By Christian Roselund

On 11 May, the U.S. Department of the Interior announced the winners of an auction awarding two lease areas off the coast of North Carolina that together can host 1.3 gigawatts of offshore wind. After 17 rounds of bidding Total Energies placed the winning US$160 million bid for 54,937 acres and Duke Energy placed a winning $155 million bid for 55,154 acres. Both sites are located in the Atlantic Ocean south of Bald Head Island.

This sale follows on a US$4.4 billion auction of six lease areas off the coasts of New York and New Jersey in February. These are the first two of seven offshore wind lease auctions that the Biden Administration is planning to hold through 2025. The next will be a sale for lease areas off the coast of Northern & Central California, which the Interior Department plans to hold in September 2022. By the end of 2022 Interior also plans to hold a lease auction in the Gulf of Mexico.

Developers are not waiting for auctions to plan projects. An analysis by Lawrence Berkeley National Laboratory found that developers had applied for 61 gigawatts of offshore wind projects at the end of 2021. However, the same report found that only 19% of wind projects that applied for interconnection between 2000 and 2015 were completed, meaning that less than 20 gigawatts of that is likely to get built. CEA research found that many of these projects are in the Mid-Atlantic and New England regions, where the offshore wind industry is more developed.

But if the offshore wind industry is more developed in the Northeast, the need for it may be greater in states such as North Carolina. Land wind speeds in the Southeastern United States are consistently lower than those in other parts of the country, and such states in “the South” (other than Texas) host very few wind turbines.

Offshore Wind in the South?

Due to a lack of hourly and seasonal correlation between wind and solar in most geographies, many models for high levels of renewable energy show that a balance of wind and solar works best in most regions. As such, offshore wind could provide a way for these states to better meet evening and overnight demand as they add more solar.

However, there are fewer policy drivers for offshore wind in the South than the Northeast. New York and Massachusetts have mandates to add offshore wind, and in Rhode Island the state legislature is considering a bill to include this requirement. By contrast, while North Carolina Governor Roy Cooper issued an executive order calling for 2.8 gigawatts of offshore wind by 2030, this does not have the force of law.

Duke Energy, the state’s largest utility, has also filed plans calling for 800 MW of offshore wind by 2030, but has not yet received approval from North Carolina regulators to build or procure this wind. Additionally, North Carolina and Virginia are the only states in the South to host renewable energy mandates, which include credit systems for renewable energy sources. Such policies are commonplace in much of the rest of the country.

Jones Act Remains a Challenge

There are other challenges to developing offshore wind in the United States. Chiefly, the “Jones Act” of 1920 requires that goods transported between ports in the United States must be transported in ships built, owned, and operated by U.S. citizens or permanent residents.

There are no large wind turbine installation vessels (WTIV) in the United States, although Dominion Energy is currently building a $500 million WTIV that it expects to be online in 2023. Until then, offshore wind developers are hiring foreign-owned WTIV and Jones Act-compliant feeder vessels to deliver materials to these ships.

Read more:

News coverage/analysis: NC offshore wind auction pits ambitious federal goals vs. hesitant state policy (S&P Global)

by Christian Roselund

Various indicators in the U.S. electricity sector are showing price increases, including renewable energy contract prices. An index of power purchase agreement prices has found that for the first time since at least 2018, the price of renewable energy contracts has increased across every grid operator. Meanwhile, capacity prices in the Midwest have surged 50-fold as a shrinking fleet of conventional generators meets inadequate available transmission.

Level10’s Q1 2022 Power Purchase Price Index reports that during the first three months of 2022 renewable energy contract prices increased 9.7%, with prices rising across every major grid operator. Level10 says this increase is the result of “pervasive and unabating headwinds” in nearly every aspect of project development, including supply chain challenges and labor and project component price increases. And as these challenges did not begin in Q1 2022, U.S. renewable contract prices have grown 28.5% year-over-year.

Wind prices have seen a sharper increase than solar prices, rising 13.5% quarter-over-quarter and 41.5% year-over year. But this could be just the beginning for solar costs. Level10 notes that the anti-circumvention investigation against solar cells and modules from Southeast Asia is causing regulatory uncertainty to reach “new heights.”

And these price increases are not limited to the United States; EU contract prices have
also grown. But despite these risks, Level10 indicates that demand for projects remains strong. One factor cited by Level10 is the Securities and Exchange Commission’s (SEC) new proposed regulations around accounting for carbon emissions; another is that projected U.S. wholesale electricity prices are rising as well.

The price of natural gas is a main driver of U.S. power prices, and gas prices are rising as more available U.S. gas is liquefied and sent to Europe. However, there are other factors. In the Midcontinent System Operator (MISO), one of the United States’ largest grids, capacity prices shot up 50-fold in the most recent auction for its Midwest region to $236.66 per megawatt-day. Spokespersons for MISO stated that this is the result of otherwise economic power plants being retired due to market rules that have suppressed capacity prices in recent years.

Notably, capacity prices remained low at about $2.88 per megawatt-day in MISO’s Southern region, which underscores the case for more transmission lines to interconnect various grid regions.

Read more:

Opinion: Contract prices for renewable power are up 30%. What’s going on? (Canary Media / Level10)
News coverage: PPA prices rise 28.5% as supply and regulatory challenges pile up: report (UtilityDive)

by Christian Roselund

The largest U.S. solar and wind developer has warned that between 2.1 and 2.8 gigawatts of its solar and storage projects planned for 2022 could be pushed out to 2023. On his company’s quarterly results call, NextEra Energy CEO John Ketchum cited a shortage of modules driven the anti-circumvention investigation against solar products from four Southeast Asian nations.

Ketchum noted that U.S. solar module assemblers are largely sold out through 2024, and that these only have the capacity to serve 10%-20% of the available market. Regardless, he says that NextEra is “as well positioned as any company in the industry” to navigate these issues, and still expects his company to build 23 to 30 gigawatts of solar, wind, and energy storage from 2021 through the end of 2024.

NextEra’s statements are broadly in line with the statements made by Solar Energy Industries Association (SEIA) about the effects of the investigation. The United States sourced 85% of its PV modules from the four named countries in 2021, and SEIA reports that a survey of its member companies found that three-quarters had PV module deliveries delayed or cancelled. The organization further reports that more than 90% said that the investigation was having a severe or devastating impact on their bottom line.

SEIA expects that the anti-circumvention investigation will reduce the amount of solar installed in 2022 and 2023 by 46%, as installers scramble to find alternatives.

Read more:

Source: Q1 2022 Remarks (NextEra Energy)

News coverage: NextEra warns of ‘outrageous’ downside of Biden solar probe (E&E News)

by Christian Roselund

On 27 April, Florida Governor Ron DeSantis vetoed a utility-authored bill that would have destroyed the state’s rooftop solar market by greatly reducing compensation to homeowners under its net metering policy. DeSantis framed his veto in economic terms, with the following statement: “Given that the United States is experiencing its worst inflation in 40 years and that consumers have seen steep increases in the price of gas and groceries, as well as escalating bills, the state of Florida should not contribute to the financial crunch that our citizens are experiencing.”

Net metering is the fundamental policy for rooftop solar in the United States and allows for a 1:1 exchange of electricity from solar installations with retail power from the grid. The policy is popular in Florida, with 84% of state residents polled in February 2022 supporting the policy.

“The state of Florida should not contribute to the financial crunch that our citizens are experiencing.”
– Governor Ron DeSantis.

HB 741 had been the subject of significant scandal after a Miami Herald investigation revealed that the bill had been authored by the state’s largest utility, Florida Power and Light, and given to a legislator. Despite this, it passed both houses of the Florida Legislature. Governor DeSantis’ veto was widely celebrated by renewable energy advocates and the solar industry.

For more on HB 741, see the 11 March 2022 edition of the U.S. Energy Transition Report.

Read more:

Source: Image of Governor DeSantis’ veto letter (Alissajean, Twitter)

News coverage: Breaking: Florida governor Ron DeSantis vetoes awful solar net metering bill (Electrek)

By Christian Roselund and Anjali Joshi

A new report by Lawrence Berkeley National Laboratory (LBNL) has found that the
capacity of U.S. renewable energy and battery projects awaiting interconnection – including 923 gigawatts of solar and wind -is now greater than the existing capacity on the nation’s grid. The April 2022 edition of “Queued Up” found that as the queues have grown, the average time from filing for interconnection to commercial operation date nearly doubled from 2.1 years in 2000 – 2010 to 3.7 years in 2011 – 2021. This report comes as the nation’s largest grid operator has approved a plan to reform its processes that includes halting new projects for two years to catch up.

Even under normal circumstances, not all the projects that apply for interconnection get built; LBNL puts this number on an historical basis at 23%. For solar and wind, the rates are lower. Queued Up reports that among projects entering the queue from 2011 through 2016, only 20% of wind projects and 16% of solar projects got built by the end of 2021.

The interconnection queue data analyzed by LBNL shows several other significant trends. One is that solar, wind, and battery storage projects are no longer concentrated in California and a few other regions and are increasingly being planned across the United States. The two grids that cover most of the Midwest, PJM Interconnection and the Midcontinent System Operator, currently have the largest volume of solar projects, despite lower levels of solar resource than California or the Southwest.

Fixing the Queues

LBNL’s report is yet one more analysis that underscores that grid operators’ existing mechanisms for planning and approval of projects are not keeping up with the pace of the energy transition in the U.S. electricity sector. In 2016 the Midcontinent System Operator (MISO) underwent reforms which it says were aimed to improve timing and certainty around interconnection approvals. In 2019 Southwest Power Pool (SPP) also made changes to its interconnection process to clear a backlog of projects.

The latest grid operator to approve changes to its queue is PJM Interconnection. On 27 April, PJM’s Member’s committee voted in favor of a new proposal that will make several changes to the way it approves projects, including moving from a “first come, first served” basis to a “first ready, first served” basis. However, the new process will also involve a 2-year moratorium on new projects entering its queue, which has been criticized by clean energy advocates.

PJM plans to file its plans with the Federal Energy Regulatory Commission (FERC) in May, but it may be challenged on some aspects of the plan by an agency that is taking a more active role in interconnection. Last summer FERC started a new rulemaking process to overhaul both transmission planning and the interconnection process nationwide. Concurrent with the LBNL queue report, the U.S. Department of Energy has also released recommendations to build out the nation’s transmission network and speed interconnection.

Battery Boom

Energy storage has grown faster than any other resource in the queues and batteries are the most common “storage” project, comprising around 98% of all projects. The remaining 2% includes pumped storage hydro, compressed air, gravity rail, and fuel cell projects. In particular, the past few years have seen a surge in the capacity of battery projects in the queues, which rose from around 50 GW at the end of 2019 to 420 GW of at the end of 2021. Although energy storage proposals have been mainly focused in California and the West, PJM has also witnessed a strong growth in energy storage proposals.

LBNL’s study also shows a growing interest in hybrid plants that combine generation and storage. At the end of 2021, 42% of solar projects in the queue were proposed as hybrids and solar+ storage was by far the most common hybrid configuration proposed, with 281 gigawatts of solar projects paired with storage. But although developers plan for around 72% of storage capacity (both hybrid and standalone) to come online by the end of 2024, only 9% of storage projects had an interconnection agreement by the end of 2021. This suggests that not all of the planned storage will come online, and that timelines will be adjusted.

Installation Forecasts Are Rising

These massive volumes in the interconnection queues come as analysts are predicting an increasingly large share of renewable energy in the United States in coming years. In an analysis released last week, The Institute for Energy Economics and Financial Analysis estimated that large-scale renewable energy could represent 30% of U.S. generation in 2027, with distributed solar adding another 6%. This is up from around 20% in 2021.

This is much faster than the Department of Energy (DOE) expects; in its February Annual Energy Outlook DOE’s Energy Information Administration (EIA) forecast that it will take until 2050 for large-scale renewables to reach 41% of U.S. generation. However, while all analysts have under-estimated future growth of renewable energy, EIA’s analyses have been among those that later contrasted the most sharply with actual installed volumes.

But to achieve this transition, renewable energy plants must be approved and interconnected to the grid. Until further reforms are made, this process will be a limiting factor to the speed of the energy transition in the U.S. electricity sector.

Read more:

Source: Record amounts of zero-carbon electricity generation and storage now seeking grid interconnection (LBNL) Source: PJM Members Endorse Plans To Revamp and Improve the Generation Interconnection Process (PJM Interconnection)