2018 marks record for corporate renewable energy buys

According to Rocky Mountain Institute’s Business Renewables Center, corporate renewable energy procurement set a new single-year record for new capacity of announced wind and solar deals in 2018.

The Center reports that as of mid-December 2018, publicly announced corporate procurements of renewable energy reached 6.43 gigawatts. Procurement approaches counted toward this total include power purchase agreements, green power purchases, green tariffs, and outright project ownership in the United States.

Facebook, AT&T, Walmart, ExxonMobil and Microsoft had the five highest total volumes of newly announced deals; Facebook alone added 1,849.5 megawatts of new renewable procurement.

The Center notes that the U.S. renewables market has nearly doubled its annual total of corporate clean energy off-site deal volume since its prior highpoint in 2015. Also noteworthy is a near-doubling of the number of new entrants into the procurement market, including AT&T which completed deals for 820 megawatts of renewable power in 2018.

According to the Center's Deal Tracker, the total cumulative corporate procurement of renewable energy in the U.S. since 2013 now exceeds 15 gigawatts.

$11.5 trillion investors' group calls for European utilities to end coal use by 2030

A group of 95 investors organized as the “Institutional Investors Group on Climate Change” has issued an open letter to European power companies on December 19, 2018, asking firms to demonstrate they are implementing business strategies aligned with the goals of the Paris Agreement.

The investors participating in the Institutional Investors Group on Climate Change collectively have $11.5 trillion in assets under management or advise; 20 of the 95 signatories each have over $200 billion in assets under management, including Aberdeen Standard Investments, BNP Paribas Asset Management, DWS, Legal and General Investment Management, Nordea Group and M&G. Other signatories include the California Public Employees' Retirement System, California State Teachers' Retirement System, New York City Comptroller’s Office, and New York State Common Retirement Fund.

Citing the United Nations IPCC Special Report on Global Warming of 1.5 °C issued on October 8, 2018, the investors cite the risks to global markets and investments from 2 °C or higher temperature rises as “potentially catastrophic.” The IPCC report found that a number of climate change impacts could be avoided by limiting global warming to 1.5 °C compared to 2 °C or more. But the report also noted that limiting global warming to 1.5 °C would require “rapid and far-reaching” transitions in land, energy, industry, buildings, transport, and cities. In particular, the IPCC report concluded that to limit warming to 1.5 °C would require net global human-caused emissions of carbon dioxide to fall by about 45 percent from 2010 levels by 2030, reaching "net zero" around 2050. 

The group demands that power generators, grid operators and distributors “plan for their future in a net-zero carbon economy.” Specifically, they request companies to publish transition plans consistent with the goal of the Paris Agreement; develop explicit timelines and commitments for the rapid elimination of coal use by utilities in EU and OECD countries by no later than 2030; and support the development of “ambitious climate policy aligned with the Paris Agreement” directly and through their trade associations.

NJ approves offshore wind funding mechanism, rejects demonstration project

On December 18, the New Jersey Board of Public Utilities took two actions affecting offshore wind: approving the state’s Offshore Wind Renewable Energy Certificate (OREC) funding mechanism, but rejecting a petition by Nautilus Offshore Wind, LLC to install a 25 MW offshore wind demonstration project in state waters off the coast of Atlantic City. Meanwhile, developers have formed a new joint venture to develop offshore wind in federal waters farther offshore New Jersey.

New Jersey Governor Phil Murphy has set a goal of 3.5 gigawatts of offshore wind capacity by 2030, and in May 2018 he signed into law a renewable energy bill codifying that goal into statute. On September 17, 2018, the NJBPU opened the nation’s largest single-state solicitation to date, seeking 1,100 megawatts of offshore wind. Applications will be accepted through December 28, 2018. Winning projects will be compensated through the OREC mechanism approved this week, which requires electric companies to buy defined quantities of ORECs from offshore wind developers, much like a traditional renewable portfolio standard mechanism.

Also on December 18, the BPU rejected a 25 megawatt demonstration project proposed by Nautilus (under development by EDF Renewables and Fishermen’s Energy). The Nautilus project would feature three turbines in state waters about 2.8 miles offshore Atlantic City. But the BPU found the Nautilus project did not demonstrate the economic and environmental benefits required under the Offshore Wind Economic Development Act for the state to commit ratepayer funds. In particular, the BPU found that Nautilus didn’t provide sufficient information to substantiate claimed economic benefits, and further that Nautilus demanded a price that was too high given the unsubstantiated benefits.

But offshore wind development may soon occur farther offshore New Jersey. On December 19, 2018, EDF Renewables North America and Shell New Energies US LLC announced the formation of a 50/50 joint venture, Atlantic Shores Offshore Wind, LLC to co-develop offshore wind generation in federal waters offshore New Jersey. The site is about 8 miles offshore Atlantic City. At issue is the 183,353-acrea OCS-0499 lease area, the rights to which were initially auctioned by the federal Bureau of Ocean Energy Management in 2015. That auction was won by Toto Holding Group subsidiary US Wind Inc., with a winning bid of $1,006,240.

More recent federal auctions for offshore wind site leasing rights have brought much higher winning bids -- for example, a December 2018 auction for sites offshore Massachusetts brought in about $135 million for each of three lease areas, totaling over $405 million in winning bids for about 390,000 acres.

Feds reap $405 million offshore wind bidding bonanza

In what the Trump administration has called a "bidding bonanza", the latest federal auction of rights to lease ocean space for offshore wind development has brought $405 million in winning bids.

On December 14, 2018, the federal Bureau of Ocean Energy Management conducted its eighth competitive lease auction for renewable energy in federal waters. At stake were the rights to lease three areas totaling about 390,000 acres over the Outer Continental Shelf offshore Massachusetts.
The three lease areas in question are located 19.8 nautical miles from Martha’s Vineyard, 16.7 nautical miles from Nantucket, and 44.5 nautical miles from Block Island. These sites were previously offered for leasing through a federal auction in 2015, but went unsold at that time.

Eleven companies participated in the auction by submitting bids, out of a total of nineteen companies that had been deemed qualified to bid. The three provisional winners were Equinor Wind US, LLC  and Mayflower Wind Energy, LLC (each bidding $135 million) and Vineyard Wind, LLC (bidding $135.1 million). These amounts are significantly higher than any previous federal auction for offshore wind sites has yielded; the previous record winning bid was just over $42 million in December 2016 for a lease area offshore New York.

After the Department of Justice and Federal Trade Commission perform an anti-competitiveness review of the auction results, each winning bidder will be required to pay the winning bid amount to the Bureau and to post financial assurance. In exchange, each winning bidder will receive a lease with a preliminary term of one year, during which the lessee may submit a Site Assessment Plan (SAP) to BOEM for approval. Under the regulations governing the federal leasing process, the SAP describes the buoys or other facilities a lessee plans to deploy to assess the lease area's wind resources and ocean conditions. After BOEM approves a lessee's SAP, the lessee may submit a detailed Construction and Operations Plan (COP) to BOEM within four and a half years for approval. When presented with a COP, BOEM will conduct an environmental review. Finally, after BOEM approves any COP, the lessee will have a 33-year term to construct and operate the project.

FERC relicenses Poe hydro project

The Federal Energy Regulatory Commission has issued an order issuing a new hydropower license to utility Pacific Gas & Electric Company for its Poe Hydroelectric Project.

The 143-megawatt project is located on the North Fork Feather River in northern California, and includes land within the Plumas National Forest. Originally licensed in 1953, the project includes two dams impounding reservoirs, a 33,000-foot-long pressure tunnel bypassing about 7.6 miles of the river, and a powerhouse with two turbines.

The Commission issued a new 40-year license for the Poe project to PG&E on December 17, 2018. In relicensing proceedings, the Commission considers a number of public interest factors, including the economic benefits of project power. In general, the Commission evaluates the economics of a hydropower project by comparing the current costs of the project to likely alternative power, without considering forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date. The Commission says the basic purpose of its economic analysis is to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power.

In the Poe project's case, the Commission noted that after considering mandatory conditions and other measures suggested by Commission staff, PG&E's annual cost of operating the project would be about $9,590,000. Assuming that the project would generate an average of 498,113 megawatt-hours of energy annually, this works out to $19.3 per megawatt-hour. By comparison, the Commission found that the project's the corresponding alternative energy cost plus the value of its dependable capacity gave this power a value of $50,800,000, or $102 per megawatt-hour in the first year of operation, the project would cost $41,210,000 or $82.7 per megawatt-hour less than the likely alternative cost of power.

EIA highlights Maine electric reliability woes

How long was your power out last year? How many times was your utility electricity service interrupted? Recently released federal statistics show that in 2017, the average Maine electricity customer experienced both the greatest number of interruptions and the longest total duration of power outages of any state in the country.

The U.S. Energy Information Administration tracks electric utility service outages. EIA tracks electric utility service interruptions using two reliability metrics developed by the Institute of Electrical and Electronics Engineers (IEEE): System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI). In general, SAIDI tracks the number of hours an average customer went without electricity service in the year, while SAIFI tracks the number of power outages lasting longer than 5 minutes.

According to the EIA, in 2017 the average U.S. electricity customer experienced 1.4 power outages, losing power for an average of 7.8 hours or 470 minutes. EIA notes that 2017 brought more "major events" like hurricanes and winter storms compared to the previous year. Excluding these major events, EIA reports that the average customer experienced just one power outage in 2017, with an average duration of about 2 hours.

But customers in some states suffered more frequent and longer-lasting interruptions in electricity service, and Maine led the pack in these power outage metrics. According to EIA data, the average Maine customer experienced 3 power outages, with an average annual interruption time of 42 hours.

U.S. Energy Information Administration chart presenting data from Annual Electric Power Industry Report, EIA-861.

For example, one major power outage occurred on October 30, 2017. As a result of a wind storm, Maine's largest utility Central Maine Power Company eventually reported that over 470,000 customers -- more than 60 percent of its customer base -- were without power. Two days after the storm, CMP estimated that over 190,000 homes and businesses remained without service. Some customers remained in the dark for a week.

US EPA sets renewable fuel standard for 2019

U.S. environmental regulators have established renewable fuel standards for 2019, calling for a 3% increase in renewable fuel volumes over 2018, but have continued to waive statutory requirements targeting even larger volumes of renewable fuel.

Congress created the Renewable Fuel Standard or RFS program through the Energy Policy Act of 2005, and expanded the program through the Energy Independence and Security Act of 2007. Administered by the U.S. Environmental Protection Agency, the RFS requires a certain volume of renewable fuel to be used in transportation (motor vehicles and jets) and heating. Refiners and importers of gasoline or diesel, along with other market participants like fuel producers and exporters, track and trade renewable fuel credits called Renewable Identification Numbers or RINs.

The RFS includes four categories of renewable fuel: cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel. By statute, Congress prescribed specific volumes of these four categories of renewable fuel for each year through 2022, and required the EPA to set RFS volume requirements annually based on these statutory targets. The statute also allows the EPA Administrator to waive these volumetric requirements, based on a determination that implementation of the program is causing severe economic or environmental harm, or based on inadequate domestic supply.

On November 30, 2018, the EPA issued its final rule for the 2019 RFS program. The 2019 final rule sets the total U.S. renewable fuel volume requirements for 2019 at 19.92 billion gallons, including 4.92 billion gallons of advanced biofuel, 2.1 billion gallons of biomass-based diesel, and just 418 million gallons of cellulosic biofuel. The rule also sets a 2020 volume requirement for biomass-based diesel of 2.43 billion gallons.

The EPA noted that "the market has fallen well short of the statutory volumes for cellulosic biofuel, resulting in shortfalls in the advanced biofuel and total renewable fuel volumes." Based on this observation, EPA exercised its waiver authority to finalize the cellulosic biofuel volume requirement at the level EPA projects to be available for 2019. This is consistent with EPA's past practice, through which it has set the cellulosic biofuel requirement lower than the statutory volume for each year since 2010.

Feds predict US coal consumption falling to 1979 levels

U.S. coal consumption in 2018 will reach its lowest level since 1979, according to a prediction by the U.S. Energy Information Administration. Reduced coal use for electricity generation is the largest contributor to the decline, driven by factors including economics and environmental regulations.

The EIA tracks total U.S. coal consumption. According to its latest forecast, EIA expects total U.S. coal consumption in 2018 to fall to 691 million short tons. This represents a 4% decline from 2017, and would bring coal use in line with 1979 levels.

Source: U.S. Energy Information Administration

EIA cites reductions in the use of coal to generate electricity as the largest contributor to this decline. Between 2007 and 2018, 93% of total U.S. coal consumption was for electricity generation. But shifts in how the country generates power -- including retirements of over 66 gigawatts of coal-fired power plants since 2007, plus decreases in the utilization or capacity factor of most remaining coal-fired generators -- have reduced the nation's consumption of coal.

Part of the shift away from coal-fired power production can be explained by economics. Natural gas prices have generally remained relatively low compared to coal prices over the past decade, and fuel-free renewable power projects are on the rise.

Environmental regulations such as the Mercury and Air Toxics Standards (which took effect in 2015) have also contributed to the shift, both directly (for example, restricting carbon emissions) and indirectly (by affecting the economics of coal-fired power generation and prompting further plant retirements instead of investments in environmental controls).

EIA predicts that the trend away from coal will continue in the short term, projecting power sector coal consumption to fall by a further 8% in 2019.