuing its measured approach to capital spending.
The purchase price reflects discounted PDP value, presenting an opportunity for Mach to boost near-term cash flow. At the same time, the company is bringing aboard de-risked SCOOP/STACK drilling locations that can fuel longer-term growth.
To finance the $815 million transaction, Mach has lined up committed debt financing led by Chambers Energy Management and EOC Partners. The senior secured term loan will provide $825 million at the closing date. Mach stated that its leverage ratio will remain below 1.0x debt to EBITDA after absorbing the new debt.
Mach’s Chief Executive Officer commented, “This transaction creates significant value for our unitholders and represents an important step in executing our strategic vision. We look forward to developing these high-quality assets and welcoming a talented local team to the Mach family.”
The seller, Paloma Partners IV, is backed by private equity firms EnCap Investments and its affiliates. Paloma amassed the properties in 2017 and 2018 when SCOOP/STACK deal activity was high. Its divestiture to Mach comes amidst a cooling of M&A in the play.
Mach was founded in 2021 with an emphasis on shareholder returns and steady growth in Oklahoma’s Anadarko Basin. The company currently runs a two-rig development program on its legacy acreage position.
The Anadarko Basin has seen resurgent activity as producers apply drilling and completion technology to unlock the potential of the SCOOP and STACK plays. Operators continue to drive down costs and improve productivity in the prolific geological formations.
Mach’s new Grady County acreage provides exposure to the volatile oil window of the SCOOP Woodford condensate play. Well results in the area have benefited from longer laterals, increased sand loadings, and optimized well spacing.
Canadian County offers additional Woodford potential plus stacked pays in the Meramec, Osage and Oswego horizons. Together, these reservoirs offer a mix of liquids-rich gas and high-margin oil for Mach’s operated portfolio.
With its firm financial footing and expanded operational scale, Mach appears positioned for further consolidation in the Anadarko Basin. The company now controls over 150,000 net acres in the region. Its proven strategy may attract additional sellers seeking to divest non-core acreage and realize value from their own holdings.
Mach can leverage its expanded position and technical expertise to exploit not only the SCOOP and STACK but also emerging zones like the Osage and Cottage Grove. The company anticipates its enlarged inventory will support steady production growth and consistent cash returns in the years ahead.
Monday’s major acquisition cements Mach Natural Resource’s status as a premier independent operator in the Anadarko Basin. The company seems intent on delivering on its promises of accretive growth, high cash margins, and peer-leading capital discipline. For Mach, size and scale will likely prove critical in generating free cash flow and distributions in a commodity price environment with little room for error.
Crescent Point Energy has entered into an agreement to acquire fellow Canadian oil producer Hammerhead Resources in an all-stock deal valued at approximately $2.55 billion. The deal will expand Crescent Point’s presence in the Alberta Montney, adding over 100,000 contiguous net acres directly adjacent to its existing land position.
Under the terms, Hammerhead shareholders will receive 0.46 share of Crescent Point common stock and $21.00 cash for each Hammerhead share. That values Hammerhead at around $45,500 per flowing barrel of production.
Strategic Fit Strengthens Key Focus Areas
The acquisition solidifies Crescent Point’s dominant position in two of Canada’s premier unconventional oil plays. It becomes the largest landholder in both the Alberta Montney and Kaybob Duvernay resource plays.
Crescent Point gains over 800 net high-value drilling locations in the Montney through the deal. This boosts its total premium inventory depth to over 20 years, creating a strong long-term growth profile.
The acquired Montney lands also carry attractive royalty rates and have promising geological characteristics analogous to Crescent Point’s existing acreage. Horizontal drilling and completions technologies have unlocked the vast resource potential of the Montney in recent years.
Significant infrastructure owned by Hammerhead, including oil batteries, water disposal, and gas gathering lines, will also transfer over and support growth plans.
Immediate Impact on Cash Flow and Dividend
According to Crescent Point’s estimates, the deal will increase excess cash flow per share by over 15% on average from 2023-2027. This comes atop the company’s existing 5-10% organic growth outlook.
The increased cash generation provides support for a 15% dividend hike to $0.46 annually upon closing the acquisition. Crescent Point’s balance sheet remains a priority, with net debt expected to decline to 1.1x adjusted funds flow by year-end 2024.
Hammerhead’s current production of 56,000 boe/d (50% oil) is expected to increase to over 80,000 boe/d by 2024. With Hammerhead’s low-decline asset base, Crescent Point sees minimal stabilization capital required to sustain output.
Consolidation Creates Scale
Pro-forma the acquisition, Crescent Point will become Canada’s 7th largest energy producer pumping over 200,000 boe/d. The increased scale provides improved access to capital and potential cost efficiencies.
The company also gains key personnel from Hammerhead to further enhance technical and operational expertise across asset teams.
CEO Craig Bryksa said the deal transforms Crescent Point into a Montney and Duvernay focused producer, complemented by its Saskatchewan assets. The consolidation “is an integral part of our overall portfolio transformation,” Bryksa noted.
Crescent Point says its near-term priorities now center on integrating Hammerhead efficiently, executing planned programs, strengthening its balance sheet, and returning increasing capital to shareholders.
For Hammerhead, the transaction provides liquidity after joining the private equity backed company just two years ago. It also positions shareholders to participate in Crescent Point’s significant free cash flow growth in the coming years.
Subject to shareholder, court, and regulatory approvals, the acquisition is expected to close in Q4 2022. The deal will cement Crescent Point’s standing as a dominant Montney producer and provides visible growth underpinned by its expanded low-risk drilling inventory.
CALGARY, AB, Nov. 9, 2023 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company“) today announced that the Toronto Stock Exchange (“TSX“) has accepted InPlay’s notice of intention to renew its normal course issuer bid for a further one year term (the “NCIB“). The previous NCIB expired on October 16, 2023. Pursuant to the Company’s previous NCIB, the Company purchased in the open market through the facilities of the TSX and through other alternative Canadian trading platforms and cancelled an aggregate of 190,400 common shares (“Common Shares“) of the Company at an average price paid of $2.84 per Common Share.
Under the NCIB, InPlay may purchase for cancellation, from time to time, as InPlay considers advisable, up to a maximum of 6,637,064 Common Shares, which represents 10% of the Company’s public float of 66,370,643 Common Shares as at October 31, 2023. As of the same date, InPlay had 90,925,401 Common Shares issued and outstanding. Purchases of Common Shares may be made on the open market through the facilities of the TSX and through other alternative Canadian trading platforms at the prevailing market price at the time of such transaction. The actual number of Common Shares that may be purchased for cancellation and the timing of any such purchases will be determined by InPlay, subject to a maximum daily purchase limitation of 43,809 Common Shares which equates to 25% of InPlay’s average daily trading volume of 175,239 Common Shares for the six months ended October 31, 2023. InPlay may make one block purchase per calendar week which exceeds the daily repurchase restrictions. Any Common Shares that are purchased by InPlay under the NCIB will be cancelled.
The NCIB will commence on November 14, 2023 and will terminate on November 13, 2024 or such earlier time as the NCIB is completed or terminated at the option of InPlay.
InPlay believes that renewing the NCIB is a prudent step in this volatile energy market environment, when at times, the prevailing market price does not reflect the underlying value of its Common Shares. The timely repurchase of the Company’s Common Shares for cancellation represents confidence in the long term prospects and sustainability of its business model. This reduction in share count adds per share value to InPlay’s shareholders and adds another tool to management’s disciplined capital allocation strategy.
With the base dividend of $0.015/share per month, NCIB share repurchases and the Company’s continued efforts towards towards overall production per share growth, InPlay will be able to continue with its strategy of providing strong returns to shareholders.
About InPlay Oil Corp.
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 on the Toronto Stock Exchange under the symbol IPO and the OTCQX under the symbol IPOOF.
For further information please contact:
Doug Bartole President and Chief Executive Officer InPlay Oil Corp. Telephone: (587) 955-0632
This news release contains certain statements that may constitute forward-looking information within the meaning of applicable securities laws. This information includes, but is not limited to InPlay’s intentions with respect to the NCIB and purchases thereunder and the effects of repurchases under the NCIB. Although InPlay believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because InPlay can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions by their very nature they involve inherent risks and uncertainties. Actual results could defer materially from those currently anticipated due to a number of factors and risks. Certain of these risks are set out in more detail in InPlay’s Annual Information Form which has been filed on SEDAR+ and can be accessed at www.sedarplus.com.
The forward-looking statements contained in this press release are made as of the date hereof and InPlay undertakes no obligation to update publically or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
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.
Production increased 6% quarter over quarter despite continued curtailments and unplanned downtime. Curtailments and well pressure issues have hampered production for InPlay and other Canadian producers in recent quarters. InPlay invested $27.5 million during the quarter to drill and make infrastructure improvements. This represents more than half of the year’s capital expenditure budget. During the quarter, the company completed six wells and upgraded a natural gas facility to process 66% more gas.
InPlay reported strong results in the 2023-3Q and 2023-4Q should be better. Management indicated that its investments should lead to the fourth quarter being the highest production quarter of the year. Management did not make any changes to its guidance for 2023, 2024, and 2025 production and fund flow generation. With a drop in capital expenditures in the upcoming quarter, management should have ample cash flow to pay dividends (7% yield), strategically repurchase shares, and explore small add-on acquisitions.
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.
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CALGARY AB, Nov. 8, 2023 /CNW/ – InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its financial and operating results for the three and nine months ended September 30, 2023. InPlay’s condensed unaudited interim financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three and nine months ended September 30, 2023 will be available at “www.sedar.com” and our website at “www.inplayoil.com“.
Third Quarter 2023 Financial & Operating Highlights
Realized average quarterly production of 9,003 boe/d(1) (57% light crude oil and NGLs), a 6% increase compared to 8,474 boe/d (57% light crude oil and NGLs) in the second quarter of 2023 despite extended curtailments and unplanned downtime experienced in the quarter of approximately 550 boe/d.
Generated strong quarterly adjusted funds flow (“AFF”)(2) of $25.2 million ($0.28 per basic share(3)), an increase of 16% from the second quarter of 2023.
Returned $4.0 million ($12.0 million in the first nine months of 2023) directly to shareholders through our monthly base dividend.
Increased revenues by 17% to $46.7 million compared to $39.8 million in the second quarter of 2023.
Improved field operating netbacks(3) by 8% compared to the second quarter of 2023.
Achieved net income of $7.5 million ($0.08 per basic share; $0.08 per diluted share). InPlay has now returned to a retained earnings position on the balance sheet demonstrating that the Company has generated positive earnings since inception (net of dividends paid).
Invested $27.5 million to drill, complete and equip three (2.9 net) Extended Reach Horizontal (“ERH”) wells in Willesden Green, three (3.0 net) ERH wells in Pembina and one (0.35 net) non-operated ERH well in Willesden Green.
Fourth Quarter Operational Update:
Drilled and completed two (1.6 net) ERH wells in Willesden Green which were recently put on production.
The three (3.0 net) Pembina ERH wells brought on production shortly before start of the quarter are producing at strong rates of approximately 260 boe/d(1) (87% light crude oil and NGLs) per well.
Brought online our second natural gas facility upgrade at Leafland, which has increased operated facility capacity by 66% while improving our liquids yield by 40%. Production benefits are already being realized through reduced back pressure on wells, lower declines and providing more consistent runtimes.
Current production is 9,700 boe/d(1) (60% light crude oil and NGLs) based on field estimates., excluding the impact of the two (1.6 net) ERH wells in Willesden Green showing strong flowback rates in the early clean up stage.
Third Quarter 2023 Financial & Operations Overview:
The third quarter of 2023 was a capital intensive quarter for the Company. InPlay invested $27.5 million drilling, completing and equipping three (2.9 net) ERH wells in Willesden Green and three (3.0 net) ERH wells in Pembina. The Company also participated in one (0.35 net) non-operated ERH well in Willesden Green not previously budgeted.
In addition to the upgrade of a natural gas facility in the second quarter, the Company completed a second material upgrade of a gas facility during the third quarter which was brought back on-line in early October. This project modernized existing infrastructure in the Leafland area of Willesden Green and has resulted in an approximate 66% increase to the natural gas processing capability of this facility. The addition of a refrigeration plant to this facility has also improved NGL recoveries by approximately 40%. This additional capacity has lowered field pressures in the area which is expected to improve production and reduce declines on existing wells and future drilling locations. This upgrade is expected to accommodate future development in Leafland and provide more consistent and reliable processing capacity within the Company’s operational control.
The Company has been focused on a high oil weighted drilling program. Three (2.9 net) Willesden Green ERH wells came on production in August into high pressure pipeline systems with average initial production (“IP”) rates per well of 203 boe/d(1) (94% light crude oil and NGLs) over their first 30 days and 215 boe/d(1) (93% light crude oil and NGLs) over their first 60 days. The impact of our facility improvements has enabled these wells to have multiple weeks of flat to improving production rates and after two months they continue to produce at an average rate of approximately 280 boe/d(1) (87% light crude oil and NGLs) per well. The production witnessed from the most recent six wells drilled in Willesden Green have recently benefitted from reduced field pressures and consistent facility runtimes resulting from our operated natural gas facility expansions.
In addition, three (3.0 net) Pembina ERH wells came on production at the end of September with average initial production (“IP”) rates per well of 227 boe/d(1) (88% light crude oil and NGLs) over their first 30 days. These wells have also continued to clean up after completions and are currently producing approximately 260 boe/d(1) (87% light crude oil and NGLs) per well.
Production for the three months ended September 30, 2023 averaged 9,003 boe/d(1) (57% light crude oil and NGLs), 6% higher compared to the three months ended June 30, 2023. Third quarter production was impacted by approximately 550 boe/d (52% light crude oil and NGLs) primarily due to the continuation of multiple third-party natural gas takeaway constraints on our operations and the commissioning of our expanded gas facility that slightly exceeded the anticipated startup timeline. The continued third-party facility outages forced the redirection of associated natural gas to less favorable third-party facilities impacting production through increased back pressure on producing wells as well as higher operating costs.
InPlay generated AFF(2) of $25.2 million ($0.28 per basic share) an increase of 16% from the second quarter of 2023. The Company achieved net income of $7.5 million ($0.08 per basic share; $0.08 per diluted share) and has returned to a retained earnings position on the balance sheet. This is evidence of the long-term sustainability of the Company as positive earnings have been generated since inception (net of dividends paid).
Outlook and Operations Update(5)
The majority of InPlay’s capital program for the year has been completed. The Company’s drilling program for the fourth quarter is underway with two (1.6 net) ERH wells in Willesden Green having been drilled to date. These two wells have been completed and are in the early stages of production. In addition, a 1.0 net Belly River well is now planned to be drilled in the fourth quarter and anticipated to come online in December with its first full month of production expected to commence in January 2024. This well replaces a previously planned one (0.8 net) Willesden Green well.
The investments made in increasing natural gas takeaway capacity through the two facility upgrades in Willesden Green will be important in alleviating potential production issues from third party facility outages going forward. These upgrades have increased our natural gas processing and takeaway capacity in Leafland from approximately 8,400 mcf/d to 17,300 mcf/d. These projects have already shown their importance by reducing back pressure on wells, lowering declines and providing more consistent runtimes, and the reduction in field pressures has the added benefit of improving our liquids weighting. Current production is approximately 9,700 boe/d(1) (60% light crude oil and NGLs) based on field estimates, excluding the impact of two (1.6 net) ERH wells in Willesden Green which are in early stage cleanup and with only four days of production are showing strong flowback rates.
As a result, the fourth quarter is forecasted to be our highest production quarter of the year and given the strong crude oil pricing environment and weak Canadian dollar, the fourth quarter is also projected to be our highest AFF quarter for the year. As the majority of the 2023 capital program was completed by the end of the third quarter, significant free adjusted funds flow (“FAFF”)(3) is expected to be generated in the fourth quarter resulting in a sizeable reduction to net debt prior to year-end.
The Company’s updated 2023 drilling program will be more active than previously planned by approximately 0.6 net wells consisting of 21 (17.1 net) horizontal wells. The changes include an additional one (0.35 net) non-op ERH Willesden Green well and a 1.0 net Belly River well instead of a previously planned one (0.8 net) Willesden Green well. As a result, InPlay has revised its 2023 development capital expenditure guidance to approximately $83 million(5). The timing of the Belly River well will not materially add to 2023 production but will pave the way for potentially an increased Belly River program in 2024 given the high oil weighting and high netback nature of this play. This area is defined by high light-oil weightings that receive a premium to the Mixed Sweet Blend (“MSW”), our pricing benchmark. Our two recent horizontal wells drilled in the area came online in November 2022 and have had operating netbacks of approximately $71.25/boe since being brought on production, and light oil and liquids weightings of approximately 94% to date. These wells have had very low decline rates over this period with average IP rates per well of 98 boe/d (97% light crude oil and NGLs) and 115 boe/d (92% light crude oil and NGLs) over their first 90 and 335 days respectively.
The Company remains committed to providing strong returns to shareholders. Our monthly base dividend of $0.015/share represents approximately a 7% yield at the current share price. To date, the Company has returned $16 million to shareholders through dividends since our inaugural dividend was declared in November 2022, representing approximately 7% of our current market capitalization while maintaining a strong financial position. The generation of shareholder returns through significant FAFF, top-tier production per share growth while maintaining low leverage all remain top priorities of InPlay.
InPlay would like to thank our staff, contractors, and suppliers for their continued dedication and execution, and thank the Board of Directors and shareholders for their continued guidance and support. We look forward to releasing our 2024 capital budget and associated guidance in January.
For further information please contact:
Doug Bartole President and Chief Executive Officer InPlay Oil Corp. Telephone: (587) 955-0632
See “Production Breakdown by Product Type” at the end of this press release.
2.
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
3.
Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release.
4.
Supplementary financial 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 previous and updated 2023 capital program and associated guidance.
Reader Advisories
Non-GAAP and Other Financial Measures
Throughout this press release and other materials disclosed by the Company, InPlay uses certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under GAAP and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with GAAP as indicators of the Company performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze InPlay’s business performance against prior periods on a comparable basis.
Non-GAAP Financial Measures and Ratios
Included in this document are references to the terms “free adjusted funds flow”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net Corporate Acquisitions”, “Debt adjusted production per 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 cashflows 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.
(thousands of dollars)
Three Months Ended September 30
Nine Months Ended September 30
2023
2022
2023
2022
Revenue
46,672
56,985
131,735
180,429
Royalties
(5,387)
(10,607)
(16,178)
(28,017)
Operating expenses
(12,677)
(10,946)
(36,343)
(30,660)
Transportation expenses
(698)
(888)
(2,190)
(2,802)
Operating income
27,910
34,544
77,024
118,950
Sales volume (Mboe)
828.3
873.5
2,411.2
2,438.1
Per boe
Revenue
56.35
65.24
54.63
74.00
Royalties
(6.50)
(12.14)
(6.71)
(11.49)
Operating expenses
(15.31)
(12.53)
(15.07)
(12.58)
Transportation expenses
(0.85)
(1.02)
(0.90)
(1.15)
Operating netback per boe
33.69
39.55
31.95
48.78
Operating income profit margin
60 %
61 %
58 %
66 %
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 September 30
Nine Months Ended September 30
2023
2022
2023
2022
Corporate acquisitions, net of cash acquired
–
89
–
501
Share consideration
–
–
–
–
Non-cash working capital acquired
–
–
–
–
Derivative contracts
–
–
–
–
Net Corporate acquisitions
–
89
–
501(1)
(1) During the nine months ended September 30, 2022, the acquired amount of Property, plant and equipment was adjusted by $0.5 million as a result of adjustments relating to the acquisition of Prairie Storm, 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 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 working capital (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 three months ended March 31, 2023. All references to adjusted funds flow throughout this MD&A 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 / Working Capital
Net debt / working capital is a GAAP measure and is disclosed in the notes to the Company’s financial statements for three months ended March 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 / working capital as part of its capital structure. The Company uses net debt / working capital (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 / working capital an important measure to assist in assessing the liquidity of the Company.
Supplementary Measures
“Average realized crude oil price” is comprised of crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s crude oil production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized NGL price” is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company’s NGL production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized natural gas price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized commodity price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Adjusted funds flow per weighted average basic share” is comprised of adjusted funds flow divided by the basic weighted average common shares.
“Adjusted funds flow per weighted average diluted share” is comprised of adjusted funds flow divided by the diluted weighted average common shares.
“Adjusted funds flow per boe” is comprised of adjusted funds flow divided by total production.
Forward-Looking Information and Statements
This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the Company’s business strategy, milestones and objectives; the Company’s planned 2023 capital program including wells to be drilled and completed and the timing of the same; the expectation that our Leafland gas facility upgrade will accommodate full development, provide consistent and reliable processing capacity, improve production on existing wells and future drilling locations and reduce production declines; accommodate full development in Leafland and provide consistent and reliable processing capacity within the Company’s operational control; 2023 guidance based on the planned capital program and all associated underlying assumptions set forth in this press release including, without limitation, forecasts of 2023 annual average production levels, debt adjusted production levels, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin, and Management’s belief that the Company can grow some or all of these attributes and specified measures; light crude oil and NGLs weighting estimates; that the fourth quarter is forecasted to be our highest production and AFF quarter of the year with significant FAFF generated resulting in a sizeable reduction to net debt and a material reduction to our leverage metrics; 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 2023 capital program; the amount and timing of capital projects; forecasted spending on decommissioning; expectations regarding third party processing constraints and maintenance shut ins and the timing and impact of the same; that the Company has the financial capability to deliver consistent return to shareholders and the dividend is supportable at a $55 WTI pricing environment until 2025; the potential for an increased Belly River program in 2024; the timing of the release of the Company’s 2024 capital budget and associated guidance; and methods of funding our capital program.
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; 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 long range plan; 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, InPlay’s long-term forecast, and potential dividends, 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 internal projections, expectations, or beliefs underlying our Board approved 2023 capital budget and associated guidance, as well as management’s preliminary estimates and targets in respect of plans for 2024 and beyond (which are not based on Board approved budgets at this time), are subject to change in light of, among other factors, the impact of world events including the Russia/Ukraine conflict, ongoing results, prevailing economic circumstances, volatile commodity prices, and industry conditions and regulations. InPlay’s 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. In this document reference is made to the Company’s longer range 2024 and beyond internal plan and associated economic model. Such information reflects internal estimates and targets used by management for the purposes of making capital investment decisions and for internal long-range planning and budget preparation. 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 2023, and more particularly 2024 and beyond, may not be appropriate for other purposes. Accordingly, undue reliance should not be placed on same.
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 capital program and associated guidance and long-term preliminary plans 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 2023 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 Company’s 2023 guidance remains the same as previously released August 14, 2023, with updated capital expenditures to $83 million. The 2023 guidance calculations which are impacted by this change are outlined below.
Actuals FY 2022
Updated Guidance FY 2023
Previous Guidance FY 2023(1)
Adjusted Funds Flow
$ millions
$131
$103 – $108
$103 – $108
Capital Expenditures
$ millions
$77.6
$83
$75 – $80
Free Adjusted Funds Flow
$ millions
$53
$20 – $25
$23 – $33
Actuals FY 2022
Updated Guidance FY 2023
Previous Guidance FY 2023(1)
Adjusted Funds Flow
$ millions
$131
$103 – $108
$103 – $108
Interest
$/boe
1.49
1.00 – 1.50
1.00 – 1.50
EBITDA
$ millions
$136
$108 – $113
$108 – $113
Working Capital (Net Debt)
$ millions
($33)
($35) – ($30)
($31) – ($27)
Net Debt/EBITDA
0.2
0.2 – 0.3
0.2 – 0.3
Actuals FY 2022
Updated Guidance FY 2023
Previous Guidance FY 2023(1)
Production
Boe/d
9,105
9,100 – 9,500
9,100 – 9,500
Opening Working Cap. (Net Debt)
$ millions
($80.2)
($33)
($33)
Ending Working Cap. (Net Debt)
$ millions
($33)
($35) – ($30)
($31) – ($27)
Weighted avg. outstanding shares
# millions
86.9
88.7
88.7
Assumed Share price
$
3.39(4)
2.75
2.75
Prod. per debt adj. share growth(3)
51 %
(3%) – 3%
0% – 5%
Actuals FY 2022
Updated Guidance FY 2023
Previous Guidance FY 2023(1)
Share outstanding, end of year
# millions
87.0
89.4
89.4
Assumed Share price
$
3.03(5)
2.75
2.75
Market capitalization
$ millions
$263
$246
$246
Working Capital (Net Debt)
$ millions
($33)
($35) – ($30)
($31) – ($27)
Enterprise value
$millions
$296
$276 – $281
$273 – $277
Adjusted Funds Flow
$ millions
$131
$103 – $108
$103 – $108
Interest
$/boe
1.49
1.00 – 1.50
1.00 – 1.50
Debt Adjusted AFF
$ millions
$136
$108 – $113
$108 – $113
EV/DAAFF
2.2
2.7 – 2.5
2.6 – 2.4
The Company’s 2024 and 2025 preliminary plans remains the same as previously released January 18, 2023, with net debt (working capital) updated to reflect the updated forecast 2023 ending net debt. The 2024 and 2025 preliminary plan guidance calculations which are impacted by this change are outlined below.
Updated Preliminary Plan FY 2024(6)
Updated Preliminary Plan FY 2025(6)
Previous Preliminary Plan FY 2024(2)(6)
Previous Preliminary Plan FY 2025(2)(6)
Adjusted Funds Flow
$ millions
$138 – $150
$144 – $154
$138 – $150
$144 – $154
Interest
$/boe
0.00 – 0.10
0.00 – 0.10
0.00 – 0.10
0.00 – 0.10
EBITDA
$ millions
$138 – $150
$144 – $154
$138 – $150
$144 – $154
Working Capital (Net Debt)
$ millions
$2 – $14
$45 – $56
$5 – $17
$48 – $59
Net Debt/EBITDA
(0.0) – (0.1)
(0.3) – (0.4)
(0.0) – (0.2)
(0.3) – (0.5)
Updated Preliminary Plan FY 2024(6)
Updated Preliminary Plan FY 2025(6)
Previous Preliminary Plan FY 2024(2)(6)
Previous Preliminary Plan FY 2025(2)(6)
Production
Boe/d
10,250 – 11,250
10,950 – 11,950
10,250 – 11,250
10,950 – 11,950
Opening Working Cap. (Net Debt)
$ millions
($35) – ($30)
$2 – $14
($31) – ($27)
$5 – $17
Ending Working Cap. (Net Debt)
$ millions
$2 – $14
$45 – $56
$5 – $17
$48 – $59
Weighted avg. outstanding shares
# millions
89.1
89.1
89.1
89.1
Assumed Share price
$
2.75
2.75
2.75
2.75
Prod. per debt adj. share growth(3)
28% – 48%
21% – 39%
28% – 48%
21% – 39%
Updated Preliminary Plan FY 2024(6)
Updated Preliminary Plan FY 2025(6)
Previous Preliminary Plan FY 2024(2)(6)
Previous Preliminary Plan FY 2025(2)(6)
Share outstanding, end of year
# millions
89.4
89.4
89.4
89.4
Assumed Share price
$
2.75
2.75
2.75
2.75
Market capitalization
$ millions
$246
$246
$246
$246
Working Capital (Net Debt)
$ millions
$2 – $14
$45 – $56
$5 – $17
$48 – $59
Enterprise value
$millions
$232 – $244
$190 – $201
$229 – $241
$187 – $198
Adjusted Funds Flow
$ millions
$138 – $150
$144 – $154
$138 – $150
$144 – $154
Interest
$/boe
0.00 – 0.10
0.00 – 0.10
0.00 – 0.10
0.00 – 0.10
Debt Adjusted AFF
$ millions
$138 – $150
$144 – $154
$138 – $150
$144 – $154
EV/DAAFF
1.8 – 1.5
1.4 – 1.2
1.8 – 1.5
1.4 – 1.2
(1)
As previously released August 14, 2023.
(2)
As previously released January 18, 2023.
(3)
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 working capital (net debt) divided by the Company’s current trading price on the TSX, converting working capital (net debt) to equity. Future share prices are assumed to be consistent with the current share price.
(4)
Weighted average share price throughout 2022.
(5)
Ending share price at December 31, 2022.
(6)
InPlay’s estimates and plans for 2024 and beyond remain preliminary in nature and do not, at this time, reflect a Board approved capital expenditure budget.
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 (net debt) are not assumed to have a material impact between the years presented above.
Test Results and Initial Production Rates
Test results and initial production (“IP”) rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed.
Production Breakdown by Product Type
Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51–101 and their respective quantities disclosed in the table below:
Light and Medium Crude oil(bbls/d)
NGLs(boe/d)
Conventional Natural gas(Mcf/d)
Total(boe/d)
Q1 2022 Average Production
3,571
1,307
20,054
8,221
Q2 2022 Average Production
3,865
1,333
23,191
9,063
Q3 2022 Average Production
3,717
1,432
26,075
9,495
2022 Average Production
3,766
1,402
23,623
9,105
Q1 2023 Average Production
3,788
1,458
22,648
9,020
Q2 2023 Average Production
3,658
1,187
21,772
8,474
Q3 2023 Average Production
3,697
1,420
23,316
9,003
2023 Annual Guidance
4,105
1,332
23,175
9,300(1)
2024 Annual Preliminary Plan
4,655
1,565
27,180
10,750(2)
2025 Annual Preliminary Plan
4,900
1,685
29,190
11,450(2)
Current Production
4,365
1,455
23,280
9,700
Q3 Pembina Wells (per well) – IP30
197
4
156
227
Q3 Pembina Wells (per well) – Current
220
5
210
260
Q3 WG Wells (per well) – IP30
188
3
72
203
Q3 WG Wells (per well) – IP60
196
3
96
215
Q3 WG Wells (per well) – Current
236
8
215
280
Notes:
1.
This reflects the mid-point of the Company’s 2023 production guidance range of 9,100 to 9,500 boe/d.
2.
This reflects the midpoint of the Company’s annual production preliminary estimate range.
3.
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 (“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.
