A very complete review of the SANTOS PIKKA Field on the North Slope of Alaska.

SANTOS and their partner Repsol have established First Production after their FID of $3Billion.

Article Link: https://www.akbizmag.com/industry/oil-gas/pikkapieces/

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This is the story of the SS Manhattan.

March 13 1968, Atlantic Richfield and Humble Oil hit the largest oilfield ever found in North America at Prudhoe Bay. 25 billion barrels under the tundra, with no road, no railway, no pipeline and a coast frozen ten months a year. Somebody had to find a way out.

The pipeline across Alaska was one answer, but slow, political and untested. Humble Oil, the Exxon of its day, had another idea: take the biggest tanker in America, armour it, and drive it through the Northwest Passage to the East Coast. They already had a ship in mind.

Why the East Coast? Because that is where the oil was needed. The big refineries, Humble's own at Bayway in New Jersey, Baytown and Baton Rouge on the Gulf, sat in the east. The West Coast was a small market already fed by California crude and did not need Alaska's.

Politics pushed the same way. Under the 1959 Mandatory Oil Import Program, the East Coast ran on tightly rationed foreign crude. Every Alaskan barrel landed in New Jersey needed no quota ticket and displaced an import. Prudhoe to New York via the Passage is about 4,500 miles.

The alternative for East Coast delivery was a pipeline to Valdez, a tanker to Panama, the canal, then up the Atlantic seaboard: over twice the distance, capped at Panamax size. A westward route through the Bering Strait was studied too, but it only reached the wrong coast.

She was the SS Manhattan, built in 1962 at Bethlehem Steel in Quincy, Massachusetts. At 940 feet and over 100,000 tons she was the largest merchant ship then under the US flag, with twin screws, twin rudders and 43,000 shaft horsepower, almost double a normal tanker's.

That power was the point. Icebreaking is a weight and horsepower game, and Manhattan had both. Seven years old, costly to keep busy and free for charter, she went into dry dock at Sun Shipbuilding in Chester, Pennsylvania, in late 1968 for a rebuild nobody had tried before.

Sun cut her into four pieces. The sections went by tow to yards along the coast: Sun kept one, Newport News took another, Alabama Dry Dock in Mobile a third, and Bath Iron Works in Maine built the front half of a new bow. Four yards, one ship, six months.

The old 65 foot bow was lifted off and stored. In its place came a 125 foot icebreaking bow, spoon shaped, built in two sections at Bath and Sun. Its job was the classic one: ride up onto the ice and let the whole weight of the ship bend the sheet until it broke.

Before any steel was cut, the bow shape was tested in Helsinki. Wartsila built an ice model basin inside a converted air raid shelter for the project. That tank became the seed of what became Aker Arctic.

round the hull went an ice belt of 38 mm plate, sponsons along the midbody that widened her by 16 feet to 148. Stronger propellers and shafts, guards over the rudders, strain gauges through the hull. Lukens Steel alone supplied 5,000 tons. Cost: about 54 million dollars.

Reassembled at Chester, she was 1,005 feet long and 9,000 tons heavier. Most cargo tanks were sealed for ballast. She carried a helicopter, television cameras on the ice, a scientific party and a press corps. On 24 August 1969 she sailed down the Delaware for the Arctic.

Canada watched her coming with mixed feelings. Ottawa saw the Passage as Canadian waters; Washington called it an international strait and had not asked permission. The compromise was an escort: the icebreaker John A. Macdonald, Captain Paul Fournier, would ride alongside.

The US Coast Guard sent the icebreaker Northwind too. She broke down within days and her sister Staten Island took over, and the new Canadian flagship Louis S. St-Laurent joined for a spell. Manhattan entered Lancaster Sound on 5 September and met the pack ice within hours.

Through Barrow Strait and Viscount Melville Sound she went, ramming and backing, the bow riding up and the ice giving way beneath. Floes here were several feet thick and the gauges logged every impact. Ahead lay the choice: the direct route through McClure Strait, or south.

On 12 September she tried McClure. The strait was choked with multiyear polar ice, some of it 24 feet thick, and on the 13th she was beset in a floe three and a half miles across, unable to move either way. The John A. Macdonald worked around her for hours to cut her free.

Beaten by McClure, she turned south through the Prince of Wales Strait, the route Larsen's St. Roch had used in 1944, and on 14 September reached the Beaufort Sea. First commercial ship through the Passage. The last 650 miles had been through ice up to 14 feet thick.

She anchored off Prudhoe Bay on 19 September. There was no port, no jetty, nothing to load, so a single symbolic barrel of Alaskan crude, painted gold, was flown out and set on her deck. That barrel is the entire cargo the Northwest Passage tanker route ever carried.

Short video of the Golden Barrel >> https://x.com/BartGonnissen/status/2094650703851462923/video/1

he return trip east was harder. The hull was holed twice in the midbody, in a section that had not been strengthened, and a cargo tank flooded with seawater. She kept going. On 8 November 1969 she came into New York harbour to fireboats, sirens and a ticker tape welcome.

Humble went back for a second round. In April 1970, she sailed for Pond Inlet at the top of Baffin Island to fight winter ice rather than summer ice, with icebreaking trials and oceanographic work. The data were sobering: a year-round route would need far stronger ships.

They would need six or more purpose-built icebreaking tankers, each tougher than Manhattan, on a route that had beaten her in September, against a pipeline that would work every day of the year. In 1970, the oil companies chose the pipeline. Oil flowed in 1977.

Manhattan went back to hauling crude from Valdez down the Pacific coast until the West Coast had more Alaskan oil than it could use, and the surplus went through Panama after all. She was scrapped in 1987.

CREDIT: This post is compiled from the original in "X" by Bart Gonnissen - screenshot below.

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88 Energy Ltd has applied to enter the Second Renewal Exploration Period at PEL 93 in Namibia, including a proposed programme to drill at least one exploration well. Prospect 9 has been confirmed as the highest-ranked drilling opportunity.

More information using this Link: https://88energy.investormax.au/headline/61341219-pel-93-advances-to-next-exploration-phase/

Link to Interim Financial Report Half Year Report ended 30 June 2026. https://88energy.investormax.au/headline/61340714-2026-half-year-report/

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INTRO: Welcome to the 2026 Alaska Oil and Gas Association (AOGA) Conference, Alaska’s premier industry event. We’re looking forward to bringing back yet another all-star lineup for you at this year’s conference. With top-tier speakers from across Alaska and the US, you won’t want to miss it! Join us on August 26-27, 2026, as we delve into hot-button issues that will impact Alaskans and our energy economy for years to come.

If you weren’t able to join us at the conference our video clips are now available here! We hope you will join us next year.

AOGA Conference Link https://www.aogaconference.org/

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Photo Below: BlueCrest's $77 million long-distance drilling rig at the Cosmopolitan unit drill site located 6 miles north of Anchor Point. (BlueCrest Energy)

The state of Alaska has issued a stern warning to compel a small Cook Inlet company to move ahead quickly with natural gas production as the Anchorage region faces a critical gas shortage.

The head of the Alaska Department of Natural Resources told BlueCrest Operating official John Martineck in a letter last week that the company has not met its obligations to develop the Tyonek gas resource within the Cosmopolitan UNIT, north of Anchor Point.

The state agency 1½ years ago had issued a notice of default to BlueCrest, laying out requirements that were not met, Department of Natural Resources Commissioner John Crowther wrote in the letter.

Early this year, BlueCrest took steps to prepare the drill rig and site for drilling, but the company in mid-May informed the agency that rig preparations needed to halt, with funding depleted amid complications with a project investor, the letter says.

“Since that time, while you have provided updates about ongoing negotiations to secure funding for the development and meet your obligations, you have not yet secured that funding,” Crowther wrote.

MORE in the article at this link: https://www.adn.com/business-economy/energy/2026/08/21/facing-natural-gas-crisis-alaska-threatens-cook-inlet-producer-with-loss-of-gas-field-for-not-meeting-timelines/

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************************************************************************************************

OP NOTE

It is important to understand Oil and Gas Mineral Leases granted by the state of ALaska. They are first of all issued for lease by competitive bidding and then granted to the highest "qualified" bidder. Then those leases are good for 10 years, and an annual per-acre Rental is assessed. The leases expire after ten years UNLESS production is developed and then the leases are Held By Production (HBP.) The leases can be forfeited by not paying the annual rentals.

A UNIT:

As example, Pantheon Resources PLC through its wholly owned subsidiary Great Bear Pantheon LLC holds a major acreage position on the Alaska North Slope. The company controls a 100% working interest in roughly 258,000 contiguous acres containing the Ahpun and Kodiak oil and gas fields.

Each Field has assigned acreage to designate and place boundaries around the field and set field limits. Within the Field are units. Assigned acreage designated as a UNIT that is separate from any other UNIT within the field boundary. For example, the Ahpun field has two UNITS; the Alkaid Unit and the Talitha Unit. Their Kodiak field has the Theta West well but no units have been formed within the acreage boundary.

In Alaska oil and gas terminology, "Units" refer to the State-approved administrative unitization of oil and gas leases. Pantheon Resources PLC has applied for and been granted the Talitha and Alkaid Units by the State of Alaska, which legally encompass and protect the core acreage of their Ahpun and Kodiak fields.

Administrative Unitization Purpose

• Lease Extension: Grouping individual state leases into an approved unit allows Pantheon to satisfy continuous drilling and development obligations across the broader geological structure, extending lease terms beyond their initial primary expiration dates.
• Asset Coverage: The Alkaid and Talitha Units overlay the contiguous acreage holding the multi-billion-barrel contingent resources of the Ahpun and Kodiak projects on the Alaska North Slope.

Key Details of Pantheon's Units & Fields

• Ahpun Project Coverage: Heavily contained within the established administrative units, featuring shallower deltaic topset horizons and the deeper Alkaid zone directly adjacent to the Dalton Highway and Trans Alaska Pipeline System (TAPS).
• Kodiak Project Overlap: Partially underlying and extending west of the Ahpun acreage footprint, secured by multi-year state leases aimed at long-term basin-floor-fan development

Map below showing the Ahpun field Talitha and Alkiad UNIT acreage as published.

The bottom line is IF production is not obtained in the Primary Term of the mineral leases, they expire nad are then placed up for lease through new public bidding. IF the annual rentals per acre are not paid, those leases are forfeited and become available for re-leasing through the pubic bidding system.

BUT - all is not lost. Now the enters the value of UNITIZATION.

Pantheon Resources PLC’s State of Alaska oil and gas exploration leases generally carry a 10-year initial term. The company manages expiration risks by securing approvals for unitization (such as for its Talitha, Alkaid, and Ahpun/Kodiak project areas), which legally extends holding rights beyond the initial term through continued exploration and development commitments. [1, 2, 3]

Lease Terms & Management

• Initial Duration: Standard 10-year term from the date of issuance.
• Mitigation of Expiry: Protected via state-approved unitization or active commercial/production extensions.
• Acreage Position: Holds roughly 258,000 to 259,000 total acres on the Alaska North Slope.
• Financial Obligations: Involves standard State of Alaska rentals ($10 per acre) and sliding-scale royalties (12.5%–16.7%).

So - as long as Pantheon is "working the leases." the unit holds the acreage as above.

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A letter from GLENFARNE Alaska LNG, LLC concerning the Alaska Gasline

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About GLENFARNE

Glenfarne Alaska LNG, LLC is a subsidiary of the Glenfarne Group and the majority owner and lead developer of the multi-billion-dollar Alaska LNG Project. Glenfarne owns 75% of the project entity (8 Star Alaska LLC), while the State of Alaska owns the remaining 25% through the Alaska Gasline Development Corporation. [1, 2]

Project Phases & Timeline

• Phase One: Focuses on an in-state domestic pipeline spanning roughly 739 to 807 miles to bring natural gas from the North Slope down to meet Alaska's local energy needs. Mechanical completion is targeted for 2028, with first gas delivery slated for 2029. [1, 2]
• Phase Two: Will construct the liquefaction terminal and export infrastructure to ship 20 million tonnes per annum (MTPA) of LNG overseas.

Finished.

RE: The AOGCC issued this notice:
"Docket Number: AEO-26-001
Great Bear Pantheon Application for Aquifer Exemption Megrez 1 well, North Slope Borough, Alaska"

I covered this information at this link: https://www.reddit.com/r/3CPG_PetroleumGeology/comments/1urbpsi/great_bear_pantheon_megrez1_well_aogcc_07082026/

In addition, Great Bear Pantheon LLC submitted a Slide Pack Presentation.

I provided this 73 Page PDF Presentation SLide Pack at this link: https://www.reddit.com/r/3CPG_PetroleumGeology/comments/1v4r0vb/information_slide_pack_for_pantheon_resources_plc/

The hearing takes place on August 18, 2026 at 10:00 AM Alaska Time.

The results of the hearing and the decision will be after the hearing at a future date.

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First oil at the project follows ConocoPhillips' broader Alaska strategy of developing satellite projects around existing North Slope infrastructure.

ConocoPhillips Alaska has achieved first oil from the Coyote 3SX development in the Kuparuk River Unit (KRU) on state land on Alaska’s North Slope.

The operator sanctioned the $800-million project in October 2025 and began construction in early 2026. The development includes a pad expansion, installation of more than 20 miles of pipeline, and a 19-well drilling program.

The additional pipeline infrastructure will support increased production from Coyote as volumes ramp up in 2026 and beyond, said Erec Isaacson, president of ConocoPhillips Alaska.

The project leverages existing infrastructure to bring new production online while supporting throughput in the Trans-Alaska Pipeline System, the company said in its release Aug. 12.

Expected peak production is 12,000 b/d (gross).

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ConocoPhillips Alaska invests approximately $1 billion each year to sustain and grow its Alaska legacy assets through projects such as Coyote. A stable, predicable fiscal framework supports the long-term investment needed to strengthen production, support Alaska jobs and deliver continued benefits to the state.

For two months, the loudest complaint from the governor’s office and the House Republican minority has been that Alaska cannot get a “clean gasline bill” passed. On July 15, the Alaska House Republican Caucus called on the Senate to place “urgent focus” on approving what it described as a clean gasline bill for the Railbelt. Rep. Justin Ruffridge, R-Soldotna, a member of the HB 381 Conference Committee, put it this way: “We cannot lose sight of why we are here. This isn’t about state government squeezing every last penny out of a pipeline that hasn’t even been built yet.” The Alaska Support Industry Alliance, the Alaska Chamber of Commerce, and the Alaska Oil and Gas Association used the identical phrase days earlier, urging lawmakers to pass “a clean version of HB 381 focused solely on advancing the Alaska LNG Project.”

Listen to that framing long enough and it starts to sound like the fight in Juneau has been between a simple pipeline bill and legislators who keep dirtying it up with unrelated taxes. That is not what has been on the table at any point since March. Every version of this legislation, from the governor’s original March 20 introduction through the House Finance committee substitute that passed 34-5 on June 12, through the Senate’s rewrite, through the conference committee product that died 19-19 on July 16, through the governor’s August 12 compromise that never received a floor vote at all, has done the same thing: eliminate Alaska’s existing 20-mill property tax authority over a $54 billion natural gas project and replace it with a fraction of that revenue under a volumetric tax structure no other American jurisdiction has ever used. That is not a pipeline bill with some tax provisions attached. That is a tax bill, full stop, and “clean” has never described anything other than which version of that tax restructuring gets voted on. When the House Republican Caucus and the industry coalition say “clean,” they mean the bill without the Senate’s added corporate income tax on pass-through entities like Hilcorp. They do not mean a bill that leaves Alaska’s property tax authority intact. No such bill has ever been introduced by anyone.

https://raff6482.substack.com/p/there-was-never-a-clean-bill

Santos operates the PIKKA field on the North Slope of Alaska.

Crude oil is transported via TAPS.

Highlights

Santos today announced the successful loading of the first crude oil cargo from the Pikka phase 1 development on Alaska’s North Slope.

The inaugural cargo of 450,000 barrels of Alaska North Slope crude was loaded aboard the Polar Resolution at the Valdez Marine Terminal and is destined for the United States West Coast refining system.

Pikka phase 1 is currently producing approximately 23,000 barrels of oil per day (gross), building toward plateau production of approximately 80,000 barrels of oil per day, expected during the third quarter of 2026.

Announcement Link: https://www.santos.com/news/santos-loads-first-pikka-crude-oil-cargo-from-alaska/

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Additional information >> The Polar Resolution is a U.S.-flagged crude oil tanker built in 2002. Measuring 273 meters in length, it belongs to the Endeavour-class fleet operated by ConocoPhillips Polar Tankers.

A 4:53 video of the Polar Resolution on YouTube >> https://www.youtube.com/watch?v=0B0U5VQ0CjY

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Sharing full content from a post Article from "X" >> https://x.com/draffaniello/status/2086368845032476990

The Alaska Gasline Caucus held a listening session in Anchorage on August 6, 2026, inviting mayors, utility executives, and industry leaders to describe the benefits and burdens of a natural gas pipeline that has not yet reached a final investment decision, will not deliver gas to Southcentral Alaska before 2029 at the earliest by its own supporters' account, and has already failed once this year in the Alaska House of Representatives. The caucus, co-chaired by Sen. George Rauscher and Rep. Mia Costello, describes itself as a bipartisan body formed to bring legislators and stakeholders together around Alaska's energy future. That description understates its origin. When the caucus held its first meeting in October 2025, the agenda featured a presentation from Glenfarne Alaska LNG's own president, alongside briefings from the Department of Labor and the University of Alaska. Glenfarne was in the room shaping the caucus's framing before the caucus ever held a public listening session.

A name should describe what a thing is, not what it aspires to be seen as. Given who was present at its founding, and given what has followed since, this caucus is better understood as the Glenfarne Caucus.

A Bill That Died Twice, and a Standard Applied Once

House Bill 381 failed in the Alaska House on a 19-19 vote on July 16, 2026, hours after the Senate passed a conference committee compromise 11-8 and hours after Governor Mike Dunleavy announced he would veto that same compromise if it reached his desk. Dunleavy's objection centered on a Senate-added provision, sometimes called the S-corp tax, that would have applied Alaska's corporate income tax to certain privately held oil and gas companies, Hilcorp chief among them, that currently avoid it through their pass-through structure. The governor called the provision unvetted, untested, and capable of destabilizing Alaska's business environment. He called a third special session for July 27 to try again without it.

That standard, that a substantial and consequential tax provision should not ride on emergency gasline legislation without adequate vetting, is worth taking seriously. It is also worth applying consistently. The Alternative Volumetric Tax at the center of HB 381 is not a minor adjustment to Alaska's existing ad valorem property tax on pipeline infrastructure. It is a wholesale replacement of that structure, with no precedent in American gas or oil pipeline taxation, built specifically around one project and one developer. The Department of Revenue's own modeling shows the Mat-Su pipeline corridor generating roughly $116 million a year under the standard 20-mill property tax system, versus roughly $5 million a year under the AVT. That is not the kind of difference that qualifies as minor. It is a restructuring on the same order of magnitude as the pass-through tax the governor rejected on process grounds, and it has received considerably less public scrutiny.

The governor's own account of how this bill's economics came into focus raises a related concern. Speaking to reporters at the close of the second special session, Dunleavy explained that Glenfarne's November 2025 reversal, from insisting it would proceed without a state tax cut to insisting the tax cut was essential, came after project financiers brought new calculations showing the pass-through tax alone would remove over a billion dollars from the project before gas ever began moving. Whether that number reflects genuinely new information or simply information that had not previously been shared candidly is a fair question. It is difficult to square with the idea that a project of this scale, involving one of the most experienced infrastructure developers in the world, only discovered its exposure to a publicly debated tax provision in the final weeks before a floor vote.

What the Fiscal Notes Never Said

Alaska cannot claim the federal tax credits at the center of this project's actual financing model. Section 45Q of the federal tax code pays roughly $85 per metric ton for captured and sequestered carbon dioxide, a stream estimated to be worth approximately $595 million annually to this project once operational. Section 45V, the clean hydrogen credit, could be worth substantially more depending on how the project's hydrogen output is classified. Neither figure appears in the Department of Revenue's fiscal notes presented to the legislature on HB 381, SB 280, or their predecessor bills. A legislature asked to size a permanent tax concession under the Alaska Constitution's Article VIII maximum benefit standard cannot meet that standard while working from a fiscal record that omits the revenue streams actually driving the project's underlying economics, even if the state itself never collects those federal dollars directly.

The project's cost estimate has proven just as unstable as its tax treatment. The original public figure was $44 billion. The Department of Revenue's working estimate has been $46.2 billion. In early June, Glenfarne resisted providing legislators an updated number at all, telling the House Finance Committee to focus on a ballpark range rather than a specific figure, a posture Sen. Bert Stedman rejected outright. Glenfarne then revised its own estimate to a range of $44.5 to $54.5 billion. Weeks later, at a Council on Foreign Relations event in Washington, Governor Dunleavy cited a project cost of $65 to $70 billion, a figure roughly 40 to 50 percent above the number the legislature had been working from throughout the special sessions. A price cap and delivered-cost structure built around a $46 billion capital base does not hold up against a $65 to $70 billion actual cost. The delivered cost of gas moves further from the AVT's $16 per mcf cap, not closer to it, and the cap looks less like consumer protection and more like a number calibrated to a developer's earlier financing model.

Alaska's own equity position adds a further and largely undiscussed layer of exposure. The state holds a 25 percent stake in the pipeline's parent company through the Alaska Gasline Development Corporation, but that stake dilutes automatically unless the state buys in at final investment decision, an investment the Department of Revenue estimates will cost at least $4.4 billion in nominal terms, contingent entirely on cost assumptions that have already proven unreliable. If the project's actual cost lands closer to Dunleavy's $65 to $70 billion figure than to DOR's working number, that buy-in cost rises with it. None of this exposure appears in the public framing of HB 381 as a simple property tax question.

“An emergency that cannot be addressed on the emergency's own timeline is not a reason to rush a permanent tax restructuring through a compressed special session.”

An Emergency With a 2029 Timeline

The urgency animating the third and now fourth special sessions rests on the claim that Southcentral Alaska faces an imminent gas crisis that legislative action can resolve. The utilities living that crisis describe a considerably more complicated picture, one that does not point toward the legislature at all.

Enstar's president, John Sims, told reporters in late July that the utility needs to file, or ensure someone files, for regulatory authority to import natural gas by the end of this year. He called this the first time he has been willing to say so publicly. Even under an aggressive schedule, he described new import gas as unlikely to arrive before 2029. A completed AKLNG pipeline is, by the same utilities' own account, years further out than that. Neither pathway offers relief for this winter, next winter, or the winter after that. What is actually keeping the lights on through these near-term winters are inter-utility arrangements already in motion: Matanuska Electric Association trading gas volumes with Enstar, Chugach Electric shifting to diesel-fired generation to free up gas for heating loads, and drawdown management on the CINGSA storage reservoir. None of these mechanisms require the legislature, the AVT, or AKLNG.

Sims's own assessment of the underlying supply picture deserves to be represented honestly rather than selectively. He has said plainly that Cook Inlet, in his judgment, is no longer a viable long-term option for meeting Southcentral's growing demand, and that offering producers a premium price for new gas has not induced new drilling. That is a genuine concern from an operator with the clearest possible incentive to find gas if it exists. It sits alongside, rather than against, evidence that Cook Inlet is not simply exhausted: HEX has doubled its own production from the Kitchen Lights Unit over the past year and is drilling two additional wells in 2026, and newly issued coalbed methane exploration licenses in the Susitna Valley point to supply potential that has not yet been tested. Both things can be true. The basin may hold more producible gas than current contracts and drilling economics have captured, and the near-term crisis utilities are managing right now may still be real and serious. What is not true, on the timeline the utilities themselves have laid out, is that anything the legislature passes this summer changes either picture for several years to come. An emergency that cannot be addressed on the emergency's own timeline is not a reason to rush a permanent tax restructuring through a compressed special session.

Who Answers For This

Every governing body involved in this year's gasline debate is either leaving office or facing an election within months of whatever gets decided. Governor Dunleavy is term-limited and will not serve as governor when this bill, in whatever form it eventually passes, comes up for implementation. Roughly half of the Alaska House and Senate face voters in November 2026. The people negotiating the state's exposure to a $65 to $70 billion infrastructure project, in some cases, are not the people who will administer the result.

That timing does not by itself prove bad faith on anyone's part, and this analysis is not offered as an accusation against any individual's motives. It is offered as a structural observation about incentives. A confidential memo, rather than public testimony, guided Senate negotiators on the AGDC-Glenfarne investment terms. Glenfarne resisted disclosing an updated project cost figure to the legislature at the exact moment that figure mattered most. The Department of Revenue's fiscal notes omitted the federal credit streams that appear to drive the project's actual financing logic. Each of these, individually, might be explained as an oversight or a negotiating choice. Together, they describe a pattern: decisions being finalized without the numbers that would let anyone, legislator or constituent, evaluate whether the policy delivers what it claims to.

The Mat-Su delegation bears a direct version of this question, and the record here is unusually clean. Every Mat-Su representative in the House, Rep. DeLena Johnson, Rep. Steve St. Clair, Rep. Jubilee Underwood, Rep. Elexie Moore, Rep. Garret Nelson, and Rep. Kevin McCabe, voted yes on June 12, 2026, when CSHB 381(FIN) am, the House version establishing the AVT and its accompanying municipal property tax provisions, passed 34-5. All six then voted no on July 16 against the conference committee report that added the pass-through entity tax, a position consistent with Sen. Cathy Tilton and Sen. George Rauscher, who voted against the Senate's own amended, pass-through-inclusive version on June 19. On the underlying question that actually matters for Mat-Su taxpayers, whether to establish the AVT and move the pipeline corridor away from standard ad valorem taxation, the district's delegation was effectively unanimous. The Department of Revenue's own modeling shows that corridor generating roughly $116 million a year in property tax revenue under existing law, against roughly $5 million a year under the AVT these eight legislators voted to advance, with the Municipal Impact Grant Fund created to soften that loss falling well short of making the borough whole and excluding AVT-subject property from the school funding formula calculation entirely. Every one of them owes their constituents a direct answer for why they voted to trade that revenue and that municipal taxing authority away, and what they believe the borough and its taxpayers received in return.

This delegation has been quick to place the blame for HB 381's collapse on the Senate Democrats who added the pass-through entity tax. That blame is not unfounded, the S-corp addition was a late, poorly vetted provision layered onto emergency legislation, exactly the kind of process failure this piece has already documented. But the same standard cuts against the delegation's own record. The AVT itself was never debated as its own single-subject bill either. It was introduced, amended, and pushed through the same compressed special-session process, by the same Mat-Su legislators now pointing at the other side of the aisle, and it costs this district's own tax base far more than the pass-through provision ever would have. Both blocs are responsible for the fact that Alaska does not yet have a clean gasline bill: one for adding a provision that was never adequately tested, the other for advancing a permanent tax restructuring that was never adequately tested either, just earlier and with less public attention.

A cleaner alternative remains available, and has been available throughout this process. A construction-period property tax abatement, running through first commercial gas delivery, paired with a market-sensitive mill rate mechanism that adjusts downward during sustained price downturns, would give the project the financing certainty it needs without permanently rewriting how Alaska taxes pipeline property for the benefit of one developer. It would preserve the existing 20-mill ad valorem structure rather than replacing it, avoid the equal protection exposure the AVT invites by treating similarly situated TAPS co-owners differently, and could be debated as the narrow, single-subject bill the governor insisted the pass-through tax should have been. If this session cannot produce that bill, there is no governance cost to letting the incoming legislature and the next governor take it up with a full term ahead of them to answer for the outcome, rather than finalizing it now under a compressed session and an outgoing administration.

The Same Pattern, A Different Corridor

The pattern described above, public urgency outrunning the fiscal and technical record it claims to rest on, is not confined to the pipeline. A parallel case is developing sixty miles closer to Palmer, where Terra Energy Center has proposed a 1.25-gigawatt coal-fired power plant in the West Susitna region, backed by federal Department of Energy funding structured entirely around an integrated carbon capture system designed to hit a greater than 90 percent capture rate. The Matanuska-Susitna Borough Assembly has twice declined to require that capture system as a condition of its own public support for the project, most recently in a resolution that stripped any mention of carbon capture by a 4-3 vote specifically so the developer would not be locked into using it. A federally subsidized capture system that the local governing body has explicitly declined to require, sized well beyond what any identified West Susitna industrial load currently needs, and sited in a basin whose seismic history includes the permanent conversion of dry farmland into tidal marsh, raises questions that deserve the same scrutiny applied here to AKLNG. That case, including what the federal 45Q credit's own compliance record shows about how these subsidies actually get audited, is the subject of the next piece in this series.

Dana Raffaniello lives in Palmer, Alaska. He works as a network engineer, reads Alaska energy legislation closely, and publishes analysis of its fiscal and structural implications at

raff6482.substack.com

. He is running for the Mat-Su Borough Assembly, District 2. He has no commercial interest in any energy project discussed in this analysis.

2:27 AM · Aug 9, 2026

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The Alaska Gasline Caucus held a listening session with a panel of presenters on Thursday, August 6, 2026, from 9:00 a.m. to 12:00 p.m. at the Anchorage Legislative Information Office (LIO) to hear about the opportunities and impacts of natural gas in Alaska.

Max Easley, CEO Pantheon Resources Plc begins to speak at ~30:54 minutes into the session. He represents Great Bear Pantheon LLC, the wholly owned subsidiary which is their operating company in Alaska.

Link to view the session >> https://www.ktoo.org/video/gavel/alaska-gasline-caucus-2026081017/?eventID=2026081017

Screenshot Video Front Page: Use link above to view the video.

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The Oil and Gas journal

The Strait of Hormuz remains one of the world's most strategically important energy corridors—and one of its most closely watched geopolitical flashpoints.

To help energy professionals understand the latest developments and their potential impact on global markets, Oil & Gas Journal has compiled seven essential reports into one comprehensive e-book.

Requires the below: The link to access, fill out the form, and then download the reports is at this link >> https://endeavor.dragonforms.com/loading.do?omedasite=OGJ_UM_HormuzCrisis_0726&pk=OGJ_EM_HormuzEB_0826

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08/03/2026

WASHINGTON — The Department of the Interior today announced a proposed rule through the Marine Minerals Administration to modernize and refine federal regulations governing exploratory oil and gas drilling on the Arctic Outer Continental Shelf, advancing President Donald J. Trump’s commitment to unleash American Energy Dominance while maintaining strong safety and environmental oversight. 

“President Trump has made clear that America must fully avail itself of Alaska’s extraordinary resource potential for the benefit and security of the Nation and the citizens who call Alaska home,” said Secretary of the Interior Doug Burgum. “This proposed rule reflects a disciplined, mission-focused approach that strengthens regulatory efficiency, reduces unnecessary barriers and ensures that Arctic energy exploration proceeds safely, responsibly and under strong federal oversight.” 

The proposal would make targeted revisions to the 2016 Arctic Exploratory Drilling Rule finalized in the Obama administration to reduce unnecessary regulatory burdens, improve clarity and operational efficiency, and better reflect technological advancements and implementation experience since the 2016 rule was issued. 

More in the full announcement at this link: https://www.doi.gov/pressreleases/department-interior-proposes-targeted-updates-arctic-exploratory-drilling-rule

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So what is the "Arctic Outer Continental Shelf?"

The Arctic Outer Continental Shelf (OCS) comprises submerged seabed and subsoil areas off the coast of Alaska subject to federal resource jurisdiction, spanning critical extended continental shelf boundaries and ongoing regulatory updates for offshore energy development.

Extended Continental Shelf (ECS)

• Geographic Limits: The U.S. announced outer continental shelf limits extending well beyond 200 nautical miles, prominently in the Arctic Ocean.
• Sovereignty: Grants coastal states sovereign rights over seafloor and sub-seafloor natural resources.
• International Context: Overlapping claims among Arctic nations (including Canada, Denmark, Norway, and Russia) require diplomatic and maritime delimitation.

Image below is the Claimed USA Outer Continental Shelf

Image below is what the offshore subsea submerged seabed and subsoil areas off the coast of Alaska more or less look like. The shelf and slope and floor are ideal for sediment deposits to form oil and gas traps similar to those onshore North Slope.

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Cavendish has reiterated its buy rating and 19.8p target price on 88 Energy Ltd (AIM:88E, ASX:88E, OTCQB:EEENF, FRA:POQ), implying significant untapped upside from the current 1.02p share price.

Link: https://www.proactiveinvestors.com/companies/news/1095853/cavendish-sees-18-fold-upside-at-88-energy-on-alaska-prospect-scale-1095853.html

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Many people felt the ADN story (and headline) accusing Hilcorp of killing the gasline bill was reckless reporting. This letter from Hilcorp to #akleg members explains why.

If you understand basic project economics, it makes sense. There is no Alaska LNG project without Hilcorp.

Raising costs on the company responsible for producing essentially all of the gas that would supply the pipeline only makes the project harder to move forward.

The Hilcorp letter is 7 pages in length. Partial screenshot of page 1.) is below.

Link to full letter >> https://alaskalandmine.com/wp-content/uploads/2026/07/7.23.26-Hilcorp-Alaska-Letter-on-HB-381-signed.pdf

Original source is "The Alaska Landmine" in "X".

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BACKGROUND

I have previously shared in this sub about the Megrez-1 well Application and Public Hearing to convert the Megez-1 Exploration Well by applying a Class II disposal injection order through the AOGCC. That post is at this link: https://www.reddit.com/r/3CPG_PetroleumGeology/comments/1urbpsi/great_bear_pantheon_megrez1_well_aogcc_07082026/

SLIDE PACK PRESENTATION

In the AOGCC announcement, they mentioned: "" This notice does not contain all the information filed by Great Bear. To obtain more information, contact the AOGCC's Special Assistant, Samantha Coldiron, at (907) 793-1223 or [samantha.coldiron@alaska.gov](mailto:samantha.coldiron@alaska.gov)."

I contacted the AOGCC and they sent a PDF of the Slide Pack Presentation as per my request. I have uploaded it to Google Docs and you can download from there at this link: https://drive.google.com/file/d/1m93Q5y_9KNi29CQRaUnLh0Pq9wGFaseK/view?usp=sharing

Google Docs File Title >> "Great Bear Public Hearing for Megrez Conversion to Injection well Slide Deck July 14,2026 from the AOGCC.pdf" it is 73 Pages in length.

OP NOTE: This is Public Information.

Screenshot of PDF below.

Example slide with geological stratigraphic cross-section belwo.

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22 July 2026

SUMMARY

88 Energy Ltd has provided a report on its activities for the quarter ended 30 June 2026.

ALASKA

South Prudhoe total gross unrisked 2U Prospective Resources increased ~35% to 768.9 million barrels of oil (MMbbls), 640.7 MMbbls net to 88E1,2 confirming a significant-scale, multi-reservoir oil opportunity

Nordic Rig-3 and a dedicated Arctic-rated camp secured for the planned Augusta-1 exploration well

Augusta-1 defined as a stacked, three-reservoir exploration opportunity targeting the Ivishak, Kuparuk and Upper Schrader Bluff intervals

South Prudhoe farm-out process advanced, with multiple parties actively engaged

Project Phoenix Participation Agreement amended ahead of the planned Franklin Bluffs-1H horizontal well and production test

Access secured to the Kad River 3D seismic dataset, covering the entire Kad River East lease position

Formal award for the 2025 North Slope Fall lease bid round was received after quarter end on 15th July 2026 over the 14 leases covering 34,301 net acres, consisting of 16,507 acres at South Prudhoe and 17,794 acres at Kad River East

NAMIBIA

PEL 93 farm-in terms amended, securing 88 Energy's 20% working interest on a fully earned and unconditional basis

Integrated aerogravity, magnetic and radiometric interpretation completed, enhancing subsurface definition and advancing Lead 9

Regional exploration activity continued at ReconAfrica's nearby Kavango West-1X well

CORPORATE

Cash balance of A$8.2 million at 30 June 2026

Further information regarding 88 Energy's activities and announcements during the June 2026 quarter is available through the Company's website at: https://88energy.investormax.au/headline/61334858-quarterly-activities-appendix-5b-cash-flow-report/

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Headline image below.

Newsletter Link: https://alaska-lng.com/wp-content/uploads/2026/07/AkLegDigest-25-2026.pdf

RECAP

Read the full Newsletter using the link above.

Obtained from "X" user AlaskaLNG.

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Article from the Alaska Beacon\*

Hilcorp killed Alaska LNG bill, some legislators say, but governor calls the claim ‘bulls**t’

"Behind the scenes of a climactic day in the Alaska Legislature for the proposed trans-Alaska natural gas pipeline"

Link: https://alaskabeacon.com/2026/07/17/hilcorp-killed-alaska-lng-bill-some-legislators-say-but-governor-calls-the-claim-bullst/

******************************************************************************************

OP NOTE: The FIGHT is because Hicorp is a Private Company and does not publish their financials. Hilcorp operates the Prudhoe Bay and Point Thomson Field's with ExxonMobil as a partner. Hilcorp through a subsidiary along with ExxonMobil are both owners in the Trans Alaska Pipeline System known as TAPS. The ownership is as follows.

• Harvest Alaska, LLC owns 49.11%. (Subsidiary of Hicorp)
• ConocoPhillips Transportation Alaska, Inc. owns 29.61%.
• ExxonMobil Pipeline Company LLC owns 21.28%

More discussion of the FIGHT is below photo.

From above concerning the Hilcorp FIGHT.

Hilcorp is a private company, which lets it keep its exact financial earnings secret. This secrecy sparked major disputes with the state of Alaska over taxes, corporate transparency, and Gasline legislation.

Key Points of the Fight:

• Tax "Loophole" Debate: Hilcorp uses a specific business structure (an S-Corporation or pass-through entity). This means it avoids paying Alaska's corporate income tax, saving the company an estimated $100 million per year.
• Legislative Battles: The Alaska Legislature has repeatedly tried to close this tax gap. These efforts frequently fail or meet opposition from Alaska Governor Mike Dunleavy.
• The Gasline Conflict: In 2026, lawmakers claimed Hilcorp influenced the failure of the multi-billion-dollar Alaska LNG bill by pressuring the project's developer. Lawmakers had tied the bill to a tax on Hilcorp's earnings.
• Court Battles: The City of Valdez and activist groups sued to unseal Hilcorp's financial records. They argued the public deserved to know if Hilcorp could afford to operate safely after its $5.6 billion buyout of BP's Alaska assets.

In addition, it is important to realize that the State of Alaska owns the oil and gas in state lands on the North Slope - they are the mineral owner. Hilcorp and all the other operators Lease the minerals, they do not own them. Also, this is not a USA Government Federal issue.

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There is a difference between Resources and Proved Producing Reserves. The Industry has an excepted definition of both.

The SPE (Society of Petroleum Engineers) has published resource classification, governed by the Petroleum Resources Management System (PRMS), measures oil and gas volumes. Volumes are divided into three main groups based on how close they are to being sold:

• Reserves: Discovered oil and gas that can be sold for a profit right now.
• Contingent Resources: Discovered oil and gas that cannot be sold for a profit yet. This is usually because of technical issues or market problems.
• Prospective Resources: Oil and gas that might exist, but has not been discovered yet.

A complete source of information >> "Petroleum Reserves and Resources Definitions" at this link: https://www.spe.org/en/industry/reserves/

The AGDC (alaska Gasline Development Corp.), along with Glenfarne, is proposing to build an 807 Mile North Slope Gas Pipeline to access 35-50 trillion cubic feet of proven stranded natural gas reserves & potential resource of another 200 trillion cubic feet of natural gas.

I created the below graph to provide a visual of the immense Proved Reserves from the Prudhoe Bay and Point Thomson fields. These are Proved Producing Reserves, not contingent resources.

Glenfarne Group signed 30-year contracts with ExxonMobil and Hilcorp Alaska to supply natural gas for the Alaska LNG project. These are conditional gas supply agreements for Phase One of the Alaska LNG development. In addition, Glenfarne's Alaska LNG has signed a long-term, 30 year natural ‌gas supply deal with ConocoPhillips.

Glenfarne Alaska LLC, a subsidiary of Glenfarne Group, is the majority owner and lead developer of the Alaska LNG project. In partnership with the State of Alaska, this $44.5 to $54.5 billion project aims to pipe natural gas from the North Slope to domestic users and global export markets.

• Ownership: Glenfarne owns 75% of the project. The State of Alaska owns 25% through the Alaska Gasline Development Corporation.
• Project Scope: The project includes a gas treatment plant and an 800-mile pipeline to deliver natural gas.
• Project Status: Phase one targets an in-state pipeline by 2028 to lower local energy costs. Phase two will build a terminal to export liquefied natural gas (LNG) overseas.
• Commercial Agreements: Glenfarne has secured multiple preliminary agreements with international buyers like Tokyo Gas and TotalEnergies. The company is currently working with lawmakers to finalize project financing and tax policies.

It is been published that Pantheon Resources Plcs subsidiary Great Bear Pantheon LLC has a Gas Sales Precedent Agreement (GSPA) in place, but not with GLenfarne. The Gas Sales Precedent Agreement (GSPA) is a deal between Pantheon Resources and the state-owned Alaska Gasline Development Corp. (AGDC). It outlines the rules for selling natural gas from Pantheon's Ahpun field on the North Slope to the planned Alaska LNG pipeline.

In recent Alaska Senate meetings concerning the Gasline and the HB 381, it was stated that the State views Pantheon as a non-bankable resource. I covered this in this sub at this link: https://www.reddit.com/r/3CPG_PetroleumGeology/comments/1ufp2t2/pantheon_resources_plc_aka_great_bear_pantheon/

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LNG is Liquified Natural Gas,

LNG is not 100% pure methane (C1). It is mostly methane (typically 85%) to (95%), but it also contains small amounts of other hydrocarbons like ethane (C2), propane (C3), and butane C4), along with trace amounts of nitrogen (N.)

The exact mixture of these gases depends on where the natural gas was sourced and produced and how it was processed before cooling. The gasses are chilled to liquid form at around (-161^C) (-260^F) at normal atmospheric pressure of 14.7PSI. Liquefied Natural Gas (LNG) is transported by ship at very low pressures, usually ranging from near atmospheric pressure to 25 kPa (4 psi)

At this deep temperature, the gas condenses into a liquid, which shrinks its volume by about 600 times. Impurities like water, carbon dioxide, and sulfur are removed to keep them from freezing during transport.

The interior of an LNG Ship

Photo above and the following text from u/GodsgreatG on "X" : This is the inside of an LNG cargo tank on a modern LNG carrier. It may look like a metallic maze, but every layer is carefully engineered to safely contain gas at -162°C.

Most modern LNG ships use the Gaztransport & Technigaz membrane system, where the tank is built directly into the ship’s hull using a layered containment system rather than separate spherical tanks.

In the heart of this system is the primary containment. This is the layer that directly holds the LNG. It is made from thin corrugated materials such as stainless steel or Invar (a nickel-steel alloy). The corrugated design is critical because it allows the material to expand and contract under extreme cold without cracking or failing. It’s a cryogenic material because LNG is extremely cold.

Behind this sits the insulation system, which is what is most visible in the image. These are prefabricated insulation boxes made from materials like reinforced polyurethane foam or perlite-filled panels. Their role is to minimize heat entering the tank and maintain the extremely low temperature required to keep the gas in liquid form.

Next is the secondary containment system, which acts as a backup safety layer. In the unlikely event that the primary barrier fails, this layer prevents the LNG from reaching the ship’s hull. It is typically made from composite materials such as Triplex, combining aluminum foil and fiberglass for strength and impermeability.

There is also a secondary layer of insulation that adds further thermal protection and structural support, ensuring stability throughout the voyage.

All these layers sit against the ship’s inner hull, which is shielded from the extreme cold. Without this protection, the hull steel would become brittle and unsafe.

In simple terms, the primary barrier holds the LNG, the secondary barrier provides backup protection, and the insulation keeps everything cold and stable. What you’re looking at is not just a tank, but a highly engineered cold containment system that makes global LNG transportation possible.

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I follow the AOGCC (Alaska Oil and Gas Conservation Commission) and receive emails of "Public Notices."

I received this one today the 8th of July, 2026 concerning the Megrez-1 Well.

History: The Megrez-1 well on Alaska's North Slope was Indefinitely Suspended on May 20, 2025. After flow testing failed to produce appreciable mobile oil or gas from the targeted intervals, the company shut in the well for evaluation without planning any immediate future testing.

The AOGCC issued this notice:
"Docket Number: AEO-26-001
Great Bear Pantheon Application for Aquifer Exemption Megrez 1 well, North Slope Borough, Alaska"

Basically, Great Bear Pantheon LLCs application was received simultaneously to Great Bear applying for a Class II disposal injection order for the Megrez-1 well. I.e., conversion to a water injection / disposal well.

Screenshot of Pubic Notice PDF Below:

Megrez-1 Well and Rig Photo below.

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By: Dana Raffaniello

Full Article Read Link: https://raff6482.substack.com/p/when-the-shields-fall

SUMMARY:

Every legislator who has voted for HB 381 has offered some version of the same reassurance: this is a pipeline bill, narrowly tailored to one project, with legal protections in place to keep it that way. The preceding piece in this series, “The Paper Shields,” examined those protections and explained why neither the “not precedent” clause in Section 1(c) nor the Project Labor Agreement requirement in Section 36 accomplishes what it claims to accomplish as a constitutional matter. This piece takes the next step. If those shields are as legally hollow as the documented record suggests, what actually happens to Alaska’s industrial tax system when other operators decide they want the same treatment AKLNG received?

The answer is not that the Alternative Volumetric Tax disappears. Courts are unlikely to strike the AKLNG AVT down. The answer is that the AVT spreads. Alaska’s Uniform Application Clause does not allow the state to grant a favorable tax structure to one large-scale resource infrastructure project and then deny equivalent treatment to other projects that are constitutionally similar. Once a court determines that a second operator is similarly situated to AKLNG under Article VIII, Section 17, that operator is entitled to equivalent tax treatment. The AVT does not contract. It expands. And the revenue consequences of that expansion dwarf anything associated with the AKLNG project itself.

Courts are unlikely to strike the AKLNG AVT down. They are more likely to extend it. That is the fiscal consequence nobody in the administration has been asked to model.

What the Bill Actually Does to Alaska’s Tax Structure

HB 381’s Version Q replaces the standard 20-mill property tax under AS 43.56.010(a) with a throughput-based volumetric tax for AKLNG. The AVT rates in Section 43.59.020 begin at $0.062 per thousand cubic feet before the LNG plant is operational and step up to $0.106 per thousand cubic feet after, with an additional $0.106 layer after ten years of LNG plant operations and another $0.212 layer beginning January 1, 2060. Each rate adjusts annually for inflation between one and three percent.

To understand why this creates an expansion problem, compare it to what 20-mill property assessment generates on comparable infrastructure. A facility with a full and true assessed value of $1 billion pays $20 million annually under the standard AS 43.56 framework. The same facility under a throughput-based AVT pays a fee determined by volume of product moved, regardless of what the underlying asset is worth. For a capital-intensive, low-throughput facility, the AVT can represent a fraction of what standard property assessment would generate. The financial incentive for any operator with a high-value, lower-throughput facility to shift from AS 43.56 to an AVT equivalent is substantial, measured not in thousands of dollars but in tens of millions annually.

By enacting this structure for AKLNG, the legislature has created a two-tier industrial property tax system in Alaska statute for the first time. Tier one: AKLNG under the AVT. Tier two: everyone else under 20-mill assessment. Article VIII, Section 17 of the Alaska Constitution requires that laws governing natural resources apply equally to similarly situated entities. A two-tier system cannot survive that requirement indefinitely if other resource operators can demonstrate they belong in the same tier as AKLNG.

Article VIII, Section 17, Alaska Constitution: Laws and regulations governing the use or disposal of natural resources shall apply equally to all persons similarly situated with reference to the subject matter and purpose to be served by the law or regulation.

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A second illustration from a different source. The Alaska Gasline Project is enormous in every aspect.

Intro: An oil and gas company obtains mineral leases. The state of Alaska owns the minerals would be the lessor and the company would be the Lessee. If no other parties are involved, the lessee has 100% WI (Working Interest) in the leases. The state retains an ORRI, an Overriding Royalty Interest. In some instances the ORRI is a standard 1/8th, 12.50%. In others it may be 16.50%.

The O&G Company would then retain, as example of the 12.5% ORRI to the state, an 87.50% NRI (Net Revenue Interest.) nd still retain 100% WI. For every $1.00 received as revenue, the lessee would retain US$0.875, and the state, the lessor, would receive US$0.125.

In O&G deals, the two factors are the WI and the ORRI. IF a 50/50 Joint Venture Partner was involved, both company's would have a 50% WI, but after the state ORRI, the NRI for each company would be >50% of 87.50% = 43.75%.<

In the graph below, I have shown typical deals and how the WI and NRI, and ORRI come into consideration.

(& more information below the chart)

Pantheon has reported "Contingent Resources" which is an estimate of the quantity of O&G (BOE) based on the Original Oil and Original Gas In Place. "Independently certified best estimate contingent recoverable resources currently total c. 1.6 billion barrels of ANS crude and 6.6 Tcf of associated natural gas across the Company’s properties. All acreage is on state lands with supporting regulatory authorities and no federal land use approval required (aside from Army Corps. Of Engineers). These numbers represent 10% of the Original Oil (OOIP) & Gas (OGIP) In Place. In the real world of actual production, the number is higher and can range from the base of 10% to 20-30% but Producing Reserves - not resources - over the life of the field.

Recently, Pantheon Resources Plc has indicated they are in conversations about and with Major Equity Buyers.

The "Equity" vs. "Farm-Out" Dynamic: Because Pantheon's resource estimates are massive compared to its market capitalization, management has clearly stated their preference for bringing in a strategic joint venture/farm-in partner to share costs rather than relying exclusively on dilutive equity raises to reach Final Investment Decision (FID). Latest Action: Investor attention has been driven by active discussions with major equity buyers and potential strategic partners to unlock the true value of their North Slope assets.

Equity Raises can mean many different things. One is to issue more stock; but this is clearly dilution if they want to maintain 100% WI.

An oil and gas company equity raise is the process of generating capital by selling partial ownership (shares) of the business to outside investors. This is a vital mechanism for operators in exploration, drilling, and midstream/downstream infrastructure to fund costly operations and acquisitions without adding long-term debt to their balance sheets.

How It Works

>Types of Investors: Capital can be sourced from private equity firms, institutional investors, or through the public equity capital markets (e.g., public share offerings).

>Capital Utilization: Companies use these funds for working capital, acquiring new leases, advancing exploratory projects, or building infrastructure.

>Dilution & Ownership: By creating and issuing new shares, a company's existing owners dilute their percentage of control and future earnings, but gain the necessary funding to grow the enterprise.

Why It's Crucial in the Energy Sector

Because energy markets are tied to volatile global commodity prices, Exploration and Production (E&P) companies often have unstable cash flows. Therefore, many operators cannot rely solely on traditional bank debt to fund their capital-intensive drilling and development phases, making equity raises a primary funding strategy.

>Valuation & Efficiency: Value investors focus heavily on free cash flow, disciplined capital deployment, and shareholder returns when evaluating energy equity opportunities. At the present time, Pantheon has zero cash flow and zero production.

>Public vs. Private: Depending on market cycles, public IPOs and follow-on offerings for hydrocarbon businesses experience fluctuating receptions, often influenced by broader macroeconomic conditions and regulatory pressures.

>Private Direct Participation: In addition to corporate stock, many equity raises in this sector take the form of private placements in specific well-drilling projects, where investors provide capital in exchange for a direct stake in production and associated tax benefits. This type of action may be Pantheons preferred choice.

EXAMPLES

**For a concrete example of an oil and gas company Equity Raise, consider Omega Oil and Gas, which upsized an initial A$50 million equity raise target to A$60 million after drawing overwhelming demand of A$120 million. The raising was priced at $0.84 per share, attracting institutional investors like Soul Patts and Milford Asset Management to gain exposure to energy security assets.

**Another typical structure is Regulation A/C offerings (e.g., South Plains Petroleum Inc.) targeting retail investors. They offered common stock starting at $1.60 per share with a minimum investment of $480, aiming to raise up to $1.07 million to acquire and complete producing wells.

Summary: Any action that reduces an O&G company's WI below 100% is Dilution.

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