Maine considers water shortage readiness

In the midst of a regulatory inquiry into Maine water utilities' ability to prepare for and respond to water supply emergencies, agency staff have issued a preliminary recommendation intended to stimulate further discussion and comment -- which could ultimately lead to changes in how Maine regulates water utilities and water supply.

2016 brought drought to much of Maine. According to a Notice of Inquiry issued by the Maine Public Utilities Commission that year, the drought posed special challenges for some of Maine's water systems with limited sources of supply -- especially those with significant seasonal demands, antiquated infrastructure, or high levels of non-revenue water. In response, the Commission opened an inquiry to gather information that will allow it to identify problems and identify collaborative and proactive solutions. The Commission received responsive comments from about a dozen water utilities, and staff conducted additional research on the topic.

On March 5, 2018, the Commission staff issued its Preliminary Recommendation in regard to the Inquiry. The document describes its recommendations as preliminary and “intended to stimulate further discussion and comment on the issues raised in the document”. It says its intended audience “is broader than the usual participants in Commission proceedings and includes entities that may not be familiar with Commission practices and governing statutes.”

Findings in the 36-page Preliminary Recommendation include:

• Maine’s 152 water utilities responded well to the 2016 drought.
• Most of Maine's water utilities should be allowed to make their own decisions regarding water supply emergencies.
• Most Maine water utilities have the ability to adequately prepare for, and respond to, a water supply emergency.
• Water supply emergencies are not amenable to a one-size-fits-all approach because of the wide variety of potential circumstances.
• All Maine water utilities should be required to prepare some sort of Emergency Response Plan, and all that experience a water supply emergency should be required to prepare an after-action report.
• Water utilities need clearly-defined authority to respond to a water supply emergency -- ideally in the utility's Terms and Conditions.
• Various entities can provide help to a water utility that needs assistance preparing for, and responding to, a water supply emergency. Support can come from neighboring systems, membership organizations, and state agencies.
• State agencies should work cooperatively to support water utilities before, during, and after a water supply emergency.
• Effective communication before and during a water supply emergency is critical.
• Some Maine water utilities are more vulnerable to a water supply emergency and may need assistance -- especially those with a limited source of supply, aging infrastructure, high levels of non-revenue/unaccounted-for water, seasonal demands, and lack of metered service. Other challenges include a lack of resources, recalcitrant customers, and local socioeconomic factors, or excessively prioritizing low rates over critical system improvements.

Commission staff has requested written comments by March 30. It said it is considering holding between two and five workshops across Maine to solicit oral comments about the Preliminary Recommendation, after which it will draft a Final Recommendation for the Commission’s review.

ISO-NE 2018 Regional Electricity Outlook

Regional electricity grid operator ISO New England, Inc. has released its 2018 Regional Electricity Outlook. According to the report, "the biggest challenge to the reliability of the grid is the lack of fuel infrastructure to supply the fleet of natural-gas-fired generators, further emission restrictions on oil-fired generation, and the reality that older oil and nuclear generators are becoming less economically competitive and may retire before the region has added sufficient new energy sources to replace them."

The report cites competitive forces has having "unleashed new approaches for producing electricity in a cleaner way and integrating technology that enables different types of resources to participate in the wholesale markets." It notes new resource types entering the wholesale market, including demand resources, and fast-responding energy storage devices.

With respect to energy supply, the 2018 outlook notes that the amount of wind and solar power in New England continues to grow "and is making a difference in how the ISO operates the power system and designs the wholesale markets." In 2017, the amount of new wind power seeking interconnection in New England surpassed proposed new natural-gas-fired generation for the first time, including significant amounts in Maine and offshore of Massachusetts.

On the demand side, it notes that significant investments in solar resources and energy-efficiency measures have moderated demand for wholesale electricity, but that electrifying the transportation and heating sectors to reduce their carbon emissions could lead to increased demand.

ISO-NE has previously identified the risk that power plants will run out of fuel as the foremost challenge to a reliable power grid in New England. Last month, ISO-NE released an operational fuel security study analyzing fuel security risks facing region's power plants under a wide range of hypothetical future scenarios. That report concluded that maintaining the electric grid's reliability "is likely to become more challenging, especially if current power system trends continue."

The 2018 Regional Electricity Outlook notes that while ISO-NE plays a role in addressing regional fuel-delivery constraints, "it will be up to market participants and state officials to take actions to secure forward fuel arrangements or bolster supply- or demand-side infrastructure." The report identifies potentially appropriate investments as including "enhancements to natural gas infrastructure or the supply chains for liquefied natural gas and oil; relaxation of rules to allow easier permitting and operation of dual-fuel resources; investments in even more renewable energy and any transmission needed to deliver it; or further measures to significantly reduce demand on the power system or the gas system," or some combination of these.

While reliability is core to the grid operator's priorities, the report acknowledges that New England's policymakers, businesses and citizens also value economic and environmental goals. The report specifically highlighted what it called "the reliability, economic, and environmental consequences of our situation: that regional action to resolve fuel-security risks will involve costly infrastructure investments and perhaps the retention of certain critical energy resources, but inaction will also come with a bill for high energy prices when energy supply is constrained—as well as the potential for greater risks to power system reliability and higher emissions."

Maine utility water supply inquiry

As Maine utility regulators consider how drought and other factors affect water utility supplies, staff at the Maine Public Utilities Commission have again requested comments and information on water supply emergencies and regulatory responses.  The feedback will inform a preliminary staff recommendation to be released in January 2017, which could lead to changes in how Maine regulates water utility supplies.

Drought and water shortage are affecting parts of the U.S., including much of New England.  In October, the Maine Public Utilities Commission issued a Notice of Inquiry (NOI) into water supply issues.  The Commission requested information about water supply problems, potential solutions, and development of plans to address any problems identified.  Specifically, the Commission posed 14 questions about water supply emergencies, plus 9 more questions about how the Commission should respond to water supply emergencies.  The Commission requested responses to these questions by November 4, 2016.

Some Maine water utilities responded to the Commission's water supply Notice of Inquiry, but many did not file a public response.  In a November 28, 2016 Procedural Order, Commission staff expressed a firm belief "that the more input the Commission receives from affected parties, the greater the likelihood that the final outcome in this Inquiry will meet the needs of those affected parties."  Accordingly, the procedural order invites any entity that did not initially respond to the NOI to do so by December 23, 2016.

The November 28 procedural order establishes a schedule for the remainder of the inquiry.  Staff intends to issue a Preliminary Recommendation in January, to which interested persons will be invited to respond during February, whether orally or in writing.  The schedule contemplates that staff would incorporate written and oral comments regarding the Preliminary Recommendation into a Final Recommendation in March, for presentation to the Commissioners during April.

The Commission has docketed the Maine water supply inquiry as Docket No. 2016-000233.

Drought and state water utility regulation

As drought affects parts of the U.S., some state regulators have expressed concerns over whether shortages will cause water supply emergencies for water utilities.  A recent Notice of Inquiry issued by the Maine Public Utilities Commission illustrates one approach to regulation of water supply management.

New England is abnormally dry this fall.  According to the U.S. Drought Monitor's National Drought Summary for October 11, 2016, "All areas except extreme northern Maine are now in abnormally dry or drought status. Moderate drought was expanded over eastern New York and Vermont while severe drought was expanded in southern New York and northern New Jersey."

Drought can mean water shortages, both for water utilities and for their customers.  As noted by the Maine Public Utilities Commission in an October 5, 2016 Notice of Inquiry into water supply issues, "Some are as of Maine are currently experiencing the impacts of drought. Some of Maine's water systems, which are located in areas where sources of supply are limited , are particularly challenged during dry conditions. In addition to a limited source of supply, some of these systems may also be disproportionately affected by seasonal demands, antiquated infrastructure, and/or high levels of non-revenue water."

As a result, the Commission opened an inquiry "to gather information that will allow it to identify problems which may exist, solicit input on ways to address any problems that are identified, and work collaboratively and proactively with Maine's water utilities and their customers, as well as other State agencies and interested persons and organizations, to develop a plan for addressing the problems that are identified."  The Commission also indicated interest in challenges other than drought that may significantly constrain a utility's source of supply.

The Commission divided its questions into two primary categories.  The first set seeks information to help the Commission to identify current and potential water supply problems and specific solutions to those problems.  These questions relate to recent water supply problems and their impacts, utility responses like voluntary or mandatory conservation measures, and communications with state agencies.

The Commission's second set of questions seeks input on what procedural steps the Commission should take to best address those problems.  This second set focuses on "the extent to which the Commission should be proactively involved in the development of a plan to deal with water supply emergencies and how the Commission should respond when a water supply emergency occurs."
 
The Commission requested that comments and responses be filed in Docket No. 2016-00233 by November 4, 2016.

Maine Green Power offer provider selected

Maine energy regulators have chosen a manager for the Maine Green Power program.  In an April 4, 2016 order, the Maine Public Utilities Commission selected 3Degrees Group, Inc. to manage the program.  3Degrees has operated the program since its 2013 launch, and now has the Commission's approval to run the program for another five-year term, with some changes to pricing, renewable energy certificate procurement, and risk mitigation procedures.

Maine's green power offer was established by a 2009 Maine law requiring the Commission to arrange for a green power offer -- a fully renewable competitive electricity supply option -- and to ensure its availability to residential and small commercial electricity customers.  Following a 2010 RFP, the Commission selected 3Degrees, Inc. to provide the first round green power offer.  Its program, named Maine Green Power, was officially launched in April 2013.  It featured blocks of 500 kilowatt-hours per month of renewable energy.  Its existing term of service expired on March 31, 2016.

Legislation enacted in 2015 extended the green power program's sunset date to April 1, 2021. On November 12, 2015, the Commission solicited proposals from providers to manage the program for a five-year term beginning on April 1, 2016.  According to the April 4, 2016 order selecting 3Degrees, the Commission evaluated proposals "based on cost considerations, non-cost aspects such as supplier experience, customer sign-up ease, and the potential use of renewable energy credits (RECs) from community-based renewable energy projects."

The Commission found "that the proposal submitted by 3Degrees, Inc. best suits the needs of the green power program."  According to the order, that proposal maintained the 500 kWh block structure, with a 19% increase in pricing.  3Degrees also proposed separate commercial pricing that includes a reduction in the per kWh price for higher usage.

The Commission also approved changes to the program's REC procurement and risk mitigation processes "in light of the five-year contract and the potential volatility in REC prices in future years":

Because of significant concerns about the price of Maine RECs in the next five years, particularly Maine Class I RECs, 3Degrees has proposed that it shall be required to use no less than $5.50 per REC of revenues paid by program participants for REC procurement purposes, as calculated as an average over the most recent three year period. At the proposed pricing for a residential customer of $8.95 for a 500 kWh block of green power, a customer would pay $17.90 for one REC. The 3Degrees proposal would require that no less than $5.50, or approximately 30%, of the funds paid by customers be spent directly on procuring RECs for the program.

The order also approved a risk mitigation mechanism.  If the procurement cost of Maine-based RECs exceeds $6.50 per REC on average (including Class I and Class II), 3Degrees could procure RECs from resources elsewhere in New England, or even from outside New England with Commission approval.  But because the program is promoted as Maine-based, the Commission directed 3Degrees to develop appropriate consumer education materials to explain the potential that, under certain circumstances, RECs may be sourced from outside of Maine or even the New England market.

Propane inventory in US sets new record

As the U.S. prepares for another winter, government records show stockpiles of propane have reached record levels.  What's in store for propane markets?

Propane is a hydrocarbon gas liquid used mostly for space heating and as a feedstock for other chemicals like ethylene and propylene, as well as for drying agricultural crops.   Natural gas processing plants and petroleum refineries are the two largest sources of propane. 

The U.S. Energy Information Administration has collected weekly propane inventory data for 22 years.  According to its most recent report, U.S. inventories of propane and propylene reached 97.7 million barrels as of September 11.  EIA describes this as the highest level of propane inventory on record.

What explains the buildup of propane in storage?  Record high propane inventories are partly due to seasonal dynamics in supply and demand.  Demand for propane for heating and agricultural uses is highly seasonal, while demand for propane as a chemical feedstock lacks strong seasonality.  Over recent years, propane and propylene stocks are typically drawn down during the winter heating and agricultural drying season (October to March), and then rebuild from early April through September. 

This year, EIA data shows inventories began increasing in mid-February.  EIA notes that domestic consumption is relatively flat, but found increases in propane production.  In particular, EIA's latest data shows that natural gas processing plants are producing a greater share of propane than in previous years (rising from 62% in 2008 to 76% in 2014), while propane production at refineries has remained relatively constant.

Maine PUC solicits standard offer proposals

The Maine Public Utilities Commission has issued Requests for Proposals for retail electricity standard offer service.  At stake is the right to supply default electricity service to customers of Maine's two largest utilities -- as well as the price those customers will pay for power.

Maine restructured its electricity sector in the late 1990s.  Formerly, utilities owned both power plants and the wires and other infrastructure needed to supply consumers with electricity.  But as of March 1, 2000, investor-owned transmission and distribution utilities may own and operate wires, but generally cannot have a financial interest in or otherwise control generation or generation-related assets.  Power plants became "deregulated" from the perspective of state retail rate regulation, and were sold off by the utilities.  At the same time, Maine law created a new kind of entity called a "competitive electricity provider" to perform the role of supplying electricity as a commodity.

Customers can choose among supply offers from competitive electricity providers.  Suppliers can offer specific types of product (e.g. 100% renewable power, locally-sourced) or particular contract terms (e.g. pricing schedules, payment terms).  Most large industrial energy consumers choose competitive electricity supply under this option, as do many commercial accounts and some homes.

If a customer does not choose a competitive electricity provider, that customer is placed on "standard offer service" by default.  Maine law requires the Maine Public Utilities Commission to arrange for standard offer service though a competitive bid process, and to ensure that standard offer service is available to all customers in Maine.

The pending RFPs cover retail electricity standard offer service for calendar year 2016 for all customer classes in the territories of Central Maine Power (CMP) and Emera Maine-Bangor Hydro District.  Collectively, CMP and Emera Maine deliver approximately eleven million megawatt hours annually, of which about 45% currently comes from standard offer service.

The RFPs and related materials are available on the MPUC website.  Initial proposals are due on October 6, 2015. Following negotiation of non-price terms and a submission of final bid prices, the Commission is expected to select one or more proposals,  Service terms will begin on January 1, 2016.

Report: New England electric sector will face gas supply deficit

A recently released report on the adequacy of New England’s natural gas pipeline infrastructure has identified the potential for shortfalls in gas supply to electric generators through 2020.  The November 20, 2014 report, Assessment of New England’s Natural Gas Pipeline Capacity to Satisfy Short and Near-Term Electric Generation Needs: Phase II, was prepared by consulting group ICF International for regional electric grid operator ISO New England Inc.  It found “a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.”

The Phase II report follows on a 2011/12 “Phase I” study by ICF of the adequacy of the natural gas pipeline infrastructure in New England to serve the combined needs of the core natural gas market and the regional electric generation fleet.  In the years since the Phase I study, existing natural gas and electric power systems have experienced significant changes, with further changes projected.  ISO-NE also identified the need to extend the power sector gas supply adequacy analysis beyond the peak winter and summer demand day, to examine supply adequacy throughout the peak winter demand period (December 1 through February 28).

ICF’s Phase II report presents its updated findings given these changes.  Its conclusions include:

• Despite the likelihood of 450 MMcf/d of new interstate natural gas transportation capacity being added by the end of 2016, the New England market is likely to remain supply constrained through 2020.
• Updating projections for energy efficiency has a significant impact on projected gas consumption for electric generation. The studied cases reduced projection winter peak day gas consumption by as much as 550,000 Dth by 2019/20.  However, this was not sufficient to eliminate the projected winter peak day supply deficits.
• Future imports of liquefied natural gas (LNG) into the region are likely to be well below the rated capacity of the import terminals.  Neither the Northeast Gateway nor Neptune offshore import terminal has received any shipments since 2010, and neither was projected to receive any future LNG shipments in this study.
• The Maritimes & Northeast Pipeline from Eastern Canada into New England is expected to continue to flow at full capacity on a peak winter day. Eastern Canadian gas production is expected to decline overall from 2015 through 2020, even as the Deep Panuke field ramps up its production. Historically, the Canaport LNG terminal in St. John, New Brunswick, has been managed to keep the pipeline full on peak winter days (when New England gas demand and gas prices are highest). In the future, with fewer LNG shipments coming in, the pipeline will flow full on fewer winter days, reducing natural gas supplies into New England.
• The Winter Near-Peak analysis indicates that gas supply deficits may occur not just on peak days, but also on multiple high demand days throughout the winter. Based on projected gas supplies, local distribution company (LDC) demands for retail gas supply, and electric generator gas demands, there is a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.

With the Phase II report now in ISO New England's hands, the grid operator has an updated analysis of the adequacy of the region's natural gas pipeline infrastructure to meet all the demands on it through 2020.  ISO New England describes itself as playing three critical roles: grid operation, market administration, and power system planning.  From all three of these perspectives, projections of a high probability of gas supply deficit for the electric power sector are troubling.  ICF's findings thus may shape how ISO New England -- or state and federal regulators -- reforms the New England gas and electric markets.

US energy consumers paid $14 billion more last winter

U.S. consumers paid $14 billion more for their energy needs during the winter of 2013-2014 compared to the previous winter, according to a report by the U.S. Energy Information Administration.

The cost of energy affects people and businesses across the country.  Consumers are affected by both the price they pay per unit of electricity or fuel for transportation and heating and the volume of each energy commodity they demand.  In much of the U.S., demand for energy increases during winter months.  The winter season often sees prices increase as well, as more expensive supply is needed to meet consumer demand.

The winter of 2013-2014 was no exception, according to the EIA's data.  U.S. consumers spent $14 billion more for energy during the fourth quarter of 2013 and first quarter of 2014 compared to the previous winter.  This amounts to an increase of 4.4%, or a 0.1% increase when measured as a share of disposable income.

The biggest drivers of the increase in consumer energy costs were higher expenditures for electricity, natural gas, heating oil and propane.  Electricity expenditures increased $7.9 billion, or 10%, last winter compared with the previous winter.  Much of the increased cost of electricity came as a result of increased costs for natural gas, a key fuel used for electric power generation.  Constraints on interstate natural gas pipelines drive fuel prices up as demand increases.  Throughout much of the northeast region, interstate natural gas pipelines reach their maximum flow rates on an increasing number of winter days.  When the pipelines begin to fill, the price of natural gas delivered into the constrained region increases.  Ultimately, when the pipelines have reached their maximum capacity, no more natural gas can be bought at any price.

The price of natural gas also affects consumers directly, as consumers also rely upon natural gas for space heating and applications like drying.  EIA's data show that consumer expenditures for natural gas increased by $5.8 billion, or 16%, last winter compared with the previous winter.

Expenditures for the other major heating fuels -- oil and propane -- also increased by $6.0 billion, or 27%, over the previous winter.  As EIA notes, heating oil and propane are used predominantly for space heating and are used to heat a relatively small number of homes, but their use is concentrated in the Northeast -- the area of the country that experienced the coldest weather this winter.  Propane consumers experienced not only price spikes but even shortages during the coldest parts of the season.

As costly as the past winter was, the increase in consumer energy costs would have been even higher if transportation-related costs had not decreased significantly.  In fact, transportation accounts for the largest single share of U.S. consumers' energy budget -- often over two-thirds of energy expenditures during the summer driving season, and over half of energy expenditures even in the winter.  But transportation fuel expenses decreased by $5.8 billion, or 3%, last winter compared with the previous winter.  EIA cites reductions in demand for gasoline due to winter storms that reduced driving.

Weather is a significant factor affecting winter energy costs -- but policies and infrastructure also play major roles in shaping consumers' energy expenditures.  What will next winter bring?

How New England plans to keep the lights on this winter

Concerns over the reliability of New England's electricity grid this coming winter have led the regional grid operator to develop a new program designed to ensure sufficient energy is available. While natural gas remains the dominant cost-effective fuel for electric generation in New England, grid operator ISO New England expressed concern over its ability to ensure a reliable supply of electricity in the event of a natural gas shortage or supply disruption. As a result, the grid operator launched a so-called Winter Reliability Program to compensate oil-fired generators, dual-fuel generators, and demand response resources for their promise to stand ready to serve if needed.  Is the program necessary?  If so, will it prove sufficient to protect consumers against power outages and high prices?

ISO New England's Winter Reliability Program plan was designed to address the reliability risks arising from constraints on the interstate pipeline system's ability to meet demands for natural gas deliveries into New England, increased reliance on natural gas-fired generation, and generating resource performance during periods of stressed system conditions.  While regional stakeholders are developing a longer-term fix for these risks, last winter highlighted the urgency of the problem, as natural gas pipelines supplying fuel to New England reached full capacity through the winter season, leaving natural gas more expensive and less available than it should be.

As a short-term solution, through its Winter Reliability Program, ISO New England will procure up to 2.4 million megawatt-hours of energy for the coming winter, from a combination of oil-fired generators, dual-fuel generators, and demand response assets.  In exchange for their commitment to provide power when called upon, the selected generators and demand response assets will receive payments regardless of whether they are actually needed this winter.

This program was conditionally accepted by the Federal Energy Regulatory Commission last month, after which the grid operator held its competitive bidding process. When the bidding settled, ISO New England had failed to procure commitments to provide as much energy as it had sought.  According to a FERC order accepting the bid results, market participants submitted bids totaling 2.29 million MWh, or 96 percent of the target, at a total offer price of $114.3 million.  ISO New England proposed to trim the offered supply farther, accepting bids from 20 participants for just 1.995 million MWh, or 83.1 percent of the target, for a total price of $78.8 million.

How did ISO New England reach this result?  According to the grid operator's filing to the FERC, the selected bids are all less than $31 per MWh-month.  ISO New England says that beyond this point, the supply curve became steeper, and the grid operator wanted to balance fuel security for the region against the costs to consumers.  But as the FERC found, ISO New England did not adequately explain its selection process, nor did it sufficiently describe why it cut off supply bids at $31 per MWh-month.  As a result, the FERC directed the grid operator to submit a compliance filing within 15 days describing its process in more detail.

Once ISO New England submits its compliance filing, we will have better insight into the selection process.  Further questions, such as whether the program will prove necessary or effective, cannot be answered until the winter season hits New England.  Will ISO New England's Winter Reliability Program yield consumers value in excess of its $78.8 million cost?

Maine standard offer prices jump up 23%

The upward trend in wholesale natural gas and electricity prices in New England will begin to hit retail consumers later this summer, based on the bids accepted today by the Maine Public Utilities Commission for standard offer electricity service.

Following Maine’s deregulation of the electric power industry, transmission and distribution utilities no longer sell electricity but merely provide wires enabling the delivery of power. For their energy needs, customers may choose among licensed competitive electricity providers, or may receive so-called “standard offer service” by default. Most residential consumers receive standard offer service, while more than half of the load of medium and large commercial and industrial customers is served by customer-selected competitive providers.

The providers of standard offer service, and the prices customers pay for standard offer service, are selected by the Maine Public Utilities Commission through a competitive process. In deliberations this afternoon, the Commission established new prices for standard offer electricity supply service for medium commercial and industrial customers of Maine’s two largest utilities, Central Maine Power Co. and Bangor Hydro Electric Co. Over a six-month term starting on September 1, 2013, Central Maine Power’s medium commercial and industrial customers taking standard offer service will pay an average price of 7.5 cents/kWh. Bangor Hydro customers will pay 7.45 cents/kWh. These new prices are over 23% higher than current standard offer prices for these customers, and are between 17% and 19% higher compared to last year’s standard offer pricing.

Why have these prices gone up? One explanation is that suppliers are pricing the recent upward trend in regional wholesale natural gas and electricity prices into their retail bids. Wholesale electricity pricing in New England is generally set by the price of natural gas. Despite the availability of low-cost natural gas throughout most of the country, peak demands for natural gas in New England for heating and for electric power generation exceed the capability of the natural gas pipeline network to deliver gas into the region. As a result, the wholesale price of natural gas – and electricity – spikes as demand for gas increases.  Based on last winter's experience with this phenomenon, retail electricity suppliers are expecting similar high wholesale prices this winter, and are increasing their retail rate bids accordingly.

One solution that could keep downward pressure on the cost of natural gas and electricity is expanded pipeline infrastructure to enable a balance between supply and demand for natural gas deliveries into New England. New England states are working to promote this solution, which could save consumers over $1 billion per year. Until then, the likelihood is for continued upward pressure on wholesale electricity prices, and corresponding upward jumps in the retail price consumers pay for electricity as evidenced by the new standard offer prices.

Grid operator expects sufficient electricity this summer

Regional electricity grid operator ISO New England, Inc. issued its 2013 summer outlook on April 29.  In that report, New England regional transmission organization found that regional electricity supplies during the upcoming summer are expected to be sufficient to meet consumer demand under normal weather conditions.  But if any number of contingencies occur, such as a heat wave, the grid could be seriously strained.

ISO New England noted that under normal conditions, there should be enough electricity this summer.  But it identified a series of risk factors could tip the balance of supply and demand for electricity, including extreme summer weather conditions or unexpected resource outages.  These factors could create "operational challenges", meaning a hard time finding enough electricity to meet peak demand.  New England may be forced to resort to  importing emergency power from neighboring regions, and asking businesses and people to voluntarily conserve energy.

The report's base assumption is for "normal" summer weather conditions of about 90 degrees in key southern New England cities.  Under these conditions, ISO New England forecasts electricity demand could reach 26,690 megawatts (MW).   If an extended heat wave pushes temperatures to 95, demand could rise to 28,985 MW.  Last summer’s load peaked July 17 at 25,880 MW, about 3% smaller than the base amount forecast for summer 2013.  New England set its record for peak demand on August 2, 2006, when demand reached 28,130 MW.

On the supply side, ISO New England identified several risks that could lead to unexpected shortages of electricity.   First, most natural gas pipeline maintenance in the region is scheduled for the summer months.  Maintenance activities could affect natural gas supplies to some power plants. On this point, the grid operator said it was coordinating with the pipeline companies to ensure that the supply is adequate for power generation during the maintenance season.

Second, liquefied natural gas (LNG) is in high global demand.  Current LNG prices are roughly three times higher in Europe and Japan than in the United States.  This mean LNG deliveries into New England might be reduced this summer.  At times, New England electric generation relies on LNG, which could also affect power plant operations.

Overall, ISO New England reported that it expects electricity supplies to be sufficient to meet consumer demand under normal weather conditions this summer.  If shortages occur, they will likely affect both the reliability of the grid and the wholesale price of power.  The winter season is likely to be worse, as regional demand for natural gas for heating increases during the winter, placing a tighter squeeze on the amount and price of gas available for electric generation.  The grid operator's prediction will be put to the test in the coming months.

Some Maine electricity prices fall

According to the Maine Public Utilities Commission, the price of electricity is falling for some customers. The Maine PUC recently set prices for standard offer electricity service for large commercial and industrial customers for next month. These prices - 3.2 cents/kWh for Central Maine Power customers and 3.1 cents/kWh for Bangor Hydro-Electric customers - are 10% lower than prices in March and 25% to 35% lower than prices one year ago.  Observers point to even lower wholesale power prices, driven largely by the availability of inexpensive natural gas.

In the late 1990s, Maine restructured its electricity market into two components: supply and delivery. Previously, Maine utilities operated both facilities for generating electricity (generation) and for delivering it to consumers (transmission and distribution). Today, thanks to the deregulation of generation and restructuring of the market, these functions are separate. In today's Maine marketplace, energy supply refers to buying the electricity itself from a competitive wholesale market, while delivery is the service provided by transmission and distribution utilities in delivering the energy to consumers.

Maine consumers are free to select a competitive electricity provider for their energy supply. As an alternative, customers can choose not to choose, instead automatically participating in a utility-wide pool of "default service" or "standard offer" electricity purchases. 

Maine recently revised the structure of standard offer service for large commercial and industrial customers.  Standard offer customers in these classes now pay a 2-part price for their energy supply: an energy charge indexed to wholesale power market prices, plus a capacity charge based on each customer’s peak usage.  On top of these standard offer charges, customers also pay their local utility to deliver the power.

Many larger consumers have found that they are able to procure electricity at a lower cost than the standard offer, either through a competitive supplier or by participating in the wholesale market directly. For others, the standard offer provides some certainty and medium-term price stability for energy purchases, although standard offer prices change monthly and can be more volatile than some competitive alternatives.

June 13, 2011 - RGGI carbon auction results

The latest carbon auction results from the RGGI program show a market in uncertainty.

The "Old Woolen Mill" on the Great Works River in North Berwick, Maine.

The Regional Greenhouse Gas Initiative (RGGI) is the first market-based greenhouse gas regulatory program in the United States.  RGGI represents a cooperative effort by Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont.  These ten states agreed to cap and reduce their electrical energy sector's greenhouse gas emissions by 10% by 2018.

While each state's legislature implemented its own version of the compact, the overall structure is that carbon allowances are auctioned off to the power sector.  Proceeds from these auctions are invested in energy efficiency, renewable energy, and other clean energy technologies.  The program has been a success in creating jobs, reducing greenhouse gas emissions from the power sector, and funding high-yield energy efficiency projects at businesses.

RGGI just held its twelfth auction.  (You can read the market monitor's report, a 10-page PDF, here.)  Altogether, the auction raised $25.5 million.  Each participating state's energy programs get a share in those proceeds based on how the underlying carbon allowances were allocated; for Maine, the twelfth auction yielded just under $770,000.  Since 2007, Maine has received $26 million through the program, which has been invested in energy efficiency through the Efficiency Maine Trust.

Interestingly, only 30 percent of the current-period carbon allowances available in the auction actually changed hands.  This low demand for allowances is striking, particularly since the price was as low as it could be: the auction floor price of $1.89 per short ton of CO2.  This apparent oversupply has emerged as the RGGI market matured; in the initial auction, the bid demand was four times larger than the supply.  While supply first outpaced demand for the tenth auction, held in December 2010, the 30% figure represents a new low for auction demand.

RGGI's thirteenth auction is scheduled for September 7, 2011.