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.
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
FERC Order No. 784 boosts energy storage
Wednesday, July 24, 2013
Energy storage - the ability to store electricity and deliver it to the grid as needed - has the potential to create great value for society. New technologies, ranging from batteries to mechanical flywheels, are expanding options for energy storage. Now, a federal rule issued last week known as Order No. 784 significantly expands opportunities for energy storage providers to capitalize on these advances.
Traditionally, electricity has been difficult to store. While society has been able to generate electricity for over a century, technologies to store that electricity once it has been generated have been elusive. As a result, electric grid operators have needed to balance the supply and demand for electricity in real-time, leading to costly inefficiencies like the continual need to ramp generators up and down. To keep the grid balanced, grid operators rely on so-called "ancillary services" like regulation and frequency response made possible by fine-tuning generators' output -- or now by energy storage technologies.
Despite recent federal rulings like the Federal Energy Regulatory Commission's Order No. 755 enabling enhanced compensation for energy storage, the market for energy storage has been restricted by regulation. Until last week, the Federal Energy Regulatory Commission restricted third parties from selling ancillary services at market-based rates to public utility transmission providers under a 1999 ruling known as the Avista order. Under Avista, transmission customers had two choices for how to procure their share of the grid's ancillary services. First, customers could purchase ancillary services from their local public utility. Second, customers could self-supply regulation and frequency response services - but could only do so from resources deemed comparable to those used by their public utility. This restriction stripped away the benefit of self-supplying ancillary services because customers couldn't tailor their purchase of regulation and frequency response services to their own needs, but rather had to buy services based on their transmission provider's overall resource mix. For example, customers were powerless to choose resources that could respond more quickly or more accurately than those used by their utility, meaning customers faced the risk of buying too much - or too little - ancillary services.
Order No. 784 significantly reforms the Commission's ancillary service regulations. By November, public utilities must take into account the speed and accuracy of regulation resources, which opens the door for greater efficiency in transmission customers' purchase of regulation resources. For example, Order No. 784 allows customers to save money by buying a smaller amount of faster or more accurate energy storage resources.
This flexibility creates a premium value for providers of these fast or accurate energy storage solutions. Order No. 784 also eases the barriers for third-party entry into ancillary service markets, and revises accounting and reporting requirements to improve market transparency and better account for public utilities' use of energy storage devices.
Order No. 784 creates significant opportunities for utility customers, as it opens the door for lower-cost and more precise ancillary services. The order also creates opportunities for innovative companies developing and implementing energy storage technologies like batteries, compressed air, and flywheels, as Order No. 784 both increases consumer demand for these technologies and reduces developers' barriers to entry into the markets.
For more information about Order No. 784 and the opportunities it creates, contact Todd Griset at Preti Flaherty at 207-623-5300.
Traditionally, electricity has been difficult to store. While society has been able to generate electricity for over a century, technologies to store that electricity once it has been generated have been elusive. As a result, electric grid operators have needed to balance the supply and demand for electricity in real-time, leading to costly inefficiencies like the continual need to ramp generators up and down. To keep the grid balanced, grid operators rely on so-called "ancillary services" like regulation and frequency response made possible by fine-tuning generators' output -- or now by energy storage technologies.
Despite recent federal rulings like the Federal Energy Regulatory Commission's Order No. 755 enabling enhanced compensation for energy storage, the market for energy storage has been restricted by regulation. Until last week, the Federal Energy Regulatory Commission restricted third parties from selling ancillary services at market-based rates to public utility transmission providers under a 1999 ruling known as the Avista order. Under Avista, transmission customers had two choices for how to procure their share of the grid's ancillary services. First, customers could purchase ancillary services from their local public utility. Second, customers could self-supply regulation and frequency response services - but could only do so from resources deemed comparable to those used by their public utility. This restriction stripped away the benefit of self-supplying ancillary services because customers couldn't tailor their purchase of regulation and frequency response services to their own needs, but rather had to buy services based on their transmission provider's overall resource mix. For example, customers were powerless to choose resources that could respond more quickly or more accurately than those used by their utility, meaning customers faced the risk of buying too much - or too little - ancillary services.
Order No. 784 significantly reforms the Commission's ancillary service regulations. By November, public utilities must take into account the speed and accuracy of regulation resources, which opens the door for greater efficiency in transmission customers' purchase of regulation resources. For example, Order No. 784 allows customers to save money by buying a smaller amount of faster or more accurate energy storage resources.
This flexibility creates a premium value for providers of these fast or accurate energy storage solutions. Order No. 784 also eases the barriers for third-party entry into ancillary service markets, and revises accounting and reporting requirements to improve market transparency and better account for public utilities' use of energy storage devices.
Order No. 784 creates significant opportunities for utility customers, as it opens the door for lower-cost and more precise ancillary services. The order also creates opportunities for innovative companies developing and implementing energy storage technologies like batteries, compressed air, and flywheels, as Order No. 784 both increases consumer demand for these technologies and reduces developers' barriers to entry into the markets.
For more information about Order No. 784 and the opportunities it creates, contact Todd Griset at Preti Flaherty at 207-623-5300.
Report: climate change poses risks to US energy sector
Thursday, July 11, 2013
Climate change poses significant risks to U.S. energy infrastructure, and the reliability and cost of the services it enables, according to a report released yesterday by the U.S. Department of Energy.
The report - U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather Report (4.2MB PDF) was developed as part of the Obama Administration’s efforts to support national climate change adaptation planning and to advance the U.S. Department of Energy’s goal of promoting energy security. These efforts are embodied by the Interagency Climate Change Adaptation Task Force and Strategic Sustainability Planning process established under Executive Order 13514.
The report is predicated on the findings that the U.S. climate is changing, and that these changes impact energy resources and infrastructure. As the report states, "Climatic conditions are already affecting energy production and delivery in the United States, causing supply disruptions of varying lengths and magnitude and affecting infrastructure and operations dependent upon energy supply." The report provides over 30 recent examples of energy infrastructure adversely impacted by climate change-related events such as power plant outages due to high temperatures or low water availability, storm damage to transmission lines, oil wells, pipelines and generators, and flooding-related disruption of fuel transportation systems.
Building on these findings, the report identifies a broad set of risks posed by climate trends, including increasing temperatures, decreasing water availability, and increasing storms, sea level rise, and flooding, as well as the current and potential future impacts of these climate trends on the U.S. energy sector. According to the report, each of these trends will independently, and in some cases in combination, affect the ability of the United States to produce and transmit electricity from fossil, nuclear, and existing and emerging renewable energy sources. These changes are also projected to affect the nation’s demand for energy and its ability to access, produce, and distribute oil and natural gas.
In particular, significant risks identified include:
The report - U.S. Energy Sector Vulnerabilities to Climate Change and Extreme Weather Report (4.2MB PDF) was developed as part of the Obama Administration’s efforts to support national climate change adaptation planning and to advance the U.S. Department of Energy’s goal of promoting energy security. These efforts are embodied by the Interagency Climate Change Adaptation Task Force and Strategic Sustainability Planning process established under Executive Order 13514.
The report is predicated on the findings that the U.S. climate is changing, and that these changes impact energy resources and infrastructure. As the report states, "Climatic conditions are already affecting energy production and delivery in the United States, causing supply disruptions of varying lengths and magnitude and affecting infrastructure and operations dependent upon energy supply." The report provides over 30 recent examples of energy infrastructure adversely impacted by climate change-related events such as power plant outages due to high temperatures or low water availability, storm damage to transmission lines, oil wells, pipelines and generators, and flooding-related disruption of fuel transportation systems.
Building on these findings, the report identifies a broad set of risks posed by climate trends, including increasing temperatures, decreasing water availability, and increasing storms, sea level rise, and flooding, as well as the current and potential future impacts of these climate trends on the U.S. energy sector. According to the report, each of these trends will independently, and in some cases in combination, affect the ability of the United States to produce and transmit electricity from fossil, nuclear, and existing and emerging renewable energy sources. These changes are also projected to affect the nation’s demand for energy and its ability to access, produce, and distribute oil and natural gas.
In particular, significant risks identified include:
- Thermoelectric power generation facilities are at risk from decreasing water availability and increasing ambient air and water temperatures, which reduce the efficiency of cooling, increase the likelihood of exceeding water thermal intake or effluent limits that protect local ecology, and increase the risk of partial or full shutdowns of generation facilities
- Energy infrastructure located along the coast is at risk from sea level rise, increasing intensity of storms, and higher storm surge and flooding, potentially disrupting oil and gas production, refining, and distribution, as well as electricity generation and distribution
- Oil and gas production, including unconventional oil and gas production (which constitutes an expanding share of the nation’s energy supply) is vulnerable to decreasing water availability given the volumes of water required for enhanced oil recovery, hydraulic fracturing, and refining
- Renewable energy resources, particularly hydropower, bioenergy, and concentrating solar power can be affected by changing precipitation patterns, increasing frequency and intensity of droughts, and increasing temperatures
- Electricity transmission and distribution systems carry less current and operate less efficiently when ambient air temperatures are higher, and they may face increasing risks of physical damage from more intense and frequent storm events or wildfires
- Fuel transport by rail and barge is susceptible to increased interruption and delay during more frequent periods of drought and flooding that affect water levels in rivers and ports
- Onshore oil and gas operations in Arctic Alaska are vulnerable to thawing permafrost, which may cause damage to existing infrastructure and restrict seasonal access, while offshore operations could benefit from a longer sea ice-free season
- Increasing temperatures will likely increase electricity demand for cooling and decrease fuel oil and natural gas demand for heating
Tackling New England natural gas pipeline constraints
Wednesday, July 10, 2013
Natural gas offers consumers a relatively low-cost energy source with fewer environmental impacts than coal or oil. Throughout most of the United States, natural gas is displacing other fossil fuels in electric power generation, heating, and transportation. But as a recent federal report found, inadequate pipeline infrastructure into New England is keeping prices for natural gas and electricity in the Northeast higher than in other regions.
In its 2012 State of the Markets report, the Federal Energy Regulatory Commission described how the availability of low-cost natural gas drove electricity prices downward last year. However, as power plants, businesses, and homes convert to natural gas for their energy needs, growing competition between heating and electric load for a limited natural gas supply drives prices of both gas and electricity upward during the winter season.
New England's demand for natural gas peaks in the winter, due primarily to heating demand from the residential and commercial sectors. As electric generators have increasingly turned to natural gas as the fuel of choice, total demand for gas has increased correspondingly. In recent years, to meet peak demands for natural gas, New England has relied on imports of liquefied natural gas (LNG), as well as natural gas produced from Canada's offshore Sable Island field. But last year, low domestic natural gas prices led to low imports of LNG and Canadian natural gas. LNG imports hit their lowest level since 2002. Sendout from the with Canaport LNG facility in St. John, New Brunswick, was drastically reduced, as LNG shippers chose to send their cargoes to higher-priced markets in Europe and Asia. As FERC found:
Unless LNG imports once again become economic, or domestic pipeline constraints are relieved, this situation is likely to repeat itself in New England next winter. As consumers find wider uses for natural gas -- from converting vehicles and the transportation sector to compressed natural gas, to increased access to natural gas for home heating -- the number of days when demand reaches pipeline limits will likely grow. This reality has led states like Maine to stimulate the development of new pipeline capacity by authorizing its Public Utilities Commission to enter into contracts for natural gas capacity. While it may be several years until the constraints can be relieved, other states are likely to follow Maine in addressing the problem.
In its 2012 State of the Markets report, the Federal Energy Regulatory Commission described how the availability of low-cost natural gas drove electricity prices downward last year. However, as power plants, businesses, and homes convert to natural gas for their energy needs, growing competition between heating and electric load for a limited natural gas supply drives prices of both gas and electricity upward during the winter season.
New England's demand for natural gas peaks in the winter, due primarily to heating demand from the residential and commercial sectors. As electric generators have increasingly turned to natural gas as the fuel of choice, total demand for gas has increased correspondingly. In recent years, to meet peak demands for natural gas, New England has relied on imports of liquefied natural gas (LNG), as well as natural gas produced from Canada's offshore Sable Island field. But last year, low domestic natural gas prices led to low imports of LNG and Canadian natural gas. LNG imports hit their lowest level since 2002. Sendout from the with Canaport LNG facility in St. John, New Brunswick, was drastically reduced, as LNG shippers chose to send their cargoes to higher-priced markets in Europe and Asia. As FERC found:
Lack of LNG and natural gas from Canada exacerbated pipeline constraints into New England from the southern supply corridor, including Marcellus Shale natural gas production, as New England relied more heavily on these pipelines for supply. This led to concerns that extreme cold weather could result in some service interruptions, particularly to power generators that generally rely on interruptible pipeline capacity to meet their fuel needs.In particular, during cold snaps, demand from power plants coincides with peak residential and commercial natural gas demand. Despite an unusually warm winter that suppressed residential and commercial load during the first quarter of 2012, demand reached pipeline capacity for part of the winter. As a result, last winter New England consumers paid over a billion dollars more for natural gas and electricity than they would have if adequate pipeline capacity existed.
Unless LNG imports once again become economic, or domestic pipeline constraints are relieved, this situation is likely to repeat itself in New England next winter. As consumers find wider uses for natural gas -- from converting vehicles and the transportation sector to compressed natural gas, to increased access to natural gas for home heating -- the number of days when demand reaches pipeline limits will likely grow. This reality has led states like Maine to stimulate the development of new pipeline capacity by authorizing its Public Utilities Commission to enter into contracts for natural gas capacity. While it may be several years until the constraints can be relieved, other states are likely to follow Maine in addressing the problem.
FERC reports on 2012 electricity, natural gas markets
Tuesday, July 9, 2013
The Federal Energy Regulatory Commission has released its 2012 State of the Markets Report. The 77-page document reviews developments and trends in U.S. electricity and natural gas markets. Trends highlighted in this year's report include the replacement of coal for electric power generation with natural gas, decreased prices for natural gas and electricity, and reduced demand for electricity.
The report's findings include:
The report's findings include:
- Record natural gas pricing led to lower natural gas prices. In 2012, driven by the increase in shale gas production, domestic production of natural gas reached a new record. As a result, natural gas prices reached 10-year lows throughout most the nation. For example, the spot price at Louisiana’s Henry Hub averaged $2.74/MMBtu for 2012, a 31 percent decrease from 2011.
- Electric generators relied on natural gas instead of coal. As a result of the low natural gas prices, combined with tighter environmental regulations, natural gas's share of electricity production rose to 31 percent in 2012. Meanwhile coal-fired power generation fell to its lowest level in 30 years -- just 39 percent of total generation.
- Electricity demand fell. The nation consumed 1.7 percent less electricity in 2012 than 2011. This reduction amounted to 62.9 TWh in 2012. The report attributes the decrease in demand to three primary factors: a decrease in residential demand, lack of demand growth in the commercial and industrial sectors, and increased energy efficiency.
- Electricity prices declined due to lower-cost natural gas and reduced demand. Because natural gas typically represents the marginal fuel in electric generation, reducing the price of natural gas usually reduces the wholesale price in electricity markets. Generally speaking, Eastern prices were between 1 percent and 31 percent lower than in 2011 while Western prices fell between 6 percent and 23 percent. Likewise, reductions in the demand for electricity due to a relatively warm winter, economic trends and increased energy efficiency contributed to lower electricity prices in 2012.
UK opens world's largest offshore wind farm
Monday, July 8, 2013
The United Kingdom has officially opened the London Array, the world's largest offshore wind project.
Built by a consortium of developers including DONG Energy, utility E.ON, and Masdar, the $2.3 billion project consists of 175 Siemens 3.6-megawatt turbines with a nameplate capacity of 630 megawatts. Each turbine sports three blades with an overall diameter of 117 meters. The project is located about 20 kilometers off London.
The project is owned by its lead developers. DONG Energy, Denmark's largest energy company, owns 50%. E.ON, parent of the world's largest investor-owned electric utility, owns 30%. Masdar, Abu Dhabi's renewable energy company, has a 20% stake in the project.
The addition of the London Array brings the United Kingdom to about 3.3 gigawatts of installed offshore wind capacity.
Built by a consortium of developers including DONG Energy, utility E.ON, and Masdar, the $2.3 billion project consists of 175 Siemens 3.6-megawatt turbines with a nameplate capacity of 630 megawatts. Each turbine sports three blades with an overall diameter of 117 meters. The project is located about 20 kilometers off London.
The project is owned by its lead developers. DONG Energy, Denmark's largest energy company, owns 50%. E.ON, parent of the world's largest investor-owned electric utility, owns 30%. Masdar, Abu Dhabi's renewable energy company, has a 20% stake in the project.
The addition of the London Array brings the United Kingdom to about 3.3 gigawatts of installed offshore wind capacity.
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