Emerging technologies and the electric grid

Monday, March 27, 2017

A task force examining the deployment of emerging technologies across the North American electric grid has identified three imperatives necessary to ensure the continued reliability and efficiency of the bulk electricity system, relating to: renewable supply and integration; greater situational awareness; and controlling an increasingly distributed energy system, with increased deployment of distributed energy resources.

The 39-page report, “Emerging Technologies: How ISOs and RTOs can create a more nimble, robust electricity system,” was published on March 16, 2017, by a group of nine Independent System Operators (ISO) and Regional Transmission Organizations (RTO) known collectively as the ISO/RTO Council (IRC).

With respect to integrating renewable resources, the IRC noted that it "[s]upports policies and positions recognizing the electricity system’s ability to accommodate large amounts of renewables and realizing their growing potential."  While remaining "agnostic to specific technologies that may faciiltate renewable integration", IRC supports policies that accommodate emerging renewable integration technologies, while "avoiding early technological lock-in."

With respect to situational awareness, the IRC notes the lack of available data on the penetration of distributed energy resources, but that a lack of data or its sharing should not limit grid operators' understanding of what's happening on the grid.  IRC suggests the development of a general operational data framework, "where increasingly comprehensive operational data from the distribution system is provided as DER penetrations reach different thresholds."

The report also notes, "Because of emerging technologies, North America’s electricity systems are moving toward a more distributed arrangement." In 2016, the Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking in which it proposed rule changes "to remove barriers to to the participation of electric storage resources and distributed energy resource aggregations" in organized wholesale electric markets.  Recognizing that such a rule change could set a framework for future DER growth, the IRC calls for continued coordination, data sharing, and flexibility.

Maine net energy billing rules, 2017 revision

Monday, March 20, 2017

On January 31, 2017, the Maine Public Utilities Commission adopted revisions to its rule chapter 313, governing net energy billing.  Net metering, or net energy billing, is the metering and billing mechanism that Maine and most other states have adopted to promote the development of solar photovoltaic and other distributed renewable energy facilities.  While the Commission first adopted a net energy billing rule in the early 1980s, its 2017 revisions to that rule reduce the benefits of net metering for future projects.  Here's a look at Maine's revised net energy billing rules.

The Commission described its actions in a written order dated March 1, and published its final rule on the same date.   Most notably, the Commission reduced the amount of future generation facility output that can be netted against its transmission and distribution utility bill -- by first introducing, then reducing, a concept called "nettable energy."  Nettable energy is now the entire amount of energy generated by the facility, including the amount consumed by a customer “behind-the-meter”.  This shift -- from netting on a net basis, to netting on a gross basis -- is a significant change in state policy that is unfavorable for behind-the-meter generation.

As before, a net energy billing customer with solar or other eligible generation may offset all of its energy supply bill with its nettable energy.  But the Commission's new rule phases out the former 100% crediting of net energy for transmission and distribution charges.  Depending on the year into which a project is placed in service, the new rule reduces the portion of the "nettable output" -- what counts for netting -- by 10% in each of the next 10 years, reaching 0% T&D crediting for customers that become net energy billing customers after calendar year 2026.  The result is a gradual reduction of the incentive to net energy bill.  (Note that once a customer becomes a net energy billing customer, its rate treatment will generally last for 15 years.  Likewise, existing net energy billing customers may continue to net bill under the previous rule's approach for a 15-year period, after which they could continue to net for supply but not for T&D.)

The Commission also added a section covering renewable energy credit (REC) aggregation.  Section 4 of Chapter 313 provides that new customers in 2018 and after may elect to have the RECs or environmental attributes of project power be aggregated by their local investor-owned utility for sale into the regional market, with the proceeds returned to participating customers.  The Commission described its decision to include a REC aggregation program as "an effort to obtain on an optional basis a value stream that is not currently being monetized."  If small renewable projects would qualify for RECs, but are either not doing so or are not selling the RECs, REC aggregation options may allow some projects to connect with the market.  On the other hand, by selling the RECs, the project owner or power consumer cannot claim to have consumed green electricity, so there are tradeoffs.

The Commission did not change some other aspects of the rule, such as maximum project size (660 kW) or its limit on the number of accounts or meters permissible under a single net energy billing arrangement (10).  It noted, "Fundamental changes to NEB in Maine and promotional programs for larger renewable and community solar projects are the purview of the Legislature as a matter of State energy policy."

Based on a list of legislative requests, the state legislature will consider at least 12 bills relating to solar energy in its 2017 session.

On March 10, the Commission published a Frequently Asked Questions document covering the Chapter 313 net metering rules.  The FAQ provides answers to 10 questions, ranging from why the Commission changed the rule, to providing specific examples of how much nettable energy a customer would be able to claim depending on the year in which its project was placed in service.

US auctions North Carolina offshore wind sites

Friday, March 17, 2017

Yesterday the U.S. Bureau of Ocean Energy Management completed a competitive lease sale for renewable wind energy development in federal waters offshore North Carolina.  Avangrid Renewables, LLC won the auction-based sale with a high bid of $9,066,650.  As a result, it has the right to lease 122,045 areas of ocean space in the designated Kitty Hawk Wind Energy Area.

The Kitty Hawk Wind Energy Area sits 24 nautical miles from shore, off the northeast coast of North Carolina by the Virginia border.  The base roughly triangular area extends 25.7 nautical miles in a general southeast direction, with a seaward apex in the northeast.  Using the National Renewable Energy Laboratory’s estimates of 3 megawatts per square kilometer, the lease area has a potential generating capacity of 1,486 megawatts.

BOEM announced the Kitty Hawk auction in January 2017.  Its conclusion yesterday represents the first federal offshore wind lease sale under the Trump administration.  According to BOEM, three other bidders particiated in the auction: Wind Future LLC, Statoil Wind US LLC, and wpd offshore Alpha LLC.

The North Carolina auction was BOEM's seventh competitive lease sale.  In all, competitive lease sales have raised about $67 million for the federal government.  While no commercial offshore wind projects are currently operating in federal waters, the Deepwater Wind Block Island project off Rhode Island began commercial operation last year.

FERC to hold session on state policies, wholesale markets

Wednesday, March 8, 2017

U.S. energy regulators have scheduled a two-day technical conference to consider how state energy policies affect wholesale electricity markets.

In a March 3 notice of technical conference, the Federal Energy Regulatory Commission gave public notice that it will hold a technical conference on May 1 and 2, 2017.  The notice describes tensions between competitive wholesale energy and capacity markets and state policies.  On the one hand, the Commission noted, "Competitive wholesale energy and capacity markets bring value to customers by efficiently pricing energy and capacity , taking into account the operational needs and the dynamics of the transmission system , and providing transparent signals for investment and retirement of resources."  Generally speaking, these wholesale competitive markets currently select resources based on principles of operational and economic efficiency without specific regard to resource type

But on the other hand, the Commission notes recent increases in "interest by state policy makers to pursue policies that prioritize certain resources or resource attributes" (such as renewable resources, or in-state resources).  That has led to what the Commission calls an "open question": "how the competitive wholesale markets, particularly in states or regions that restructured their retail electricity service, can select resources of interest to state policy makers while preserving the benefits of regional markets and economic resource selection." These topics have come up in discussions relating to several eastern regional transmission organizations and independent system operators, such as the IMAPP process in New England, and similar efforts in PJM and NYISO to consider the integration of public policy into markets.

To foster further FERC-level discussion about the development of regional solutions that "reconcile the competitive market framework with the increasing interest by states to support particular resources or resource attributes," the Commission has scheduled the May 1-2 technical conference. The notice specifically references a range in potential long-term expectations regarding the relative roles of wholesale markets and state policies in shaping the resource mix -- ranging from no state role on the one end, to state authority over resource selection that must be accounted for in wholesale market design -- and a variety of potential solutions in between.

Anyone who wishes to participate in the conference may submit a nomination form to FERC online by 5:00 p.m. on March 17, 2017. 

Oroville Dam evacuation and relicensing

Tuesday, February 14, 2017

A California dam in the midst of a federal relicensing process has experienced flooding and storm-related damage, prompting the evacuation of over 180,000 people.  Evacuation orders and a reservoir drawdown represent the most rapid responses to the Oroville Dam incident -- but future discussions of engineering, dam safety, and public policy are likely to continue after the emergency has been resolved.

Oroville Dam is the tallest dam in the U.S.:  a 770-foot high earthfill embankment dam on the Feather River in northern California.  The dam was built from 1961-1968 by the California Department of Water Resources, as part of the State Water Project.  The resulting impoundment, Lake Oroville, can store over 3.5 million acre-feet of water, making it California's second largest man-made lake.

The Oroville project is subject to licensing by the Federal Energy Regulatory Commission under the Federal Power Act.  Its first license was issued on February 11, 1957, for a 50-year term which expired on January 31, 2007.  The Department of Water Resources filed an application for a new license for the project, which remains pending in Docket No. P-2100, although a settlement agreement was also filed.  In the meantime, the project continues to operate under a series of annual licenses issued by the Commission.  According to a DWR website, it "anticipates that FERC will issue a new license order in 2017 pending issuance of the aquatic biological opinion from the National Marine Fisheries Service."

According to state documents, California was hit by three major storms during January and February 2017, with major rain and runoff.  As Lake Oroville reached its full capacity, operators opened a spillway to allow excess water through the dam.  But on February 7, the spillway began to erode.  Four days later, operators opened the auxiliary emergency spillway, but eventually determined that this too was "in danger of failing."  Since a failure could cause widespread and severe flooding, officials called for evacuations downstream in the Feather River Valley.  On February 12, Governor Edmund G. Brown Jr. issued an emergency order strengthening the state's response.

Focus for now remains on safely resolving the risks that the Oroville Dam or its spillways might fail in a way that releases damaging waters.  The Commission could investigate what happened under its authority over the project through its existing license.  It could also raise issues relating to the incident in the context of the project's relicensing.  That case has been pending for roughly a decade, with a settlement agreement having been reached years ago.  But it is possible that the 2017 Oroville Dam incident could have consequences in the relicensing context, such as revised spillway designs or operating plans that could be reflected as conditions in a new license.

Teton County power outage in focus

Friday, February 10, 2017

What happens when a storm damages utility transmission towers?  Some consumers in the Teton Village area near Jackson, Wyoming, are facing multi-day power outages as local utility Lower Valley Energy scrambles to restore power safely.

Lower Valley Energy is a cooperative serving about 29,000 electricity customers in wesstern Wyoming and southeast Idaho, including the Jackson area.  Its 2015 financial statements describe about $126 million in net utility plant, and operating revenues of about $52 million. 

The Teton County outage started on the evening of February 7, 2017.  The utility announced that at least 10 transmission poles had buckled, causing a "major outage in Teton County."  At the time, it noted that while it did not yet know why the lines fell, wind gusts had been documented over 90 miles per hour.  The utility estimated up to 4,000 customers were without power the next morning, including the Teton Village area, Jackson Hole Mountain Resort ski area, and the airport.

Ultimately, the utility discovered that 17 steel transmission poles had buckled, among other failures. Lower Valley Energy announced a plan to replace them temporarily with wooden poles to restore power, and to "re-route power, hopefully at least on an intermittent basis, to the airport area."  But the damage to the transmission system serving Teton Village led the utility on February 8 to describe an expectation that Teton Village would be without power for 5-7 days.  This would lead the ski area to announce that it will "not be operating until further notice."

Later on February 8, the utility announced that the Jackson Hole airport was fully operational with its own backup generation, but restoring power to Teton Village could take days.  On the next morning, it announced that it had not been "successful in energizing the Teton Village Fire Department and facilities yesterday due to other outages in the valley," but that it hoped to accomplish that day.

Utility reliability comes at a cost, but also provides a value.  Businesses, local people, and visiting vacationers expect reliable access to electricity, but storms and their effects on infrastructure can be unpredictable.  An outage places issues of utility reliability in sharp focus.  After power is restored, questions for follow-up might include how the transmission towers failed, how the utility responded to the incident, and what should be done in the future to prevent similar incidents. Businesses, institutions (like the fire station) and people affected by the Teton County outage might consider how they could reduce their exposure to the risk of a prolonged utility outage -- for example, solar panels or other distributed generation, or battery backup -- and whether the cost is worth the benefit.

NH energy efficiency resource standard workshops

Monday, February 6, 2017

Following the New Hampshire Public Utilities Commission's adoption last summer of an energy efficiency resource standard, a regulatory board has scheduled a series of workshops to allow public input on how utilities serving the state plan to met the standard over the next three years.

On August 2, 2016, the Commission issued its Order No. 25,932, approving a settlement agreement establishing an energy efficiency resource standard or EERS.  The Commission described the EERS as "a framework within which the Commission’s energy efficiency programs shall be implemented," effective January 1, 2018.  Compared to previous energy efficiency structures, the EERS represents a a long term, binding energy savings target consistent with a policy directive to capture all cost-effective energy efficiency.  According to a public notice issued by the Commission, "Implementation of an EERS is expected to increase investment in cost-effective energy efficiency resources, reduce energy costs for NH ratepayers, and create new jobs."

As implementation of the standard nears, the Energy Efficiency Resource Standard (EERS) Committee of the state's Energy Efficiency and Sustainable Energy Board has scheduled a series of stakeholder workshops to allow stakeholders and the general public "the opportunity to influence, early in the planning process, how utilities serving the state are intending to achieve the EERS over the next three years." Workshop topics announced so far include residential, municipal, and commercial and industrial programs; how to evaluate program cost-effectiveness; project finance and program marketing; and evaluation, measurement and verification.

Workshops have been scheduled through March 3, 2017.  Utilities are expected to file a proposed EERS plan with the EESE Board by April 1, 2017, with a final plan to be filed with the Commission by September 30 for approval by December 31.