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The Canada Energy Regulator is hearing arguments on Friday from Trans Mountain Corporation on why it should allow a change in the route and diameter of a small section of the pipeline. The company has warned that without that change it could face a worst-case scenario of a delay of two years in the completion of the pipeline.

The expanded Trans Mountain pipeline will triple the capacity of the original pipeline to 890,000 barrels per day (bpd) from 300,000 bpd to carry crude from Alberta’s oil sands to British Columbia on the Pacific Coast.

The Federal Government of Canada bought the Trans Mountain Pipeline Expansion (TMX) from Kinder Morgan back in 2018, together with related pipeline and terminal assets. That cost the federal government $3.37 billion (C$4.5 billion) at the time. Since then, the costs for the expansion of the pipeline have quadrupled to nearly $23 billion (C$30.9 billion) and could continue to increase.

The expansion project has faced continuous delays over the years. The latest roadblock emerged in December when the Canadian regulator denied a variance request from the project developer to move a small section of the pipeline due to challenging drilling conditions. Trans Mountain is now waiting to receive the reasons for the decision, the corporation said, adding that construction on the project was more than 97.8% complete.

The company has asked the regulator to reconsider its decision to deny the variance request and is presenting arguments on Friday on the reasons why the request should be granted.

Trans Mountain has previously said that it plans on achieving first oil on the expanded pipeline to the Westridge Marine Terminal by the end of the first quarter of 2024.

Last week, the company said it plans to start line fill in March or May, depending on the diameter of pipe it uses and assuming there would be no other setbacks.

By Charles Kennedy for Oilprice.com

 

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Turnover with Brazil nearly doubled in December as the South American country ramped up imports of commodities from Moscow

 

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Oil and Gas 360

HOUSTON, Jan. 11, 2024 (GLOBE NEWSWIRE) — Prairie Operating Co. (Nasdaq: PROP; the “Company” or “Prairie”) today announced it has entered into a definitive agreement to acquire the assets of Nickel Road Operating LLC (“NRO”) for a total consideration of $94.5 million, subject to certain closing price adjustments and other customary closing conditions.  The total consideration consists of $83 million in cash and $11.5 million in deferred cash payments.  The effective date of the transaction is February 1, 2024.

The acquisition is expected to be accretive to Prairie’s shareholders across key financial metrics including production, reserves, and free cash flow.  Furthermore, the addition of NRO’s assets strategically expands Prairie’s core operating area, increases inventory of high rate-of-return drilling locations, and provides additional flexibility to the 2024 drill schedule.  The transaction adds over 5,500 net leasehold acres and 62 fully permitted proven undeveloped (“PUD”) drilling locations. The 84% liquids weighted assets produce approximately 3,370 net Boepd and add third-party engineered proven reserves estimated at 22.2 MMboe and $254 million in PV10 value, according to an independent, third-party reserve report by Cawley, Gillespie & Associates, Inc. (“CG&A”) using SEC pricing as of December 31, 2023.

NRO’s assets and operations are located near Prairie’s existing DJ Basin operations in largely rural Weld County, Colorado.  The permitted PUDs are expected to payout in approximately 1 year from the onset of production and are economic in a low commodity price environment, with operational break-evens below $30/bbl WTI. (1)  In addition, existing infrastructure provides takeaway capacity and opportunities to improve efficiencies.

“This acquisition increases and strengthens our overall position within a top-tier U.S. shale basin and aligns with our strategy of creating value through accretive acquisitions,” stated Ed Kovalik, Chairman and Chief Executive Officer of the Company.  “Furthermore, the transaction positions us to accelerate our development program within free cash flow, supporting the Company’s stated goal of debt-free, long-term growth.”

Gary Hanna, President of the Company, added, “Today’s announcement underscores our commitment and ability to create value for our shareholders through accretive acquisitions.  Today’s target rich environment gives us ample opportunity to continue executing our acquisition strategy.  These assets strategically enhance our existing operations, enabling us to capitalize on operational efficiencies in the DJ Basin.”

Strategic Drivers & Asset Overview: (1)

3,370 net Boepd (84% liquids) flowing from 26 operated horizontal wells
5,500 net contiguous acres across four lateral targets
90% held by production (“HBP”)
94% working interest in seven operated Drilling and Spacing Units (“DSUs”) 74% net revenue interest
Adds 62 permitted PUDs
Free cash flow expected to support full field development program
No exposure to federal leases
Key infrastructure in place to support development plan

Financial Highlights: (1)

Expected to be immediately accretive to key financial metrics, including production, reserves, and cash flow
Adds 22.2 MMboe and $254 million in 1P PV10 value
Adds 5.3 MMboe and $104 million in PDP PV10 value
Cash flow from PDP operations expected to be ~$40 million over the next twelve months
Average IRRs of 75% and discounted ROI of 1.9x
Net payout after approximately 1 year of production per well
Development Break-even below $30/bbl WTI

Transaction Metrics: (1)

Based on an effective date of February 1, 2024, and existing production of approximately 3,370 Boepd, the transaction metrics are as follows:

PV15 of Proved Developed Producing (“PDP”) reserves
Implied multiple of 2.3x NTM cash flow
$28,000 per net flowing Boe
$17,000 per net acre
$4.25 per Boe of 1P reserves of 22.2 MMboe, as determined by CG&A. Including approximately $182 million of net undiscounted future development capital results in a recycle ratio of approximately 3.6x times.

A summary of reserves and values as of December 31, 2023 and as determined by CG&A follows.

Reserve Category
Formation
Well Count
Net Oil (mbo)
Net Gas (mmcf)
Net NGL (mbngl)
Net Equiv. (mboe)
PV10 ($000s)
PDP
Codell
 7
 746
 1,145
 189
 1,125
 26,582
Niobrara
 19
 1,909
 6,733
 1,160
 4,191
 77,313
Total
 26
 2,655
 7,878
 1,349
 5,317
 103,895
PUD
Codell
 19
 2,697
 4,379
 715
 4,142
 42,269
Niobrara
 43
 6,141
 19,483
 3,392
 12,780
 107,252
 
Total
 62
 8,838
 23,862
 4,107
 16,922
 149,521
 
TOTAL PROVED
 88
 11,493
 31,740
 5,456
 22,239
 253,416

Note: PV10 is a non-GAAP financial measure. See the “Non-GAAP Financial Measure” section below.

Based on CG&A reserve report using SEC pricing as of December 31, 2023, and NRO provided lease operating statements and corporate financial statements

Additional Information

A company presentation describing the acquisition can be found on the Company’s website (www.prairieopco.com).  The transaction is currently expected to close in the first half of 2024. The Company expects to fund the transaction through a combination of public and / or private issuance of common stock, cash on hand, and proceeds from existing warrant exercises.

Non-GAAP Financial Measures

PV10 is derived from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”), which is the most directly comparable GAAP financial measure for proved reserves.  PV10 is a computation of the Standardized Measure on a pre-tax basis. PV10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes discounted at 10 percent.  We believe that the presentation of PV10 is relevant and useful to our investors as supplemental disclosure to the Standardized Measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our reserves before considering future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV10 is based on prices and discount factors that are consistent for all companies.

About Prairie Operating Co.

Prairie Operating Co. is a publicly-traded company engaged in the development, exploration, and production of oil, natural gas, and natural gas liquids with operations focused on unconventional oil and natural gas reservoirs located in Colorado focused on the Niobrara and Codell formations. The company also owns crypto miner computer assets, complementary to its energy assets. The Company is dedicated to developing affordable, reliable energy to meet the world’s growing demand while continuing to protect the environment. To learn more, visit www.prairieopco.com.

Forward-Looking Statements

The information included herein and in any oral statements made in connection herewith include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of present or historical fact included herein, are forward-looking statements. When used herein, including any oral statements made in connection herewith, the words “could,” “should,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on the Company’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Statements concerning oil and gas reserves also may be deemed to be forward looking statements in that they reflect estimates based on certain assumptions that the resources involved can be economically exploited. Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date hereof. The Company cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond the control of the Company. These risks include, but are not limited to, the ultimate outcome of the acquisition of NRO by the Company; the Company’s ability to consummate the proposed transaction with NRO; the Company’s ability to finance the proposed transaction with NRO; the possibility that the Company may be unable to achieve expected free cash flow accretion, production levels, drilling, operational efficiencies and other anticipated benefits within the expected time-frames or at all and to successfully integrate NRO’s operations with those of the Company; that such integration may be more difficult, time-consuming or costly than expected; that operating costs, customer loss and business disruption may be greater than expected following the proposed transaction or the public announcement of the proposed transaction; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; commodity price and cost volatility and inflation; general economic, financial, legal, political, and business conditions and changes in domestic and foreign markets; the risks related to the growth of the Company’s business; and the effects of competition on the Company’s future business. Should one or more of the risks or uncertainties described herein and in any oral statements made in connection therewith occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements. There may be additional risks not currently known by the Company or that the Company currently believes are immaterial that could cause actual results to differ from those contained in the forward-looking statements. Additional information concerning these and other factors that may impact the Company’s expectations can be found in the Company’s periodic filings with the Securities and Exchange Commission (the “SEC”), including the Company’s Annual Report on Form 10-K filed with the SEC on March 31, 2023, and any subsequently filed Quarterly Report and Current Report on Form 8-K. The Company’s SEC filings are available publicly on the SEC’s website at www.sec.gov.

Reserve Information

The Company obtained the reserve report information referenced herein from CG&A with respect to the reserves of NRO. The reserves were calculated in accordance with SEC guidelines using the price of $76.97 per barrel for oil, $2.252 per MCF for gas, and $20.619 per barrel for NGL. The base rates of oil of $78.22 bbl and gas of $2.637 per million British Thermal Units (MMBtu) were based upon WTI-Cushing spot prices (EIA) during 2023 and upon Henry Hub spot prices (Platts Gas Daily) during 2023, respectively. The reserve classifications and the economic considerations applied in the reserve report conform to the criteria set forth in the 2018 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers (SPE). All reserve estimates represent CG&A’s best judgment based on data available at the time of preparation of the reserve report, and CG&A’s assumptions as to future economic and regulatory conditions. It should be realized that the reserves are actually recovered, the revenue derived from, and the actual cost incurred could be more or less than the estimated amounts.

Investor Relations Contact:Wobbe Ploegsma[email protected]832.274.3449

 

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LONDON – Oil prices climbed about 3% on Friday, as some  tankers diverted course from the Red Sea following overnight air and sea strikes by the United States and Britain on Houthi targets in Yemen after attacks on shipping by the Iran-backed group.

Witnesses in Yemen confirmed explosions throughout the country.

 futures were up $2.21, or 2.9%, at $79.62 a barrel at 1350 GMT, while U.S. West Texas Intermediate crude futures climbed $2.13, or 3%, to $74.15.

Both benchmarks were on course for a second straight weekly rise.

The U.S. and UK strikes come in retaliation for Houthi attacks since October on commercial vessels in the Red Sea, concentrated on the Bab al-Mandab Strait to the southwest of the Arabian Peninsula, in a show of support for Palestinian militant group Hamas in its fight against Israel.

The escalation has fuelled market concerns about the Israel-Hamas war widening into a broader conflict in the Middle East affecting oil supplies from the region.

That includes the important Strait of Hormuz, on the opposite side of the Arabian Peninsula, between Oman and Iran. Iran seized on Thursday a tanker carrying Iraqi crude south of the strait destined for Turkey.

“If a large part of Strait of Hormuz flows were to be halted, it would present up to three times the impact of the 1970s oil price shocks and over double the impact of the Ukraine war on gas markets, atop already fragile supply chains and stock levels,” said Saul Kavonic, an energy analyst at MST Marquee.

ING analysts in a note said more than 20 million barrels per day of oil move through the Strait of Hormuz, equivalent to around 20% of global consumption.

U.S. President Joe Biden said the “targeted strikes” in Yemen were a clear message that the United States and its partners will not tolerate attacks on its personnel or “allow hostile actors to imperil freedom of navigation”.

A Houthis spokesperson said the group would continue to target shipping heading towards Israel.

Saudi Arabia, a top oil exporter and regional power, called for restraint and “avoiding escalation” and said it was monitoring the situation with great concern.

Attacks by the Houthis in the Red Sea have disrupted international commerce on a route between Europe and Asia which accounts for about 15% of the world’s shipping traffic.

Shipping giant Maersk and others are diverting vessels away from the Red Sea, warning customers of further disruptions.

 

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Workers in China, Russia, and Mexico saw their inflation-adjusted earnings rise in 2023, a new report reveals

 

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The ambassador to New Delhi calls on businesses to explore further opportunities in Russia

 

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Houthi attacks from Yemen on commercial vessels in the Red Sea and Gulf have generated major disruption across key shipping artery

 

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The Biden administration has announced a $9 million grant to Alaska researchers to study a project that could capture carbon emissions from a big new coal-fired power plant and inject them in a depleted natural gas field not far from Anchorage.

The University of Alaska Fairbanks would lead the research into what’s known as carbon capture and storage, or CCS.

That’s a still-emerging field that boosters say could help fight global warming while reorienting the petroleum industry to profit from less environmentally harmful projects — even as research shows that CCS is expensive and still hindered by technical challenges. Critics say it’s largely a distraction from the need to shift to proven renewable energy sources like wind and solar.

The new CCS grant is one of 16, and $444 million in total, announced by the U.S. Department of Energy last month. The department aims to expand carbon dioxide storage infrastructure “to significantly and responsibly reduce CO2 emissions from industrial operations and power plants,” it said in its announcement.

The Alaska grant would help examine the viability of a major carbon “storage complex” in Southcentral Alaska, likely at the mostly depleted Beluga River gas field west of Anchorage, according to the university’s application.

A 60-mile pipeline would carry carbon emissions to Beluga from a new 400-megawatt coal-fired power plant, which a Canadian company, Flatlands Energy, proposes to build in the Susitna River valley. As an alternative, researchers would also examine if the carbon could be injected into aquifers closer to the plant, which would save money on pipeline construction.

The overall project would be the first of its kind in Alaska, and it coincides with an increasing focus from state and federal policymakers on the development of the CCS industry.

The 2021 federal infrastructure legislation included $8.2 billion for the technology, largely to advance demonstration and large-scale pilot projects. A year later, lawmakers boosted a tax credit for carbon storage by 70%, and today, companies can collect an $85 credit for each ton that’s locked away.

Alaska Republican Gov. Mike Dunleavy, meanwhile, has advanced his own policies in an effort to generate profits for the state from the management of carbon emissions.

Earlier this year, Dunleavy signed legislation aimed at generating carbon credits by leaving harvestable timber standing on state land.

A separate, still-pending bill he sponsored — the Carbon Capture, Utilization and Storage Act — would add provisions for CO2 injection and storage to Alaska’s existing framework of oil and gas laws. Dunleavy’s administration envisions companies paying the state at least $2.50 for each ton of carbon injected into public land.

The new Biden administration grant would help the Alaska researchers develop a better understanding of what’s known as pore space — the empty areas between grains of sand or within a rock that could be filled with oil, gas, or injected CO2 — said Brent Sheets, head of the Fairbanks university’s Petroleum Development Laboratory and one of the study’s leaders.

“The state wants to start monetizing its pore value for CO2 — that’s what this is all about,” Sheets said in an interview. “If the state’s going to start monetizing it, they’re going to have to define it.”

For the project to move forward, the Alaska Legislature will have to approve a $2.2 million state budget request from the university and advanced by Dunleavy that would partially match the $8.8 million federal grant.

A group of nine legislators recently traveled to North Dakota for a tour of an active CCS project and briefings on the industry, which included a presentation by researchers working on the new Alaska study, according to Anchorage Democratic Sen. Bill Wielechowski, who attended.

Given his new understanding of CCS technology and the federal government’s support for it, Wielechowski said he’s open to the state budget request, though he probably wouldn’t have been before the trip.

“I don’t think the Biden administration would be providing a grant for dirty coal,” Wielechowski said in an interview. “Let’s have the hearings and let’s see if they genuinely can do this cleaner than some of the alternatives.”

One potential stumbling block for the Alaska project is its proximity to and potential synergies with a controversial proposed road project under development by Dunleavy’s administration, West Susitna Access.

Anders Gustafson, who leads an organization opposing the road called the Alaska Range Alliance, said his group would be closely watching the request for state money as the budget process plays out.

“We’re going to be all over it,” he said.

The study, Sheets said, focuses on a proposed coal plant because no existing source in urban Alaska currently emits enough carbon — and could earn enough tax credits by capturing it — to make a CCS project pay off.

Natural gas plants, which currently generate the vast majority of the region’s electricity, emit a much more diluted stream of carbon, Sheets said.

The university’s grant proposal says it will examine the storage of more than 50 million metric tons of carbon — most of it from the coal plant, with additional contributions from two natural gas plants in the Anchorage area.

At 400 megawatts, the proposed coal plant could generate electricity equivalent to roughly half of urban Alaska’s entire peak demand. But some 25% of that would go toward running the carbon capture infrastructure, Sheets said.

“It’s a pretty big tax on the plant to capture that and separate out that CO2,” he said. “But the technology is well-proven and well-understood.”

Earlier this year, there was just one commercial carbon capture facility operating at a power plant anywhere in North America.

CCS skeptics point to mechanical problems that have left the coal-fired facility, in the Canadian province of Saskatchewan, capturing substantially less emissions than its official target.

The cost of CCS has also proven to be a major obstacle. The only operating commercial-scale carbon capture project at a U.S. power plant, at a coal-fired facility in Texas, shut down for three years amid what its operator described as challenging economic conditions. It reopened in September.

“The extent to which carbon capture and storage will be used in the future is highly uncertain,” the nonpartisan Congressional Budget Office wrote in a report this month. “Its prospects depend on a variety of factors, including changes in the cost to capture CO2, the availability of pipeline networks and storage capacity for transporting and storing CO2, federal and state regulatory decisions, and the development of clean energy technologies that could affect the demand for CCS.”

Source: Alaskabeacon.com

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I am working on several stories about the issues with the potential threats to our national grid. This potential terrorist attack has been planned for years and has been made possible by the current administration’s energy and border policies.

The Biden Administration curtailed an executive order from President Trump that was put in place to stop the illegal terrorism being set up by China and other countries.

The infrastructure has been compromised, and the Hon. J. William Middendorf II wrote about some of the components on March 10, 2021.

Could China Hack Our Electric Grid? Joe Biden Just Made It Easier.

The Key Takeaways in his article:

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