FERC’s Energy Infrastructure Update for December 2018

FERC’s Energy Infrastructure Update for December 2018

On February 4, the Federal Energy Regulatory Commission (FERC) released its Energy Infrastructure Update for December 2018, which gives the highlights of changes and expansions in the industry.

For natural gas pipelines, five were placed in service, two were certified, and six more were proposed; there were no updates in December for storage facilities or liquified natural gas (LNG) imports of exports. The total number of pipeline projects placed into service in 2018 was 26, which is lower than the 32 in 2017. There were 48 certified in both 2017 and 2018. No storage facilities were placed into service in 2018, and only one was in 2017. There were four storage facilities certified in 2018, compared to only two in 2017. One LNG export was placed into service, compared to three in 2017. There was one import/export facility certified in 2018, and there were none in 2017.

For hydropower, one capacity amendment was filed in December, and another hydropower facility was licensed. In 2018, two facilities files for 10-MW Exemption and three filed for capacity amendments. Only one license was issued last year, and one capacity amendment was issued. Two licenses were placed in service in 2018.

In December, no new coal facilities were put into service, and only four were put in service in 2018; three were put in service in 2017. Seven new natural gas facilities were put in service, and 103 were opened in 2018; this is compared to the 106 put in service in 2017. No nuclear facilities opened in December, but five opened last year; only one opened in 2017. No oil facilities opened in December either, but 14 opened in 2018, compared to the 37 opened in 2017. No hydropower facilities opened either, but 10 opened in 2018; 14 opened in 2017. Twelve wind power facilities opened in December, 55 opened in 2018; 83 opened in 2017. No biomass facilities opened in December, but 13 opened last year; 27 opened in 2017. Two geothermal steam facilities opened, half of the four that opened last year; only two opened in 2017. There were 15 solar facilities opened in December, and 429 total in 2018; in 2017 750 opened.

There were a number of suggestions for additions and retirements to take place by January 2022. One coal addition was suggested, and 57 retirements. For natural gas, 276 additions were suggested and only 94 retirements. There were 11 additions suggested for nuclear power, and nine retirements. Seventeen oil additions and 24 retirements were suggested. For hydropower, 237 additions and 20 retirements were suggested. There were 530 wind additions and no retirements suggested. There were 53 biomass additions and 29 retirements recommended. For geothermal steam, 19 additions and no retirements were suggested. Solar power saw the largest recommended additions with 2,278 and only five retirements.

In December, 20.2 miles of electric transmission projects of less than 230 volts were completed, compared to 54 miles of in December 2017. That same voltage has 327.3 miles in all of 2018, compared to 329.3 in 2017. For voltages of 345, there were 161.8 miles completed in December, compared to 32.5 miles in December 2017. In all of 2018, 714.5 miles were completed, compared to 363.1 miles in 2017. For 500 voltage, there was none in December, only 69.4 miles in 2018; there were no miles completed in 2018. In total, 182 miles were completed in December, compared to 86.5 miles in December 2017. In all of 2018, a total of 1,111.2 miles completed; 692.4 miles were completed in 2017.

FERC Energy Infrastructure Updates for September 2018

FERC Energy Infrastructure Updates for September 2018

On November 5, the Federal Energy Regulatory Commission (FERC) issued an update on the Energy Infrastructure in the country, related to natural gas and hydropower, and covering the highlight for electric generation and transmissions.

One pipeline project was placed in service in September, while another three were certified, and one other pipeline project was proposed.

A total of 10 pipeline projects have been placed into service between January and September of 2018, whereas the same timeframe in 2017, a total of 18 were put in service. Forty-two pipeline projects have been certified in the first nine months of the year, while last year only 27 were certified.

No storage facilities were put into service in those months, and only a single one was put into service in 2017. Four storage facilities were certified, as opposed to only one in 2017.

One liquefied natural gas (LNG) project was put in service for exports, and none were certified for either imports or exports. Last year there were two LNG projects put in service in that timeframe, but none were certified.

As for electric generation, six different projects were put online in September. Three wind plants went online in September, whereas 32 have been brought online in the first nine months. Nine solar power facilities also went online, part of the 310 that have been put in action since January

Four coal plants have gone online this year, along with 68 natural gas facilities, one nuclear facility, 11 oil facilities, ten water, 11 biomass, two geothermal steam, and two waste heat facilities; none of these went online in September. This is compared to the same time period last year, where no coal plants, 79 natural gas, one nuclear, 18 oil, 12 water, 55 wind, 25 biomass, one geothermal steam, and 433 solar facilities were brought online.

There were a large number of proposed additions and retirements of facilities with the goal of being finished by October 2021. For coal there was one addition and 74 retirements; 291 additions and 112 retirements for natural gas; eight additions and retirements for nuclear power; 18 additions and 22 retirements for oil; 252 additions and 19 retirements for water; 57 additions and 24 retirements for biomass; 22 additions and no retirements for geothermal steam; 2,020 additions and five retirements for solar power; six additions and no retirements for waste heat; and 88 additions labeled under the “other” category, which encompasses  “purchased steam, tires, and miscellaneous technology such as batteries, fuel cells, energy storage, and fly wheel.”

The only update FERC had for hydropower was: “NorthWestern Corporation was issued an order raising the capacity of its Missouri-Madison Project No. 2188 from 303.500 MW to 305.240 MW. The project is located on the Missouri and Madison Rivers in Gallatin, Madison, Lewis and Clark and Cascade Counties, MT.”

There were no transmission activities in September that needed to be highlighted in the report, no projects were completed in that month.

FERC’s Annual Report on Enforcement

FERC’s Annual Report on Enforcement

On November 15, the Federal Energy Regulatory Commission’s (FERC) Office of Enforcement issued their 12th annual report on enforcement. As in previous years, the Office of Enforcement will maintain its focus on the threats “posed by fraud and market manipulation in wholesale energy markets” in order to ensure that this kind of conduct does “not undermine FERC’s goal of ensuring efficient energy services at reasonable cost or erode confidence in those markets to the detriment of consumers and competitors.”

The report highlights FERC’s focus on fraud and market manipulation, conduct that threatens the regulated markets transparency, serious violations of mandatory Reliability Standards, and anticompetitive conduct. The Report follows the trend from previous years, of providing the public with information about “the nature of non-public enforcement activities,” like surveillance inquiries, self-reported violations, and investigations that had been closed without enforcement action in the public.

During the presentation about the Report, FERC was informed that “the Report summarizes audits, market reports, litigation filings, and settlements which were approved by the Commission.” The Office of Enforcement said that the summaries are available to help any companies that are seeking to comply with FERC’s orders and regulations. The individuals and companies whose conduct was reviewed in this report were not identified in order to maintain confidentiality.

During the 2018 Fiscal Year, FERC approved six different settlements between Enforcement and subjects in order to resolve different matters. These settlements totaled about $83 million in civil penalties and $66 million in disgorgement. More information on this was included in the Report.

Some of the highlights of Enforcement Report include:

  • “Investigations staff opened 24 new investigations and closed 23 pending investigations with no action. Additionally, staff negotiated six settlements that resulted in more than $83 million in civil penalties and disgorgement of more than $66 million in unjust profits. These Commission-approved settlements included provisions requiring the subjects to enhance their compliance programs and periodically report back to Enforcement regarding the results of those enhancements.
  • Audits and Accounting staff completed 14 audits of oil pipelines, electric utilities and natural gas companies, resulting in 209 recommendations for corrective action and directing refunds and recoveries totaling more than $185 million. Additionally, DAA advised and acted on 435 proceedings at the Commission covering various accounting matters with cost-of-service rate implications.
  • Market Oversight staff continued its analysis of market fundamentals, and enhanced its capabilities for identifying anticompetitive market outcomes and anomalies that may indicate an exercise of market power. Market Oversight published its 2017 State of the Markets Report and Seasonal Assessment reports. It also held two Electric Quarterly Report user group meetings to discuss potential system improvements and enhancements.
  • Analytics and Surveillance staff reviewed numerous instances of potential misconduct and provided analytical expertise to Investigations staff in approximately 50 investigations. Natural gas surveillance screens produced approximately 7,719 alerts. Each month Analytics and Surveillance staff ran and reviewed 84 electric surveillance screens, hourly and intra-hour sub-screens, and reports for more than 36,000 hubs and pricing nodes within six regional transmission owner and independent system operator regions.”
FERC and the America’s Water Infrastructure Act of 2018

FERC and the America’s Water Infrastructure Act of 2018

On November 14, Federal Energy Regulatory Commission (FERC) announced that it has begun implementing the America’s Water Infrastructure Act of 2018, which was signed into law by President Donald Trump on October 23. According to sections 3003 and 3004 of the Act, FERC must issue new rules to establish an expedited process for issuing and amending licenses for already existing non-powered dams and closed-loop pumped storage projects. FERC says the processes have to seek a final decision from them within two years of the receipt of a completed application.

The Act will help speed up the process of licensing and re-licensing for different hydropower projects. The bill can also expand some hydropower projects from a limit of five megawatts to 40 megawatts.

“There are a lot of hydropower projects coming up on relicensing — about a third of the fleet — so as these projects come up to be relicensed, it’s really important that we reduce the amount of regulatory burden to accelerate a timely relicensing process,” said Justin Ong, a policy associate with Clearpath, a Washington-based organization dedicated to advancing conservative-based clean energy policies.

“Giving our utilities the flexibility to better plan ahead will keep our energy sources safe and save taxpayers money,” Sen. Maria Cantwell of Washington said in a statement about the hydropower provisions.

According to the release in the Federal Register, “the Commission has 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).”

FERC released a schedule for the implementation of the Act, which plans for a Notice of Proposed Rulemaking for the expedited licensing process in early 2019 and for a final rule to be made in April 2019. They have also planned for a workshop on the closed-loop pump storage projects that are in abandoned mining sites, which is scheduled to be held in February 2019; FERC’s guidance on this should be issued in September 2019.

FERC will also be providing, in April 2019 a draft list of the already existing non-powered dams that have the greatest potential for non-federal development; they will have a finalized list in August 2019. According to the Energy Department, only three percent of the dams in the United States are currently electric; outfitting these already existing dams could help states meet the mandates for clean and renewable energy.

“In [Indiana’s] 8th Congressional District alone, there are six nonpowered dams that could be modernized to produce clean energy,” Rep. Larry Bucshon, R-Ind., said when the House passed the water projects bill in September.

The Act also requires FERC to convene an interagency task force in order to coordinate the different regulatory processes that require authorization for the new processes; the coordination session will be held on December 12. Some of the agencies that will be joining the task force session include the National Oceanic and Atmospheric Administration, the Department of the Interior, the Department of Energy, the U.S. Forest Service, five Indian tribes, and various state agencies.

“Without question, this water infrastructure package is a win for America,” said FERC committee leaders. “It… promotes hydropower development, which creates clean energy jobs here at home and provides consumers with low-cost, emissions-free electricity. We applaud the Senate for passing this vital legislation and urge President Trump to sign it into law soon.”

FERC Directs Guidance on Return on Equity

FERC Directs Guidance on Return on Equity

On November 15, the Federal Energy Regulatory Commission (FERC) issued guidance on how pending cases are going to be affected by a recent order that proposed using a “new approach for calculating the allowed Return on Equity (ROE) to have it be included in the rates of transmission owners” in New England. These new orders were voted on at FERC’s meeting on October 16.

The first order established a paper hearing to two parties involved in ongoing proceedings regarding the Midcontinent Independent System Operator, Inc. (MISO) transmission-owning members to submit briefs concerning FERC’s new approach to determining the base ROE. The order proposes to change the approach for determining ROE by giving four financial models equal weight, as opposed to relying on the discounted cash flow methodology that FERC had been using.

With these new policies, FERC is abandoning its old two-step discounted cash flow methodology that was issued in Opinion No.531, saying they need to stop using that methodology exclusively, and will instead be using the new, broader model to give everything equal weight.

FERC says that by using a wider range of evidence to determine base ROE, their decisions will now be more closely aligned with how investors make their decisions on investments. This order is similar to the Coakley Briefing Order in that it will not make any changes to the new methodology, it instead will help ensure that everyone in these proceedings gets an opportunity to present their arguments and evidence on determining base ROE.

FERC has also essentially raised the burden of proof for a Section 206 proceeding.

During this discussion, FERC Chairman Neil Chatterjee said they plan to consider if additional changes are needed for its transmission incentives and calculation of base ROE. Chatterjee said it was “high time” to see if FERC’s ROE and incentive policies are producing “the level and type of transmission investment the nation needs.”

“FERC needs to stay laser-focused on adopting and enforcing policies that ensure reasonable transmission rates. This especially applies to making sure equity returns included in transmission rates are not excessive,” said Delia Patterson, senior vice president and general counsel at the American Public Power Association.

The second order gave some additional guidance on the effects of the Coakley Briefing Order in regard to any pending proceedings about base ROE that are already set for hearing and settlement procedures. FERC said in this order that in these types of proceedings it expects the parties involved to address the new methodology that is proposed in the Coakley Briefing Order. This includes presenting evidence based on the new methodology how to apply the new methodology to the facts in these proceedings.

According to FERC’s presentation, “The Coakley Briefing Order addressed issues that the D.C. Circuit remanded to the Commission in Emera Maine v. FERC, related to the New England Transmission Owners’ base ROE as provided for in the ISO New England tariff, which the Commission approved in Opinion No. 531.”

FERC’s new policies are based on the hope that by raising transmission owners’ ROEs, they will encourage some desperately needed investments to respond to changes in the transmission business. They need transmissions to be expanded so they can connect new renewable energy and may affect “how particular resources provide services to the grid and the relative competitiveness of various types of generators.”

Climate activists and transmission owners alike can attest to the importance of bringing more green energy onto the power grid, and the new ROE methodology might help make this happened. During the October meeting where this was voted on, Commissioner Cheryl LaFleur suggested that FERC intends to apply this new policy fairly broadly.

“FERC had coordinated its approaches to determining transmission and pipeline ROEs under the one-stepDCF methodology in the past, it is entirely plausible that FERC will synchronize its ROE methodology for pipelines with the Coakley 2018 proposal soon.”

FERC Staff Issues Assessment of Demand Response and Advanced Metering

FERC Staff Issues Assessment of Demand Response and Advanced Metering

On November 7, the Federal Energy Regulatory Commission (FERC) issued their 13th annual report on demand response and advanced metering, which is required by the Energy Policy Act of 2005.

They discussed the penetration rates for advanced meters, as well grid modernization. The report noted that data has recently indicated that advanced meters have become the main type of meters in the United States. The penetration rate for advanced meters has approached 50 percent. In the last year, several states have requested advanced meters to be deployed on a larger scale; a number of them were approved to carry on.

The summer of 2018’s high temperatures and high fire risks led to utilities and operators in multiple states asking their customers to participate in voluntary conservation, emergency demand response, and/or critical peak pricing.

FERC also provided information on survey data from the U.S. Energy Information Administration (EIA) on recent actions that were taken at the state, federal, and regional levels, as well as by industry. EIA’s data shows that the biggest increase in customer enrollment in retail demand programs was in the radio frequency region, which increased by 50 percent. EIA says this increase was mostly due to the higher reported enrollment programs that are run by DTE Electric Company, Delmarva Power, and Potomac Electric Power Company.

The data shows that the enrollment in retail demand response programs went up by 8.2 percent between 2015 and 2016, and the enrollment in time-based rate programs went up by 4.8 percent.

FERC also responded to Advanced Energy Economy’s (AEE) petition for declaratory order pertaining to their “jurisdiction to regulate the participation of certain energy efficiency resources in the wholesale electricity markets.” FERC found that it indeed has jurisdiction in those markets, exclusively.

They approved the proposed modifications to PJM’s tariff to “improve the ability of certain resource types to participate in PJM’s capacity market.”

The assessment also included information on Order No. 841, the Electric Storage Resource Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, which is intended to remove any barriers for “the participation of electric storage resources in the RTO and ISO markets,” by requiring RTO and ISO to revise their tariffs and establish a model for participation that recognizes the operational and physical characteristics for the storage of electric resources.

FERC discussed the different issues and developments in demand response, specifically state legislative and regulatory activities regarding those and time-based rates. Several states have approved time-based rate pilot programs, “some in combination with proposed electric vehicle charging infrastructure investments, due to an interest in incenting off-peak charging of electric vehicles.” Other states have begun to consider what their next steps will be in regard to time-based rate programs and demand response.

FERC discussed the different issues and developments in demand response, specifically state legislative and regulatory activities regarding those and time-based rates. Several states have approved time-based rate pilot programs, “some in combination with proposed electric vehicle charging infrastructure investments, due to an interest in incenting off-peak charging of electric vehicles.” Other states have begun to consider what their next steps will be in regard to time-based rate programs and demand response.

FERC Acts on Tax Reductions for Energy Customers

FERC Acts on Tax Reductions for Energy Customers

On November 15, the Federal Energy Regulatory Commission (FERC) took steps to help ensure that their ratepayers will receive beneficial tax deductions from the December 2017 Tax Cuts and Jobs Act. They issued a Note of Proposed Rulemaking, several orders, and a policymaking during this meeting, all related to the Tax Act. The Tax Act cut the corporate tax rate from 35 percent to 21 percent, which came into effect on January 1, 2018.

The Notice of Proposed Rulemaking, RM19-5-000, is proposing to require that each public utility transmission provider with a transmission owner tariff or a rate schedule to revise their rates to account for any changes that fall under the Tax Act. FERC says these proposed rules are intended to address the effects the Tax Act has had on the Accumulated Deferred Income Taxes (ADIT), which is reflected in their transmission rates.

According to the Washington Examiner, “FERC’s proposed tax rule would apply to the interstate transportation of energy only, where it has jurisdiction over the wholesale electricity and natural gas markets.”

The utilities FERC is calling public in this instance are electric utilities, but they are owned by investors, not municipal utilities. Under these reforms the public utilities will:

  1. “include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases
  2. include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT
  3. incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT”

Every public utility with transmission stated rates will determine the amount of excess and deferred income tax that is due to the reduced federal corporate income tax rate, and they are to recover or return that amount from or to their customers.

FERC did not provide a specific mechanism to adjust the rate bases, nor did they give a specific method to return the excess ADIT.

FERC says “We estimate that the total number of public utility transmission providers with formula rates that would have to develop revisions to their formula rates, including the addition of a new permanent worksheet, and make compliance filings in response to this Proposed Rule is 106.”

During that meeting, they also addressed policy statement PL19-2-000, which provides guidance on accounting and ratemaking for ADIT, for all natural gas and oil pipelines and public utilities that fall under FERC’s jurisdiction.

“Among other things, the policy statement states that for a public utility or natural gas pipeline that continues to have an income tax allowance, any excess of deficient ADIT associated with an asset must continue to be amortized in rates even after the sale or retirement of that asset,” FERC said.

FERC will also be considering if it needs to make more changes to its calculation of base returns on equity and to transmission incentives.

“I think we all agree that our policies are overdue for a fresh look with input from all interested stakeholders, not just those that happen to be parties to a pending complaint proceeding,” Chairman Neil Chatterjee said. “Further, with 13 years having passed since Congress established Section 219 of the Federal Power Act, I think it’s high time we look at whether these two sets of policies are producing the level and type of transmission investment that the nation needs.”

“FERC is the federal agency that regulates and oversees interstate transmission of electricity, natural gas and oil and is composed of five commissioners nominated by the president and confirmed by the U.S. Senate,” according to the Nevada Independent.

FERC will be receiving comments on these proposals 30 days after this proposed rule is published in the Federal Register. FERC will also be putting the full text of the proposal on their website, and it will be available in FERC’s Public Reference Room from 8:30 a.m. to 5:00 p.m. Eastern time at 888 First Street, N.E., Room 2A, Washington D.C. 20426.