Feds predict US coal consumption falling to 1979 levels

Tuesday, December 4, 2018

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.

FERC issues notices for America's Water Infrastructure Act of 2018 implementation

Wednesday, November 14, 2018

Federal hydropower regulators have issued a pair of notices framing the implementation of recently enacted legislation designed to streamline the processes for licensing some hydroelectric projects.

On October 23, 2018, President Trump signed the America's Water Infrastructure Act of 2018. The new law amends several portions of the Federal Power Act which govern how the Federal Energy Regulatory Commission issues preliminary permits, hydropower licenses, and approvals for qualifying conduit hydropower facilities. It also directs the Commission to:
  • Issue a rule within 180 days establishing an expedited process for issuing and amending licenses for qualifying facilities at existing nonpowered dams that will seek to ensure a final decision by the Commission on an application for a license no later than two years after receipt of a completed application;
  • Issue a rule within 180 days establishing an expedited process for issuing and amending licenses for closed-loop pumped storage projects that will seek to ensure a final decision by the Commission on an application for a license no later than two years after receipt of a completed application;
  • Along with the Secretaries of the Army, Interior, and Agriculture, jointly develop a list of existing nonpowered federal dams that the Commission and the Secretaries agree have the greatest potential for non-federal hydropower development, to be published within 12 months; and
  • Hold a workshop within 6 months to explore potential opportunities for development of closed-loop pumped storage projects at abandoned mine sites, and issue guidance within one year to assist applicants for licenses or preliminary permits for closed-loop pumped storage projects at abandoned mine sites.
On November 13, 2018, the Commission established three dockets in order to implement the requirements of the Act: RM19-6-000 (Licensing Regulations under America’s Water Infrastructure Act of 2018); AD19-7-000 (Nonpowered Dams List); and AD19-8-000 (Closed-loop Pumped Storage Projects at Abandoned Mines Guidance). The Commission's notice establishes a schedule with abbreviated deadlines for the development of these materials, with notices of proposed rulemaking for the expedited licensing processes expected in January or February 2019.

As part of the provisions calling for new expedited processes for issuing and amending licenses for qualifying facilities at existing nonpowered dams and closed-loop pumped storage projects, the new law also requires the Commission to convene an interagency task force, including appropriate federal and state agencies and Indian tribes, to coordinate the regulatory processes required to construct and operate these projects. Also on November 13, the Commission published a notice inviting these groups to request participation in the interagency task force. Federal and state agencies and Indian tribes who wish to participate on the interagency task force must file a statement of interest with the Commission by November 29, 2018.

ISO-NE files info on 2022-2023 capacity market auction

Friday, November 9, 2018

This week the operator of New England's wholesale electricity markets made a series of filings with its federal regulator providing information on its upcoming thirteenth forward capacity auction, through which electric generators may commit to providing electric capacity during the period from June 1, 2022 through May 31, 2023.

ISO New England Inc. is the independent system operator and wholesale market-maker for most of New England's electricity grid. It is a private, not-for-profit entity, which operates pursuant to a tariff on file with the Federal Energy Regulatory Commission. As part of its planning for system operations, ISO-NE operates a forward capacity market through which it conducts annual auctions through which qualified generators and other resources may bid to obtain commitments to provide capacity in a future year, in exchange for which resources will be compensated. The next primary auction for capacity supply obligations will be Forward Capacity Auction 13 (or FCA 13), which will be held beginning on February 4, 2019, and will cover the 2022-2023 capacity commitment period.

In advance of each primary auction, ISO-NE calculates an "Installed Capacity Requirement," which it defines as a measure of the installed resources that are projected to be necessary to meet reliability standards in light of total forecasted load requirements for the New England Control Area and to maintain sufficient reserve capacity to meet reliability standards. In computing the Installed Capacity Requirement, the grid operator considers parameters and assumptions including load forecast, resource capacity ratings, and resource availability. It also considers what relief can be obtained during a capacity deficiency through measures including emergency assistance (tie benefits) from neighboring interconnected regions (New Brunswick, New York, and Quebec), load reduction by reducing system voltage by 5%, and running the system at a minimal level of operating reserve.
 
In its November 6 Installed Capacity Requirement filing, the grid operator told the Commission that it proposed a installed capacity requirement for FCA 13 of 33,750 megawatts, after taking into account 969 megawatts of credits over interconnection with Canadian utility Hydro-Quebec.

In a parallel Informational Filing for qualification in FCA 13, the grid operator noted that 31,432 megawatts of existing generating capacity resources qualified for the 2022-2023 capacity commitment period, as did 80 megawatts of existing import capacity resources, and 3,413 megawatts of existing demand capacity resources, totaling 34,925 megawatts of existing capacity. Some resources submitted bids to retire, and 3,223 megawatts of resources submitted bids to withdraw in part or in whole from the auction if it clears below a defined price. Additionally, ISO-NE qualified 238 new capacity resources, totaling 8,716 megawatts.

ISO-NE will conduct its thirteenth forward capacity auction starting on February 4, 2019.

Federal auction set for Massachusetts offshore wind leases

Wednesday, November 7, 2018

The federal agency responsible for managing ocean energy development on the Outer Continental Shelf has scheduled an auction for about 390,000 acres offshore Massachusetts, to be held on December 13, 2018.

Under federal law, the U.S. Bureau of Ocean Energy Management is responsible for conducting auctions to lease parcels of federal waters for offshore wind energy development.

On October 17, Secretary of the Interior Ryan Zinke announced that BOEM will hold its next offshore wind auction in December. According to the Final Sale Notice published in the Federal Register on October 19, the agency will hold its Atlantic Wind Lease Sale 4A, covering 388,569 acres offshore Massachusetts. The sale will cover three separate leases, located within an area previously offered but unsold in 2015.

BOEM map of the proposed lease areas available through the December 2018 auction.

Nineteen companies have qualified to participate as bidders in the lease sale:
  • Avangrid Renewables, LLC
  • Camellia Wind Energy LLC
  • CI III Blue Cloud Wind Energy II LLC
  • Cobra Industrial Services, Inc.
  • Deepwater Wind New England, LLC
  • East Wind LLC
  • EC&R Development, LLC
  • EDF Renewables Development, Inc.
  • EDPR Offshore North America LLC
  • Enbridge Holdings (Green Energy) L.L.C.
  • Innogy US Renewable Projects LLC
  • Mayflower Wind Energy LLC 
  • Northeast Wind Energy LLC 
  • Northland Power America Inc .
  • PNE WIND USA, Inc.
  • Equinor Wind US LLC
  • Vineyard Wind LLC
  • Wind Future LLC
  • wpd offshore Alpha LLC
According to BOEM, if fully developed, the areas available for leasing could support about 4.1 gigawatts of commercial wind generation.

Canada's Supreme Court rules for Quebec utility over energy contract

Monday, November 5, 2018

Canada's highest court has ruled that Quebec's provincial utility Hydro-Quebec cannot be required to renegotiate a long-term contract to buy power from a Labrador hydroelectric plant at below-market rates, even though the deal has yielded about 14 times more profit for Hydro-Quebec than for the Labrador generator.

At issue is the Churchill Falls hydroelectric plant on the upper Churchill River in Labrador, and a 1969 agreement between Hydro-Quebec and Churchill Falls (Labrador) Corporation Limited -- a company jointly owned by Newfoundland and Labrador Hydro and Hydro-Quebec. The Churchill Falls plant can generate 5,428 megawatts of power, and is one of the world's largest hydroelectric power stations.

According to former Premier of Newfoundland and Labrador Brian Tobin, during pre-construction negotiations, Hydro-Quebec told Churchill Falls that it would not allow the Labrador generator to "wheel" project power through the Hydro-Quebec grid, nor to build its own power line through Quebec to reach U.S. markets. As a result, under the terms of the 1969 agreement, Hydro-Quebec agreed to buy most of the project's power at the fixed price of $2.50 per megawatt-hour, to guarantee construction cost overruns, and to build transmission lines connecting the generators to markets, enabling the Labrador generator to sell power and to use debt financing to construct the plant. The original contract was set to expire in 2016, but included a renewal clause allowing Hydro-Quebec to extend the contract for an additional 25 years at a fixed price of $2 per megawatt-hour through 2041.

After the contract was signed, changes in the electricity market -- including oil price shocks in the 1970s, a decline in public confidence in nuclear power after a 1979 accident, and the U.S. Federal Energy Regulatory Commission's 1996 decision to require open access to transmission systems -- meant the contract's purchase price is now well below market prices. Because Hydro-Quebec sells electricity from the plant to third parties at market prices, Hydro-Quebec reaps substantial profits from the deal. For example, Hydro-Quebec reports that the average retail price for residential customers in St. John's, Newfoundland in 2018 is $120.30 per megawatt-hour. Canada's National Energy Board says the 2017 average wholesale prices for electricity imports were over $24 per megawatt-hour, with exports priced even higher at $38.58 per megawatt-hour -- over 19 times higher than the price Hydro-Quebec now pays Churchill Falls during the extended contract term. According to CBC, the contract has yielded about $28 billion in profits to Quebec, but just $2 billion for Newfoundland and Labrador.

Citing legal theories including a general duty of good faith, Nalcor Energy subsidiary Churchill Falls asked Canadian courts to order that the contract be renegotiated and the benefits be reallocated. After lower courts sided with Hydro-Quebec, the generator appealed to the Supreme Court of Canada.

On November 2, the Supreme Court of Canada rendered its judgment in the matter of Churchill Falls (Labrador) v. Hydro-Quebec. The high court found, by a 7 to 1 decision, for Hydro-Quebec, noting that the parties "bound themselves knowing full well what they were doing" and that Hydro-Quebec could insist on adhering to the contract despite the "unforeseen" increase in the power's market value.

The one dissenting judge characterized the contract as "relational" in nature, and thus said that both parties are subject to a duty of cooperation which Hydro-Quebec breached by failing to renegotiate and to more fully share the benefits of higher-than-expected market prices. He said that because "a profit imbalance of this nature and magnitude is beyond what the parties intended when they concluded the agreement", the parties had an implied obligation to cooperate in establishing a mechanism for the allocation of "extraordinary profits."

New law eases some hydro licensing processes

Thursday, November 1, 2018

A recently-enacted federal law will make it easier for hydroelectric project developers to secure a license for new hydroelectric facilities at existing non-powered dams.

U.S. rivers are home to thousands of dams, most of which impound water but don't generate electricity. A 2013 report suggested only 3% of the nation's 80,000 dams were used to produce hydroelectric power. In an effort to facilitate the development of hydroelectric facilities at some of these non-powered dams, Congress recently enacted the America's Water Infrastructure Act of 2018.

Title III of the Act relates to energy matters. One section of the Act extends the default term of preliminary permits for hydropower development from three to four years. The Act authorizes the Federal Energy Regulatory Commission to extend the period of a preliminary permit for up to four additional years, and to issue an additional permit under "extraordinary circumstances."

Another section of the Act speeds up the process through which the Commission evaluates proposals to develop "qualifying conduit hydropower facilities" and increases such a project's maximum installed capacity from 5 megawatts to 40 megawatts.

A third section of the Act requires the Commission to, within 180 days, issue a rule establishing an expedited process for issuing and amending licenses for hydroelectric facilities meeting defined criteria. These criteria require the "qualifying facilities" to be associated with an existing dam or other barrier operated for the control, release, or distribution of water for agricultural, municipal, navigational, industrial, commercial, environmental, recreational, aesthetic, drinking water, or flood control purposes, which as of the date of the Act's enactment was not generating electricity with Commission-licensed or exempted hydropower generating works. The Act also requires that the operation of these facilities must not result in any material change to the storage, release, or flow operations of the associated qualifying nonpowered dam.

The Act also includes provisions creating an establishing an expedited process for issuing and amending licenses for closed-loop pumped storage projects, and prescribing the considerations for setting the terms of new licenses for existing projects through the relicensing process.

The Act, which was introduced in the Senate as S.3021, was signed by President Trump on October 23, 2018, and became law the same day. The Commission has until April 2019 to issue the rules required by the Act.

FERC solicits panel members to resolve hydropower licensing study disputes

Monday, October 29, 2018

U.S. hydropower regulators have asked for volunteers interested in serving as panel members to assist in resolving disputes related to the scope of studies required for hydropower licensing.

Under federal law, the Federal Energy Regulatory Commission is tasked with processing applications for licenses for most hydropower projects located in the U.S. To process any given application, the Commission typically uses one of three different licensing processes. Since 2005, the Commission's "Integrated Licensing Process" or ILP has been the default choice.

Under the ILP, the applicant seeking a license files a proposed study plan describing the studies it intends to conduct to inform the Commission's review of its application. Studies might cover the project's impact on a variety of types of resources and issues, such as aquatic, terrestrial, cultural, recreational, geological, land management, engineering and socioeconomic topics. After a 90-day period of consultation with stakeholders and Commission staff, the applicant may file a revised study plan for Commission approval. Ultimately, the director of the Commission's Office of Energy Projects will issue a study determination approving the study plan with any modifications based on the record. Whatever studies are required by the Commission-approved study plan must be conducted by the applicant or its consultants.

The nature and extent of the studies required can be controversial. Stakeholders have opportunities to comment on the applicant's original study plan, to participate in consultation, and to comment to the Commission on the revised study plan.

Under the ILP, certain federal or state agencies or tribes also have the ability to request that a study dispute be referred to a dispute resolution panel. The three-member panel would consist of FERC staff, the agency or tribal representative referring the dispute, and an independent third person selected by the other two panelists from a list of subject-matter experts. The panel members make a finding with respect to each disputed study request, on the extent to which each study criteria set forth in the regulations is or is not met, and why. The panel then makes a recommendation to the Director of the Office of Energy Projects based on its findings.

On October 22, 2018, the Commission issued a notice requesting applications from those interested in being listed as potential panel members. The Commission previously compiled lists in 2004, 2010, and 2015. For the latest round, the Commission has requested applications by January 31, 2019.