The New North Slope:   Icewine, Peregrine and Umiat. 

In Home, News by wp_sysadmin

Today’s Key Takeaways:  IRA brings energy service inflation in next 18 months.  Nova Minerals reports strong gold recovery results at Estelle.  Learn more about Australia’s “Alaskan-focused oil exploration company.”  Main headwinds for clean energy are all regulatory – zero emissions projects already massively backlogged. 


Inflation Reduction Act Could Result In More Energy Service Inflation
Bojan Lepic, Rigzone, August 15, 2022

The US Inflation Reduction Act will usher in more energy service inflation as incentives offered to manufacturers struggle to keep up with the increased demand triggered by the bill.

The US Inflation Reduction Act will usher in more energy service inflation in the next 18 months as the incentives offered to manufacturers struggle to keep up with the increased demand triggered by the bill, Rystad Energy claims.

Rystad Energy’s research shows that there will be a positive impact on domestic energy security and the US’ position in the global low-carbon supply chain, but significant growing pains are likely in the coming years.

The bill will provide over $100 billion to accelerate construction start dates for low-carbon developments, including solar, wind, and battery storage. These measures will undoubtedly increase renewable energy installations and short-term demand for US manufacturing, given the focus on domestic production and procurement.

However, the $60 billion provided for expanding manufacturing capabilities will struggle to alleviate existing inflation or even keep pace with expected growth.

The analytics firm stated that deflationary clouds recently circled above the US energy industry, with the cost of goods and services falling across several disciplines. In June 2022, prices fell across civil, mechanical, and electrical goods and services month-over-month, with steel leading the way. The extent to which this deflation will pick up speed or stall depends mainly on the economic moves by the US’ biggest global economic adversary – China.

Producer inflation in China is at an almost 18-month low as manufacturing capacity increases and coincides with a global demand decrease. The country’s short-term stimulus policies will significantly impact the global inflation outlook. If China employs low expansionary policies, new project module construction prices will start to fall before the end of this year. On the other hand, high expansionary policies – which are now a viable option for policymakers due to recent domestic slowdowns caused by weakening global demand – would increase prices by an additional 10 percent this year and only start to fall in 2023.

“Cost inflation in the US energy industry has hit operators, manufacturers, and suppliers hard – and the Inflation Reduction Act shows no signs of addressing that in the near term. The fate of the industry’s future inflation or deflation lies firmly in the hands of the Chinese, fittingly, as US policymakers attempt to build and strengthen a domestic supply chain and attempt to avoid such reliance in the future,” says Matthew Fitzsimmons, senior vice president with Rystad Energy.

In what is a piece of good news for the US onshore industry, China’s actions are unlikely to impact inflation, but they may still be exposed to additional price increases. Supply and demand balances in US shale reign supreme and will continue to push project costs higher over the next year despite falling raw material prices. For example, increased activity has driven spot land rig prices to double their 2016 values. Planned E&P activity through next year will push average high spec rates above $33,000 per day. 

US manufacturing impact

To stoke domestic clean energy manufacturing in the US, the bill incentivizes manufacturers with incentives on components necessary for clean energy projects. These incentives will help to increase the domestic supply of critical components in both wind and solar infrastructure, encouraging developers to ramp up production and boost clean energy capacity.

The bill’s wind and solar industry incentives reward manufacturers based on a facility’s overall power generation rather than the components’ quantity or size. These incentives bode well for reversing rampant price inflation of offshore wind components by incentivizing manufacturers in the US to ramp up production.

Labor market impact

Elements of the Inflation Reduction Act are designed to boost the domestic energy labor market with wage requirements for developers to take advantage of tax credits. The number of US oil and gas extraction employees has grown by 25 percent in the past 18 months, returning to pre-Covid-19 pandemic levels. As a knock-on effect, the number of unemployed American workers actively looking for oil and gas jobs has been at its lowest since 2005. While previous wage premiums have saved the day and enticed workers to help grow domestic oil and gas production previously, the bill will pose new competitive challenges for oil and gas recruitment.

To receive tax credits for clean energy projects, developers must comply with wage requirements set by the Secretary of Labor. Wage rates will be determined by averages based on region and job title to ensure that workers also benefit from the legislation. Developers found to be underpaying workers will have to pay fines to compensate for violations or risk losing their tax benefits.

According to Rystad, these projects require apprenticeship thresholds to be met for developers to receive full tax benefits. For projects commenced in 2022, 10 percent of all labor hours spent on construction, alteration, or repairs must be performed by qualified apprentices. This percentage increases to 12.5 percent in 2023 and 15 percent in 2024. Some roles, including supervisors, superintendents, and administrative staff, are excluded from these rules, so in practice, they only apply to employees directly involved in installing or maintaining facilities.

“The increase in apprentices will likely cause productivity declines for clean energy projects. More inexperienced workers will likely lead to more inefficiencies on job sites. However, investing in a healthy labor force through these requirements will increase productivity in the long run and stabilize hourly wages for developers as workers graduate from apprenticeship programs and develop the skills necessary to complete and maintain clean energy projects,” the company explained.


Say G’Day to 88 Energy
Scott Rhode, Alaska Business, August 2022 Issue

Australian firm explores the North Slope, but not ANWR

Western Australia, the home of 88 Energy, is in some ways the antipodean Alaska. The state shares the distinction of being its country’s largest by area. Although not as thinly populated as Australia’s Northern Territory, most of its people are concentrated in a single city, Perth. It also has a Barrow Island, named after the same Sir John Barrow for whom Alaska’s northernmost point was named in 1826. And the state economy is dominated by oil and gas production, responsible for 61 percent of Australia’s total petroleum output.

Far from the oil fields at home, 88 Energy looks across the globe, describing itself as an “Alaskan-focused oil exploration and appraisal company.” Even for the North Slope, though, 88 Energy is oriented Down Under, working on units far to the south of most other operators. Its portfolio spans 440,000 net acres of the central North Slope region and into the National Petroleum Reserve-Alaska (NPR-A), on land leased both from the state and federal governments.

Meet the Project Areas

Since 2015, 88 Energy has held leases at Project Icewine, which encompasses 193,000 acres south of Prudhoe Bay. The company has conducted seven well penetrations across that project area, at sites designated Icewine-1 and Charlie-1. Icewine is the only North Slope asset that 88 Energy operates but does not have a 100 percent working interest, instead owning a 75 percent share.

To the west, 88 Energy has two working areas on the south side of NPR-A. Project Peregrine is on 195,973 acres acquired in August 2020 via an off-market takeover of fellow Western Australia oil explorer XCD Energy. Sitting on top of the Nanushuk and Torok oil plays, Peregrine has a prospective oil resource of 1.6 billion barrels. In early 2021, 88 Energy drilled the Merlin-1 well, which demonstrated the presence of light oil in three targets.

Just south of Peregrine is 88 Energy’s Umiat field. The company says historic flow testing demonstrated a sustained rate of 200 barrels per day, peaking at 800 barrels per day, with no water mixed in. Umiat has the potential to combine with Peregrine for field operations.

A Texas-based subsidiary of 88 Energy, Regenerate Alaska, paid $771,000 for Tract 29, a 23,400-acre sliver of land on the Canning River’s opposite bank during the first—and so far only—ANWR lease sale in January 2021, in the waning days of the Trump administration. However, ANWR exploration is no longer in the company’s sights.

Farther to the east, just inland from ExxonMobil’s Point Thomson unit, is 88 Energy’s Yukon lease area, covering 19,000 net acres. In the early ‘90s, the Yukon Gold-1 exploration found oil there along the Canning River, which forms the western boundary of the Arctic National Wildlife Refuge (ANWR). Further 3D seismic mapping in 2018 estimated a resource of 90 million barrels of oil equivalent.

The proximity to ExxonMobil’s infrastructure positions the Yukon leases as a jumping-off point for development inside ANWR. A Texas-based subsidiary of 88 Energy, Regenerate Alaska, paid $771,000 for Tract 29, a 23,400-acre sliver of land on the Canning River’s opposite bank during the first—and so far only—ANWR lease sale in January 2021, in the waning days of the Trump administration.

However, ANWR exploration is no longer in the company’s sights.



Will Gas Prices Go Down Again This Week?
Samson Haileyesus, Small Business News, August 15, 2022

The national average gas prices across the US continue its dip on Monday, August 15, 2022, reaching $3.956. It is now below $4 per gallon, first time since March 5, according to the American Automobile Association (AAA). The price of gas is in its 63-day streak of dropping prices at the pump following an all-time high of $5.016 in June.

Gas Prices Go Down Again This Week

The average gas price is currently 10 cents less than one week ago and 62 cents lower than one month ago, but still 77 cents shy from the $ 3.184 price tag a year ago. The continued decline in gas prices has fueled optimism that gas prices are set to cool down within months if not weeks.

63 Straight Days of Price Drop

For 63 consecutive days, gas prices have steadily declined by an average of 10 to 15 cents a week. Despite the relief, some states continue to see the price of gas going above the national average of $3.956.

California continues to experience the highest gas prices in the nation with the average gallon of gas price going $5.366 a gallon at the pump, despite prices dipping by 8 cents from last week. It remains the state with the most expensive gas price, eclipsing the national average by $1.41. Some counties in California continue to see steep gas prices. For example, Trinity and Mono continue to see high gas prices going beyond the $6 mark.



Encouraging gold recoveries from RPM
Shane Lasley, North of 60 Mining News, August 12, 2022

Nova Minerals Ltd. Aug. 8 reported highly encouraging gold recovery results from its first phase of metallurgical test work on mineralization from its high-grade RPM North deposit on the Estelle property in Alaska.

Currently, it is envisioned that ore mined from RPM would be transported to a central processing facility at Korbel, a larger but lower grade gold deposit that lies about 16 miles to the north.

According to an initial scoping study completed earlier this year, a mine at Korbel would produce 1.96 million ounces of gold over an initial 15 years.

The open pit operation outlined in this study would mine 195 million metric tons of ore from the Korbel Main deposit averaging 0.41 grams per metric ton, which would be upgraded to 0.7 g/t gold with an ore sorter before being fed into the mill, floatation, and leaching gold recovery circuit.

The metallurgical work completed for RPM considers the same gold recovery technique.

Floatation tests conducted at Bureau Veritas in Vancouver, British Columbia, recovered 92.4% of the gold from RPM mineralization averaging 1.34 grams per metric ton gold into a concentrate with 14.3% of the flotation feed mass.

Intensive leaching at Bureau Veritas Vancouver recovered 96.2% of gold contained in this floatation concentrate, resulting in an overall gold recovery of 88.9% from RPM mineralization.

“The new metallurgical test work from the RPM Deposit at Estelle continues to demonstrate encouraging gold recoveries on the high-grade deposit using composite samples of only 1.34 g/t,” said Nova Minerals CEO Christopher Gerteisen. “These results from RPM are a significant improvement on the positive results already achieved from the Korbel Deposit and harmonized with the existing flowsheet.”

The strong gold recoveries and higher-grade gold mineralization at RPM are expected to boost the economics of a second scoping study for an expanded operation on the Estelle property that is slated for completion later this year.

The initial study was based solely on the Korbel Main deposit, which hosts 286 metric tons of indicated resources averaging 0.3 g/t (3 million oz) gold, plus 583 million metric tons of inferred resource averaging 0.3 g/t (5.1 million oz) gold.

The gold grades at RPM North are nearly seven times higher.

According to a calculation completed earlier this year, RPM hosts 23.1 million metric tons of inferred resource averaging 2 g/t (1.5 million oz) gold.

Nova is currently carrying out drilling to upgrade and expand this resource.

Initial results from the 2022 drilling at RPM can be read at Nova drills 140m of 6.5 g/t gold at RPM in the current edition of North of 60 Mining News.

It is expected that upgraded resources for both RPM and Korbel will be incorporated in a phase-two scoping study later this year and a prefeasibility study slated for 2023.


Think the Inflation Reduction Act is a climate savior? Think again.
Devin Hartman, RStreet.Org, August 9, 2022

After the malaise of Build Back Better, Senate Democrats on Sunday passed a successor-of-sorts in the form of the Inflation Reduction Act (IRA). The act is rather humorously titled, considering it will have a negligible effect on inflation, according to the Congressional Budget Office (CBO). But the IRA is also hailed as the most important climate action in U.S. history. Perhaps, then, a better name for it would be the Emissions Reduction Act.

At first glance, the alternative name may seem appropriate. The bulk of IRA investments—$385 billion over 10 years—target clean energy and climate, with the main thrust being long-term extensions of production and investment tax credits for mature power technologies. The central estimates of three modeling exercises project that the IRA will drive an additional 10 to 15 percent greenhouse gas emissions reductions economy-wide by 2030, relative to 2005 levels, with the power industry taking the lead. Another analysis found 21 to 26 percent reductions from the IRA just in the power industry. These results might generally indicate the IRA’s effect if you presume that the private sector is emissions agnostic and that few constraints to build and integrate new technologies exist.

The reality, especially in the power industry, is that private markets are brimming with clean energy and carbon reduction appetite but cannot satisfy their hunger because of pervasive flaws in regulatory architecture. Hundreds of gigawatts of new zero-emission generators are massively backlogged, and it is getting worse. Industry cites a record volume of potential clean energy development, yet the rate of growth is slowing. This means voluntary clean energy demand goes unsatisfied, while states fall behind on mandatory renewable portfolio standards.

A closer look reveals that the main secular headwinds are all regulatory, putting aside episodic issues like supply chain disruption. Renewables developers say that new generator interconnection processes are the biggest barrier to renewables development, and the data make a strong case. The operator of the largest wholesale electricity market is so backlogged that it expects to start reviewing interconnection applications filed this past year beginning in 2026. Depending on who you ask in the industry, permitting/siting and transmission congestion/generator curtailment are jockeying for second and third place. Permitting alone takes four years on average and, in some cases, decades.

This does not even get into the additional intricacies of land use, grid reliability and expansion that renewable developers say are underappreciated. For example, outmoded electricity market design, reliability rules and utility procurement practices restrict the ability of unconventional resources to displace conventional power plants reliably and cost effectively. Even if regulators miraculously resolve all these, most relief will not begin for five to 10 years, given implementation and infrastructure timelines. That casts serious doubt on the marginal deployment effect of tax credits and other subsidies, especially in this decade.

Add it all up, and there are scant signs in the market that the hard costs of clean energy are inhibiting development. But there is ample evidence that regulatory quality dictates the pace of the energy transition. Clean energy deployment is a kinked regulatory hose, and subsidies increase the pressure.

These regulatory limitations are, in modeling speak, the binding constraints on deployment. Yet the aforementioned modeling exercises, plus a similar analysis by Moody’s Analytics, do not even reference whether they account for generator interconnection processes. Four of the five studies make no direct or implied reference to transmission congestion or generator curtailment, while three do not note any treatment of permitting or siting constraints. One study capped its model at double annual year-over-year growth to reflect siting and related issues, far above what project developers experience. The Princeton University assessment explained that constraints like siting, permitting and transmission expansion are hard to model and thus may limit energy growth rates in practice.

Clearly, what is hard to model matters most. These constraints are already binding and establish a ceiling for clean energy development far below what simulations expect. As such, it is hard to place much stock on the indicative—much less predictive—value of these studies.

Models are only as good as the assumptions behind them, no matter how sophisticated and well-intended they are. These models hardly reflect the recent past, much less the future. For half a decade, subsidizing mature clean power technologies has been a peripheral driver of deployment and primarily constitutes a public-to-private wealth transfer. This was the case even when markets almost exclusively chose the least-cost technology, whereas in recent years market behavior reveals a healthy willingness to pay a clean premium. By severely discounting what motivates and constrains energy markets, such modeling overstates the effect of subsidies and mandates while discounting the performance of unfettered markets.

Going forward, models must be more than engineering exercises. They need to reflect lessons from observed behavior, such as the demand-side clean premium as well as transportation behavior, where new peer-reviewed evidence suggests that conventional electric vehicle subsidies increase emissions. Modeling needs to incorporate regulatory features accurately at a minimum and, ideally, assess alternative regulatory structures to determine what emissions impact reforms might have.

Assessing an array of prospective policies within the existing policy framework is critical to inform policymakers of the costs and benefits of different policy instruments and select the right ones. Doing so reveals that there are individual regulatory reforms with more emissions impact than the core energy subsidies of Build Back Better, which are largely replicated in the IRA. Those core subsidies conservatively cost north of $115 per ton of carbon abated, more than doubling estimates of their climate benefits. By contrast, regulatory reforms that enable energy development often have negative abatement costs; they are good economic policy before counting emissions benefits. 

An optimistic take on the IRA is that it provides a guarantee that power markets will be motivated, while yielding emissions reductions from some smaller provisions. A realistic take is that the IRA mostly subsidizes what the private sector plans to invest in without remedying what inhibits those investments. Altogether, there is a real risk that the IRA spends hundreds of billions of dollars in a manner that harms social welfare (i.e., negative net benefits). It will be far less efficient and effective at reducing emissions than other policy options, especially in the power industry, where the IRA throws subsidies at a regulatory blockade.

As for now, the question remains: how much climate impact will the IRA have? Nobody has a good guess until we start modeling the real world. In the meantime, the best way to identify climate solutions is to have our ear to the ground.