The municipal utility serving the town that hosts the headquarters for the operator of the regional electric grid has informed its customers that the utility “is unable to accommodate new natural gas service requests due to the lack of natural gas availability in the region.” Holyoke Gas & Electric adds, “Recent proposals that would increase natural gas capacity in the region have been met with opposition, and the current pipeline constraints are causing significant adverse environmental and economic impacts on the region's ratepayers."
Holyoke Gas & Electric is a consumer-owned municipal utility established in 1902 through the purchase
of a gas and electric plant from the Holyoke Water Power Company. According to the utility, the
town saw ownership of a municipal utility "as a way to
stabilize rates and keep local control over their energy services." As a municipal utility, Holyoke Gas & Electric is operated as a not-for-profit concern, and is owned by the community it serves. The utility cites public power advantages from this structure including operating in the local public interest, with local control over rates and services, local ownership, and reliance on local employees. In 1999, the utility acquired the Holyoke Dam, the city's canal system, and the remainder of the Holyoke Water Power Company's assets. The utility touts its ability to produce over 65% of its electricity needs from these renewable hydropower resources and cites "some of the lowest utility rates in New England."
Holyoke's Gas Division provides natural gas service through about 9,900 meters in Holyoke and Southampton. But on January 28, 2019, the utility gave its customers notice that it had placed a moratorium on most new natural gas service installations. According to that notice, the utility's natural gas customers are served by an interstate pipeline "which has become severely constrained due to a dramatic increase in demand over the last two decades," with "no corresponding increase in pipeline capacity to deliver additional supply to the region." As a result of significant growth in demand for natural gas by Holyoke's customers, HG&E said it is "forced to impose a moratorium on new natural gas connections until the capacity issue is addressed."
The utility further explained, "While inexpensive natural gas has never been more plentiful in the United States, there is insufficient pipeline capacity in our region to deliver additional load. Recent proposals that would increase natural gas capacity in the region have been met with opposition, and the current pipeline constraints are causing significant adverse environmental and economic impacts on the region's ratepayers." In its notice, the utility noted that due to the lack of natural gas during peak demand periods, "more electric generators are forced to switch to oil, while coal generators are called upon to operate, causing significant spikes in greenhouse gas emissions." Regional electric grid operator ISO New England, which is headquartered in Holyoke, reported that during a 15-day cold spell in January 2018, over two million barrels of oil were burned to generate electricity due to the lack of natural gas, more than the total amount of oil burned in 2017.
Beyond increased emissions, the utility also used ISO-NE data to show how "the lack of natural gas has a significant impact on energy costs throughout New England." Citing data from ISO-NE, the utility observed that during the two-week period from December 26, 2017 to January 8, 2018, electricity prices experienced an "approximately $700 million increase in energy costs for New England ratepayers compared to the prior year."
Holyoke Gas & Electric says it is working with gas utility Columbia Gas of Massachusetts to explore a solution involving system upgrades in other communities to "address local capacity issues, which will help reduce
regional carbon emissions, improve reliability, and support local
economic development." In the meantime, HG&E says its moratorium on new natural gas connections will remain in place "until the capacity issue is addressed."
Energy powers society; society's choices shape energy policy. A blog about our energy resources and the choices they present for society.
Showing posts with label oil. Show all posts
Showing posts with label oil. Show all posts
Holyoke utility imposes moratorium on new gas service, citing pipeline constraints
Friday, February 15, 2019
US EPA sets renewable fuel standard for 2019
Monday, December 10, 2018
U.S. environmental regulators have established renewable fuel standards for 2019, calling for a 3% increase in renewable fuel volumes over 2018, but have continued to waive statutory requirements targeting even larger volumes of renewable fuel.
Congress created the Renewable Fuel Standard or RFS program through the Energy Policy Act of 2005, and expanded the program through the Energy Independence and Security Act of 2007. Administered by the U.S. Environmental Protection Agency, the RFS requires a certain volume of renewable fuel to be used in transportation (motor vehicles and jets) and heating. Refiners and importers of gasoline or diesel, along with other market participants like fuel producers and exporters, track and trade renewable fuel credits called Renewable Identification Numbers or RINs.
The RFS includes four categories of renewable fuel: cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel. By statute, Congress prescribed specific volumes of these four categories of renewable fuel for each year through 2022, and required the EPA to set RFS volume requirements annually based on these statutory targets. The statute also allows the EPA Administrator to waive these volumetric requirements, based on a determination that implementation of the program is causing severe economic or environmental harm, or based on inadequate domestic supply.
On November 30, 2018, the EPA issued its final rule for the 2019 RFS program. The 2019 final rule sets the total U.S. renewable fuel volume requirements for 2019 at 19.92 billion gallons, including 4.92 billion gallons of advanced biofuel, 2.1 billion gallons of biomass-based diesel, and just 418 million gallons of cellulosic biofuel. The rule also sets a 2020 volume requirement for biomass-based diesel of 2.43 billion gallons.
The EPA noted that "the market has fallen well short of the statutory volumes for cellulosic biofuel, resulting in shortfalls in the advanced biofuel and total renewable fuel volumes." Based on this observation, EPA exercised its waiver authority to finalize the cellulosic biofuel volume requirement at the level EPA projects to be available for 2019. This is consistent with EPA's past practice, through which it has set the cellulosic biofuel requirement lower than the statutory volume for each year since 2010.
Congress created the Renewable Fuel Standard or RFS program through the Energy Policy Act of 2005, and expanded the program through the Energy Independence and Security Act of 2007. Administered by the U.S. Environmental Protection Agency, the RFS requires a certain volume of renewable fuel to be used in transportation (motor vehicles and jets) and heating. Refiners and importers of gasoline or diesel, along with other market participants like fuel producers and exporters, track and trade renewable fuel credits called Renewable Identification Numbers or RINs.
The RFS includes four categories of renewable fuel: cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel. By statute, Congress prescribed specific volumes of these four categories of renewable fuel for each year through 2022, and required the EPA to set RFS volume requirements annually based on these statutory targets. The statute also allows the EPA Administrator to waive these volumetric requirements, based on a determination that implementation of the program is causing severe economic or environmental harm, or based on inadequate domestic supply.
On November 30, 2018, the EPA issued its final rule for the 2019 RFS program. The 2019 final rule sets the total U.S. renewable fuel volume requirements for 2019 at 19.92 billion gallons, including 4.92 billion gallons of advanced biofuel, 2.1 billion gallons of biomass-based diesel, and just 418 million gallons of cellulosic biofuel. The rule also sets a 2020 volume requirement for biomass-based diesel of 2.43 billion gallons.
The EPA noted that "the market has fallen well short of the statutory volumes for cellulosic biofuel, resulting in shortfalls in the advanced biofuel and total renewable fuel volumes." Based on this observation, EPA exercised its waiver authority to finalize the cellulosic biofuel volume requirement at the level EPA projects to be available for 2019. This is consistent with EPA's past practice, through which it has set the cellulosic biofuel requirement lower than the statutory volume for each year since 2010.
NECA Fuels Conference 2018
Thursday, September 20, 2018
Northeast Energy and Commerce Association holds its 2018 Fuels Conference on September 27, 2018, in Marlborough, Massachusetts.
NECA is New England's oldest and most broadly-based, non-profit trade association serving the competitive electric power industry.
The program for NECA's 2018 Fuels Conference features diverse perspectives on fuels including natural gas (pipeline and LNG), biogas, oil, and other fuels, and in their uses such as electric power generation, heating, and transportation. Speakers will share their outlook for U.S. and New England natural gas markets, address the trend towards electrification of sectors like heating and transportation, explain the portfolio of fuels used to heat and power the region, and discuss what consumers can expect from lawmakers, regulators, and energy providers.
Registration is available through NECA's website.
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NECA is New England's oldest and most broadly-based, non-profit trade association serving the competitive electric power industry.
The program for NECA's 2018 Fuels Conference features diverse perspectives on fuels including natural gas (pipeline and LNG), biogas, oil, and other fuels, and in their uses such as electric power generation, heating, and transportation. Speakers will share their outlook for U.S. and New England natural gas markets, address the trend towards electrification of sectors like heating and transportation, explain the portfolio of fuels used to heat and power the region, and discuss what consumers can expect from lawmakers, regulators, and energy providers.
Registration is available through NECA's website.
FERC disallows MLP pipelines' recovery of income tax allowance
Wednesday, March 21, 2018
U.S. energy regulators have revised their policies, and will no longer allow master limited partnership (MLP) interstate natural gas and oil pipelines to recover an income tax allowance in their cost-of-service rates. The Federal Energy Regulatory Commission issued its Revised Policy Statement on Treatment of Income Taxes following a 2016 federal court order addressing the topic.
At issue is the Commission's policy on how MLP pipelines may set their cost-based rates. As described by the Commission, an MLP is a partnership form in which units are traded on exchanges much like corporate stock. To be treated as an MLP for Federal income tax purposes, an MLP must receive at least 90 percent of its income from certain qualifying sources, including natural gas and oil transportation.
MLP pipelines are not corporations, but are pass-through entities. This means that MLPs are not taxed at the pipeline level; instead, for tax purposes, the partnership agreement allocates to each partner a share of the partnership’s taxable income, and each partner is personally responsible for paying income taxes on the partnership’s net taxable income.
From 2005 until a 2016 court ruling, the Commission's 2005 Income Tax Policy Statement allowed all partnership entities (including MLPs) to recover an income tax allowance for the partners' tax costs, much like a corporation receives an income tax allowance for its corporate income tax costs. Alongside this income tax policy, the Commission has used a discounted cash flow (DCF) methodology to determine the rate of return regulated entities need to attract capital.
In 2008, a pipeline MLP named SFPP, L.P. filed a cost-of-service rate increase to increase the rates for a line running between California and Arizona. Shippers protested the filed rates, including the interaction between (a) the Commission’s policy permitting an income tax allowance policy for partnership business forms (such as SFPP) and (b) the Commission’s DCF methodology used to determine a cost-of-service rate of return. The Commission eventually issued orders addressing issues in the case including the income tax allowance issue, which were challenged in court.
On appeal, in 2016 the United States Court of Appeals for the District of Columbia Circuit issued a decision known as United Airlines, Inc. v. FERC, 827 F.3d 122 (2016). In that case, the D.C. Circuit held that because both the partnership income tax allowance and the DCF ROE may include investors’ tax costs, permitting both may result in a double recovery, and remanded the case back to the Commission for further action.
This week, the Commission took that further action. It issued an order in the SFPP case denying that MLP an income tax allowance. More holistically, the Commission concurrently issued a Revised Policy Statement on Treatment of Income Taxes. In the revised policy statement, the Commission found that "an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology."
At issue is the Commission's policy on how MLP pipelines may set their cost-based rates. As described by the Commission, an MLP is a partnership form in which units are traded on exchanges much like corporate stock. To be treated as an MLP for Federal income tax purposes, an MLP must receive at least 90 percent of its income from certain qualifying sources, including natural gas and oil transportation.
MLP pipelines are not corporations, but are pass-through entities. This means that MLPs are not taxed at the pipeline level; instead, for tax purposes, the partnership agreement allocates to each partner a share of the partnership’s taxable income, and each partner is personally responsible for paying income taxes on the partnership’s net taxable income.
From 2005 until a 2016 court ruling, the Commission's 2005 Income Tax Policy Statement allowed all partnership entities (including MLPs) to recover an income tax allowance for the partners' tax costs, much like a corporation receives an income tax allowance for its corporate income tax costs. Alongside this income tax policy, the Commission has used a discounted cash flow (DCF) methodology to determine the rate of return regulated entities need to attract capital.
In 2008, a pipeline MLP named SFPP, L.P. filed a cost-of-service rate increase to increase the rates for a line running between California and Arizona. Shippers protested the filed rates, including the interaction between (a) the Commission’s policy permitting an income tax allowance policy for partnership business forms (such as SFPP) and (b) the Commission’s DCF methodology used to determine a cost-of-service rate of return. The Commission eventually issued orders addressing issues in the case including the income tax allowance issue, which were challenged in court.
On appeal, in 2016 the United States Court of Appeals for the District of Columbia Circuit issued a decision known as United Airlines, Inc. v. FERC, 827 F.3d 122 (2016). In that case, the D.C. Circuit held that because both the partnership income tax allowance and the DCF ROE may include investors’ tax costs, permitting both may result in a double recovery, and remanded the case back to the Commission for further action.
This week, the Commission took that further action. It issued an order in the SFPP case denying that MLP an income tax allowance. More holistically, the Commission concurrently issued a Revised Policy Statement on Treatment of Income Taxes. In the revised policy statement, the Commission found that "an impermissible double recovery results from granting a Master Limited Partnership (MLP) pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology."
FERC acts on 2017 tax cuts
Monday, March 19, 2018
Federal utility regulators have taken a portfolio of actions in response to recent changes to U.S. tax law which reduced the tax rates applicable to many electric utilities and pipeline companies. Some rates for use of infrastructure will be reduced automatically, while regulators prompted others to explain why they should not be reduced to reflect the tax law changes. At the same time, regulators have opened an inquiry and proposed a rulemaking to address further aspects of the 2017 federal tax law change.
Late last year, Congress enacted the Tax Cuts and Jobs Act of 2017. That law amended U.S. tax law in a variety of ways. Among other things, the 2017 tax law changes reduced the federal corporate income tax rate from a maximum 35 percent to a flat 21 percent rate, effective January 1, 2018.
Many electric utilities and natural gas and oil pipeline companies stand to benefit from this tax reduction in the form of reduced income tax expense going forward, as well as a reduction in accumulated deferred income taxes on the books of rate-regulated companies. Where tax expense decreases, so does the cost of service.
Rates for use of some federally regulated energy infrastructure are set based on cost of service. On March 15, 2018, the Federal Energy Regulatory Commission took a series of actions to address the effect of the tax law changes on its regulated industries including electric transmission companies, interstate natural gas pipelines, and oil pipelines. According to the Commission, its actions “recognize the specific regulatory and operating parameters that must be addressed differently for each of the industries it regulates.”
Transmission rates for most FERC-regulated utilities automatically adjust with changes in the tax rates based on a formula whose inputs are updated annually or on some other regular cycle. For these utilities, a reduction in corporate income tax means a reduction in rates, although the ratemaking process means there can be a lag in time before rate reductions take effect.
But in some cases, utility tariffs provide for rates are either stated as a fixed number, or the formula includes a fixed tax rate. The Commission identified 48 companies whose transmission tariffs specifically reference tax rates of 35 percent. In a pair of show-cause orders issued under the Federal Power Act -- one for utilities with stated rates, and one for utilities with formula rates referencing 35 percent -- the Commission directed these companies to propose revisions to their transmission rates or show why they should not do so. It also issued two waivers allowing certain utilities mid-year rate adjustments to reflect the new tax law.
Interstate natural gas pipelines typically have stated rates for their services. These rates are approved by the Commission in a rate proceeding under Natural Gas Act sections 4 or 5 and remain in effect until changed in a subsequent section 4 or 5 proceeding. To revise its practices with respect to natural gas pipelines, the Commission issued a Notice of Proposed Rulemaking that would allow it determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction and the Commission’s recently revised policies on income tax allowance. Under the rule proposed by the Commission, interstate pipelines would need to file a one-time report called “FERC Form No. 501-G” describing the rate effect of these changes. In addition to filing the one-time report, each pipeline would have four options: a pro rata rate reduction, a rate settlement or case, an explanation why no rate change is needed, or merely filing the FERC report and letting the Commission decide if further action is required.
While cost-of-service ratemaking typically applies to public utilities and interstate natural gas pipelines, most oil pipelines set their rates using indexing. With respect to oil pipelines regulated by the FERC, the Commission said it will address tax changes in the 2020 five-year review of the oil pipeline index level.
Concurrently, the Commission opened an inquiry into the effect of the Tax Cuts and Jobs Act of 2017 on all jurisdictional rates, including whether the Commission should address certain changes relating to accumulated deferred income taxes and bonus depreciation. In a presentation to the Commission, staff described this Notice of Inquiry as "a vehicle to help the Commission build a record to determine whether additional action is needed."
In a separate policy statement and order issued on March 15, the Commission revised its policies to disallow income tax allowance cost recovery in MLP pipeline rates.
Late last year, Congress enacted the Tax Cuts and Jobs Act of 2017. That law amended U.S. tax law in a variety of ways. Among other things, the 2017 tax law changes reduced the federal corporate income tax rate from a maximum 35 percent to a flat 21 percent rate, effective January 1, 2018.
Many electric utilities and natural gas and oil pipeline companies stand to benefit from this tax reduction in the form of reduced income tax expense going forward, as well as a reduction in accumulated deferred income taxes on the books of rate-regulated companies. Where tax expense decreases, so does the cost of service.
Rates for use of some federally regulated energy infrastructure are set based on cost of service. On March 15, 2018, the Federal Energy Regulatory Commission took a series of actions to address the effect of the tax law changes on its regulated industries including electric transmission companies, interstate natural gas pipelines, and oil pipelines. According to the Commission, its actions “recognize the specific regulatory and operating parameters that must be addressed differently for each of the industries it regulates.”
Transmission rates for most FERC-regulated utilities automatically adjust with changes in the tax rates based on a formula whose inputs are updated annually or on some other regular cycle. For these utilities, a reduction in corporate income tax means a reduction in rates, although the ratemaking process means there can be a lag in time before rate reductions take effect.
But in some cases, utility tariffs provide for rates are either stated as a fixed number, or the formula includes a fixed tax rate. The Commission identified 48 companies whose transmission tariffs specifically reference tax rates of 35 percent. In a pair of show-cause orders issued under the Federal Power Act -- one for utilities with stated rates, and one for utilities with formula rates referencing 35 percent -- the Commission directed these companies to propose revisions to their transmission rates or show why they should not do so. It also issued two waivers allowing certain utilities mid-year rate adjustments to reflect the new tax law.
Interstate natural gas pipelines typically have stated rates for their services. These rates are approved by the Commission in a rate proceeding under Natural Gas Act sections 4 or 5 and remain in effect until changed in a subsequent section 4 or 5 proceeding. To revise its practices with respect to natural gas pipelines, the Commission issued a Notice of Proposed Rulemaking that would allow it determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax reduction and the Commission’s recently revised policies on income tax allowance. Under the rule proposed by the Commission, interstate pipelines would need to file a one-time report called “FERC Form No. 501-G” describing the rate effect of these changes. In addition to filing the one-time report, each pipeline would have four options: a pro rata rate reduction, a rate settlement or case, an explanation why no rate change is needed, or merely filing the FERC report and letting the Commission decide if further action is required.
While cost-of-service ratemaking typically applies to public utilities and interstate natural gas pipelines, most oil pipelines set their rates using indexing. With respect to oil pipelines regulated by the FERC, the Commission said it will address tax changes in the 2020 five-year review of the oil pipeline index level.
Concurrently, the Commission opened an inquiry into the effect of the Tax Cuts and Jobs Act of 2017 on all jurisdictional rates, including whether the Commission should address certain changes relating to accumulated deferred income taxes and bonus depreciation. In a presentation to the Commission, staff described this Notice of Inquiry as "a vehicle to help the Commission build a record to determine whether additional action is needed."
In a separate policy statement and order issued on March 15, the Commission revised its policies to disallow income tax allowance cost recovery in MLP pipeline rates.
ISO-NE 2018 Regional Electricity Outlook
Thursday, February 15, 2018
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."
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 Gov. LePage's 2018 State of the State and energy policy
Tuesday, February 13, 2018
Maine Governor Paul R. LePage delivered his final State of the State address this evening. Here's a recap of some of his remarks on energy policy in previous speeches of that sort.
Nevertheless, the Bangor Daily News reports that his remarks as delivered did address energy, calling for lower energy prices.
- In 2012, Governor LePage described Maine’s high energy costs as "one of the largest inhibitors, if not the biggest obstacle to job creation." He advocated an energy policy encompassing "all forms of energy."
- Energy did not appear in his 2013 speech, according to a transcript provided by the Portland Press Herald.
- In 2014, Governor LePage noted that "heating and electricity costs remain a major obstacle," with homeowners spending nearly double the national average on heating, and high electricity costs posting challenges to attracting business. He described efforts to expand natural gas pipeline capacity from Pennsylvania, and to connect to clean energy resources in Quebec.
- In 2015, Governor LePage used his speech to argue for lower electricity rates and home heating costs, as well as changes to Maine’s renewable energy policies.
- In 2016, Governor LePage released his speech in the form of a letter to the state legislature. As in previous speeches, his 2016 letter mentioned energy issues as a focus for -- or obstacle to -- economic development. Arguing that Maine's electricity prices are not competitive, he criticized legislative mandates supporting "long-term contracts for above-market rates." He also called for expansion of linear infrastructure like natural gas pipelines into New England and electric transmission lines to hydropower resources in Canada.
- Last year, he returned to delivering the speech to the legislature orally. His 2017 address included a section on energy matters, in which he criticized the Public Utilities Commission's decision to amend its rules governing net energy billing. He called upon lawmakers to agree to lower energy costs, to lower carbon dioxide levels in the most cost-effective manner, and to reduce our demand for oil.
Nevertheless, the Bangor Daily News reports that his remarks as delivered did address energy, calling for lower energy prices.
New England Operational Fuel-Security Analysis released
Tuesday, January 23, 2018
The risk that power plants will run out of fuel is the foremost challenge to a reliable power grid in New England, according to the region's grid operator, and the region is vulnerable to the season-long outage of any of several major energy facilities.
While the ability to count on a portfolio of power plants to generate power is considered the cornerstone of reliable electricity supply, ISO New England has noted several factors that make fuel security a growing concern for the region. These factors include the inadequacy of the region’s natural gas infrastructure to meet winter needs for both heating and power, and the retirement of many of the region’s coal, oil, and nuclear power plants due to economic and environmental pressures.
On January 17, 2018, ISO New England released its Operational Fuel-Security Analysis, a 56-page report studying the possible fuel security risks facing region's power plants under a wide range of hypothetical future scenarios. Prepared following about two years of study, the report found that maintaining the electric grid's reliability "is likely to become more challenging, especially if current power system trends continue."
The report considered a 23 possible range of possible future power resource combinations that could materialize for the winter period from December 1, 2024 through February 28, 2025, to examine whether enough fuel would be available to meet demand and to quantify the operational risks. Each scenario assumed no new natural gas pipeline capacity would be added to serve generators, but considered variation in five other key factors for power system reliability: resource retirements, LNG availability, oil tank inventories, imported electricity, and renewable resources.
The study identified six major conclusions:
While the ability to count on a portfolio of power plants to generate power is considered the cornerstone of reliable electricity supply, ISO New England has noted several factors that make fuel security a growing concern for the region. These factors include the inadequacy of the region’s natural gas infrastructure to meet winter needs for both heating and power, and the retirement of many of the region’s coal, oil, and nuclear power plants due to economic and environmental pressures.
On January 17, 2018, ISO New England released its Operational Fuel-Security Analysis, a 56-page report studying the possible fuel security risks facing region's power plants under a wide range of hypothetical future scenarios. Prepared following about two years of study, the report found that maintaining the electric grid's reliability "is likely to become more challenging, especially if current power system trends continue."
The report considered a 23 possible range of possible future power resource combinations that could materialize for the winter period from December 1, 2024 through February 28, 2025, to examine whether enough fuel would be available to meet demand and to quantify the operational risks. Each scenario assumed no new natural gas pipeline capacity would be added to serve generators, but considered variation in five other key factors for power system reliability: resource retirements, LNG availability, oil tank inventories, imported electricity, and renewable resources.
 |
| ISO-NE chart of Hours of Emergency Actions under Modeled Scenarios, Ordered Least to Most, Operational Fuel-Security Analysis (2018) |
The study identified six major conclusions:
Outages: The region is vulnerable to the season-long outage of any of several major energy facilities.
Stored fuels: Power system reliability is heavily dependent on LNG and electricity imports; more dual-fuel capability is also a key reliability factor, but permitting for construction and emissions is difficult.
Logistics: The timely availability of fuel is critical, highlighting the importance of fuel-delivery logistics.
Risk trends: All but four scenarios result in fuel shortages requiring load shedding, indicating the trends affecting New England’s power system may intensify the region’s fuel-security risk.
Renewables: More renewable resources can help lessen the region’s fuel-security risk but are likely to drive coal- and oil-fired generation retirements, requiring high LNG imports to counteract the loss of stored fuels.
Positive outcomes: Higher levels of LNG, imports, and renewables can minimize system stress and maintain reliability; to attain these higher levels, delivery assurances for LNG and electricity imports, as well as transmission expansion, will be needed.
New England's electric grid and winter 2017-18
Monday, December 11, 2017
New England's electricity grid is ready for reliable operations this winter, says the region's grid operator -- but special operating procedures might be required in the case of unexpected outages or fuel delivery constraints.
According to ISO New England Inc., the independent, not-for-profit regional transmission organization responsible for almost all of New England, supplies of electricity should be sufficient to meet regional consumer demand this winter. The grid operator projects a peak demand of 21,197 megawatts under normal winter temperatures (about 7 degrees Fahrenheit), or 21,895 megawatts of peak demand if extreme weather occurs (2 degrees F).
These projections are higher than last winter's actual peak demand (19,647 MW on December 15, 2016, during the hour from 5 to 6 p.m.), but lower than the region's all-time winter peak (22,818 MW, on January 15, 2004) or the record peak (28,180 MW on August 2, 2006). ISO-NE notes that total energy consumption and regional peak demand have remained flat in recent years "as a result of increased use of energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems."
The grid operator projects that it has commitments from enough power plants and demand-side resources to meet the forecast peak demand under both normal and extreme weather conditions. ISO-NE also points to its fifth seasonal Winter Reliability Program provides incentives for generators to stock up on oil or contract for liquefied natural gas, and also for demand-side resources committing to be available. As noted by the grid operator, the availability of generators with fuel has been a key reliability factor during recent cold winters, thanks in part to the past winter reliability programs. ISO-NE says its new capacity market performance incentive rules which take effect June 1, 2018 should eliminate the need for future special programs.
At the same time, the grid operator warns of its "continuing concern" over the availability of fuel for those power plants to generate electricity when needed. In a press release, ISO-NE noted, "The region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow." It observed that over 4,000 megawatts of natural-gas-fired generating capacity is at risk of not being able to get fuel when needed, due to natural gas pipeline constraints.
The grid operator also cites changes to the regional portfolio of generating resources, such as the May 2017 retirement of a 1,500 MW coal- and oil-fired power plant. According to ISO-NE, the Brayton Point power plant's closure "removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable." The reliability benefits of stockpiled fuel and baseload power and related proposals are currently under examination by the Federal Energy Regulatory Commission.
The grid operator listed challenges that could affect power system operations such as "if demand is higher than projected, if the region loses a large generator, electricity imports are affected, or when natural gas pipeline constraints limit the fuel available to natural-gas-fired power plants," as well as the special operating procedures it would invoke in those circumstances.
According to ISO New England Inc., the independent, not-for-profit regional transmission organization responsible for almost all of New England, supplies of electricity should be sufficient to meet regional consumer demand this winter. The grid operator projects a peak demand of 21,197 megawatts under normal winter temperatures (about 7 degrees Fahrenheit), or 21,895 megawatts of peak demand if extreme weather occurs (2 degrees F).
These projections are higher than last winter's actual peak demand (19,647 MW on December 15, 2016, during the hour from 5 to 6 p.m.), but lower than the region's all-time winter peak (22,818 MW, on January 15, 2004) or the record peak (28,180 MW on August 2, 2006). ISO-NE notes that total energy consumption and regional peak demand have remained flat in recent years "as a result of increased use of energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems."
The grid operator projects that it has commitments from enough power plants and demand-side resources to meet the forecast peak demand under both normal and extreme weather conditions. ISO-NE also points to its fifth seasonal Winter Reliability Program provides incentives for generators to stock up on oil or contract for liquefied natural gas, and also for demand-side resources committing to be available. As noted by the grid operator, the availability of generators with fuel has been a key reliability factor during recent cold winters, thanks in part to the past winter reliability programs. ISO-NE says its new capacity market performance incentive rules which take effect June 1, 2018 should eliminate the need for future special programs.
At the same time, the grid operator warns of its "continuing concern" over the availability of fuel for those power plants to generate electricity when needed. In a press release, ISO-NE noted, "The region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow." It observed that over 4,000 megawatts of natural-gas-fired generating capacity is at risk of not being able to get fuel when needed, due to natural gas pipeline constraints.
The grid operator also cites changes to the regional portfolio of generating resources, such as the May 2017 retirement of a 1,500 MW coal- and oil-fired power plant. According to ISO-NE, the Brayton Point power plant's closure "removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable." The reliability benefits of stockpiled fuel and baseload power and related proposals are currently under examination by the Federal Energy Regulatory Commission.
The grid operator listed challenges that could affect power system operations such as "if demand is higher than projected, if the region loses a large generator, electricity imports are affected, or when natural gas pipeline constraints limit the fuel available to natural-gas-fired power plants," as well as the special operating procedures it would invoke in those circumstances.
Carbon capture and sequestration for enhanced oil recovery
Wednesday, October 25, 2017
A project to capture carbon dioxide emissions from a coal-fired power plant in Texas has captured more than 1 million tons of carbon dioxide for use in enhanced oil recovery, according to the U.S. Department of Energy.
Historically, carbon dioxide resulting from the combustion of coal and other fossil fuels has been emitted directly into the atmosphere, but global concern over climate change has led to efforts to limit carbon emissions to the atmosphere. While many of these programs focus on reducing reliance on combustible fuels, carbon capture and sequestration technologies offer the potential to remove carbon dioxide from thermal plants' flue gas before it is emitted from their smokestacks. The U.S. Department of Energy runs programs designed to support the development and commercial deployment of these technologies.
The Petra Nova project uses an amine solvent-based CO2-capture technology to remove carbon dioxide from the flue gas of NRG's coal-fired W.A. Parish power plant. It is a 50/50 joint venture between NRG and JX Nippon Oil & Gas Exploration. NRG describes Petra Nova as "the world's largest post-combustion carbon capture facility installed on an existing coal-fueled power plant." The Department of Energy selected Petra Nova to receive $190 million as part of the Clean Coal Power Initiative Program.
The project uses a carbon capture process which was jointly developed by Mitsubishi Heavy Industries, Ltd. and the Kansai Electric Power Co. It was designed to capture about 90 percent of the CO2 from a 240 MW slipstream of flue gas, compressing and transporting approximately 1.4 million metric tons of CO2 per year through an 80 mile pipeline to Hilcorp's operating West Ranch oil field where it is utilized for enhanced oil recovery (EOR) -- injecting the CO2 underground to help additional oil flow to a production wellbore. According to the Department of Energy, the use of this CO2 for enhanced oil recovery has boosted the West Ranch Oil Field's oil production from 300 barrels per day to about 4,000 barrels per day.
Petra Nova began commercial operations on January 10, 2017. According to an October 23 press release, Petra Nova has now captured more than 1 million tons of CO2 for use in enhanced oil recovery. Secretary of Energy Rick Perry has said that Petra Nova's success "could become the model for future coal-fired power generation facilities," which could support CO2 pipeline infrastructure development and drive domestic enhanced oil recovery opportunities.
Historically, carbon dioxide resulting from the combustion of coal and other fossil fuels has been emitted directly into the atmosphere, but global concern over climate change has led to efforts to limit carbon emissions to the atmosphere. While many of these programs focus on reducing reliance on combustible fuels, carbon capture and sequestration technologies offer the potential to remove carbon dioxide from thermal plants' flue gas before it is emitted from their smokestacks. The U.S. Department of Energy runs programs designed to support the development and commercial deployment of these technologies.
The Petra Nova project uses an amine solvent-based CO2-capture technology to remove carbon dioxide from the flue gas of NRG's coal-fired W.A. Parish power plant. It is a 50/50 joint venture between NRG and JX Nippon Oil & Gas Exploration. NRG describes Petra Nova as "the world's largest post-combustion carbon capture facility installed on an existing coal-fueled power plant." The Department of Energy selected Petra Nova to receive $190 million as part of the Clean Coal Power Initiative Program.
The project uses a carbon capture process which was jointly developed by Mitsubishi Heavy Industries, Ltd. and the Kansai Electric Power Co. It was designed to capture about 90 percent of the CO2 from a 240 MW slipstream of flue gas, compressing and transporting approximately 1.4 million metric tons of CO2 per year through an 80 mile pipeline to Hilcorp's operating West Ranch oil field where it is utilized for enhanced oil recovery (EOR) -- injecting the CO2 underground to help additional oil flow to a production wellbore. According to the Department of Energy, the use of this CO2 for enhanced oil recovery has boosted the West Ranch Oil Field's oil production from 300 barrels per day to about 4,000 barrels per day.
Petra Nova began commercial operations on January 10, 2017. According to an October 23 press release, Petra Nova has now captured more than 1 million tons of CO2 for use in enhanced oil recovery. Secretary of Energy Rick Perry has said that Petra Nova's success "could become the model for future coal-fired power generation facilities," which could support CO2 pipeline infrastructure development and drive domestic enhanced oil recovery opportunities.
Energy East pipeline case suspended
Monday, September 11, 2017
The developed of a proposed C$15.75 billion Canadian oil pipeline has asked Canadian regulators to temporarily suspend their review of the project, following the regulator's decision to consider the project's indirect greenhouse gas emissions and other factors as part of its environmental review.
At issue are the proposed Energy East Pipeline and the related Eastern Maineline Project, proposed by affiliates of TransCanada Corp. to transport "about 1.1 million barrels of oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick" and to ensure natural gas supply to utilities in Ontario and Quebec. In 2014, the developed applied to Canada's National Energy Board for approvals required for the 4,500-kilometer project's development.
That case remains pending, but a recent decision about the scope of environmental review has prompted the developer to ask for a temporary pause of the case. On August 23, 2017, the National Energy Board released its final decision establishing a List of Issues and Environmental Assessment Factors to be considered in its review of the projects. The factors set for consideration include greenhouse gas emissions. While the Board's environmental factors typically include only direct greenhouse gas emissions -- those emitted by the project itself -- including indirect emissions -- in this case the Board decided to include indirect greenhouse gas emissions as well:
The case remains suspended until that time.
At issue are the proposed Energy East Pipeline and the related Eastern Maineline Project, proposed by affiliates of TransCanada Corp. to transport "about 1.1 million barrels of oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick" and to ensure natural gas supply to utilities in Ontario and Quebec. In 2014, the developed applied to Canada's National Energy Board for approvals required for the 4,500-kilometer project's development.
That case remains pending, but a recent decision about the scope of environmental review has prompted the developer to ask for a temporary pause of the case. On August 23, 2017, the National Energy Board released its final decision establishing a List of Issues and Environmental Assessment Factors to be considered in its review of the projects. The factors set for consideration include greenhouse gas emissions. While the Board's environmental factors typically include only direct greenhouse gas emissions -- those emitted by the project itself -- including indirect emissions -- in this case the Board decided to include indirect greenhouse gas emissions as well:
Given increasing public interest in GHG emissions, together with increasing governmental actions and commitments (including the federal government’s stated interest in assessing upstream GHG emissions associated with major pipelines), the Board is of the view that it should also consider indirect GHG emissions in its NEB Act public interest determination for each of the Projects.On September 7, the applicants filed a letter requesting a 30-day suspension of the Board's review process to give applicants time to "review the Decision, the resulting implications to the Projects, and the respective Project applications." The next day, the Board issued a ruling that it "will not issue further decisions or take further process steps relating to the review of the Projects until 8 October 2017."
The case remains suspended until that time.
US conditionally approves Arctic offshore oil exploration
Wednesday, July 19, 2017
The U.S. Bureau of Ocean Energy Management has conditionally approved an oil and gas company's plan to drill four exploration wells into the federal submerged lands of the Beaufort Sea in the U.S. Arctic.
On July 12, 2017, BOEM announced that it had conditionally approved a Beaufort Sea exploration plan (EP) it received from Eni US Operating Co. Inc. The company is a subsidiary of Italian multinational oil and gas company Eni S.p.A.
Under federal law, BOEM regulates exploration and production activities on the Outer Continental Shelf. It requires a developer to file and receive approval of an Exploration Plan or EP before most activities can begin. An EP describes all exploration activities planned by the operator for a specific lease or leases, including the timing of these activities, information concerning drilling processes, the surface location of each planned well, and actions to be taken to meet important safety and environmental standards and to protect access to subsistence resources, but it does not allow actual production of oil -- for that, an operator is required to obtain BOEM approval of a Development and Production Plan (DPP).
Eni US had applied to BOEM for approval of a plan to drill four exploration wells from its existing Spy Island Drillsite, located in Alaska state waters. The Nikaitchuq North Project's wells would run down from Spy Island, then extend below the ocean floor to federal leases on the Outer Continental Shelf. Eni proposed exploratory drilling activities commencing in December 2017, and continuing into 2019.
BOEM deemed Eni US's exploration plan application to be submitted in June 2017, triggering a 30-day review period including a site-specific Environmental Assessment of the proposed exploration activities pursuant to the National Environmental Policy Act. That NEPA process concluded with a Finding of No Significant Impact (FONSI), and on July 12 BOEM issued its conditional approval of the Exploration Plan. Conditions include a requirement that Eni procure all other appropriate permits from state and federal agencies, as well as certain mitigation measures.
In a statement announcing the conditional approval, BOEM's acting director, Walter Cruickshank, described Eni's exploration plan as "a solid, well-considered plan,” and noted the existence of "vast oil and gas resources under the Beaufort Sea.”
On July 12, 2017, BOEM announced that it had conditionally approved a Beaufort Sea exploration plan (EP) it received from Eni US Operating Co. Inc. The company is a subsidiary of Italian multinational oil and gas company Eni S.p.A.
Under federal law, BOEM regulates exploration and production activities on the Outer Continental Shelf. It requires a developer to file and receive approval of an Exploration Plan or EP before most activities can begin. An EP describes all exploration activities planned by the operator for a specific lease or leases, including the timing of these activities, information concerning drilling processes, the surface location of each planned well, and actions to be taken to meet important safety and environmental standards and to protect access to subsistence resources, but it does not allow actual production of oil -- for that, an operator is required to obtain BOEM approval of a Development and Production Plan (DPP).
Eni US had applied to BOEM for approval of a plan to drill four exploration wells from its existing Spy Island Drillsite, located in Alaska state waters. The Nikaitchuq North Project's wells would run down from Spy Island, then extend below the ocean floor to federal leases on the Outer Continental Shelf. Eni proposed exploratory drilling activities commencing in December 2017, and continuing into 2019.
BOEM deemed Eni US's exploration plan application to be submitted in June 2017, triggering a 30-day review period including a site-specific Environmental Assessment of the proposed exploration activities pursuant to the National Environmental Policy Act. That NEPA process concluded with a Finding of No Significant Impact (FONSI), and on July 12 BOEM issued its conditional approval of the Exploration Plan. Conditions include a requirement that Eni procure all other appropriate permits from state and federal agencies, as well as certain mitigation measures.
In a statement announcing the conditional approval, BOEM's acting director, Walter Cruickshank, described Eni's exploration plan as "a solid, well-considered plan,” and noted the existence of "vast oil and gas resources under the Beaufort Sea.”
Atlantic Ocean oil development in Canada, U.S.
Tuesday, June 6, 2017
Canadian oil company Husky Energy has announced a decision to develop its West White Rose Project offshore Newfoundland and Labrador. Meanwhile the U.S. National Marine Fisheries Service has proposed authorizing the take of marine mammals incidental to geophysical surveys in the Atlantic Ocean relating to hydrocarbon development.
Husky Energy is a Canada-based publicly traded energy company. It is the operator of the White Rose field, discovered in 1984 about 350 kilometres east of St. John’s, Newfoundland and Labrador, in water depths of about 120 meters. Commercial oil production from the main White Rose field began in 2005; since then, over 275 million barrels of oil has been produced. Husky holds working interests in the main field as well as satellite fields.
The oil and gas industry is the largest contributor to Newfoundland and Labrador's gross domestic production. Husky's May 28, 2017 announcement relates to its West White Rose development. Husky says it and project partners Suncor Energy and Nalcor Energy – Oil and Gas will use a fixed wellhead platform, tied back to the SeaRose floating production, storage and offloading (FPSO) vessel. According to Husky, the tie-back to the SeaRose FPSO vessel "will enable the Company to maximize resource recovery," with "incremental operating costs are expected to be less than $3 per barrel over the first 10 years." Husky expects a net project cost of $2.2 billion to first oil in 2022, and a gross peak production rate of approximately 75,000 barrels per day (bbls/day) in 2025.
Meanwhile, U.S. regulators have proposed removing one obstacle to oil and gas prospecting in the Atlantic Ocean. The U.S. National Marine Fisheries Service has published notice of five proposed authorizations for harassment or take of marine mammals incidental to geophysical surveys in the Atlantic Ocean. The federal Marine Mammal Protection Act allows the Secretary of Commerce to permit the incidental, but not intentional, harassment or taking of small numbers of marine mammals by U.S. citizens who engage in a specified activity. In 2014-2015, NMFS "received five separate requests for authorization for take of marine mammals incidental to geophysical surveys in support of hydrocarbon exploration in the Atlantic Ocean." The applicants proposed "to conduct two-dimensional (2D) marine seismic surveys using airgun arrays" within the U.S. Exclusive Economic Zone "(i.e., to 200 nautical miles (nmi)) from Delaware to approximately Cape Canaveral, Florida and corresponding with BOEM’s Mid- and South Atlantic OCS planning areas, as well as additional waters out to 350 nmi from shore."
NMFS's proposal to issue the incidental take or harassment permits now faces public comment, before a final agency decision.
Husky Energy is a Canada-based publicly traded energy company. It is the operator of the White Rose field, discovered in 1984 about 350 kilometres east of St. John’s, Newfoundland and Labrador, in water depths of about 120 meters. Commercial oil production from the main White Rose field began in 2005; since then, over 275 million barrels of oil has been produced. Husky holds working interests in the main field as well as satellite fields.
The oil and gas industry is the largest contributor to Newfoundland and Labrador's gross domestic production. Husky's May 28, 2017 announcement relates to its West White Rose development. Husky says it and project partners Suncor Energy and Nalcor Energy – Oil and Gas will use a fixed wellhead platform, tied back to the SeaRose floating production, storage and offloading (FPSO) vessel. According to Husky, the tie-back to the SeaRose FPSO vessel "will enable the Company to maximize resource recovery," with "incremental operating costs are expected to be less than $3 per barrel over the first 10 years." Husky expects a net project cost of $2.2 billion to first oil in 2022, and a gross peak production rate of approximately 75,000 barrels per day (bbls/day) in 2025.
Meanwhile, U.S. regulators have proposed removing one obstacle to oil and gas prospecting in the Atlantic Ocean. The U.S. National Marine Fisheries Service has published notice of five proposed authorizations for harassment or take of marine mammals incidental to geophysical surveys in the Atlantic Ocean. The federal Marine Mammal Protection Act allows the Secretary of Commerce to permit the incidental, but not intentional, harassment or taking of small numbers of marine mammals by U.S. citizens who engage in a specified activity. In 2014-2015, NMFS "received five separate requests for authorization for take of marine mammals incidental to geophysical surveys in support of hydrocarbon exploration in the Atlantic Ocean." The applicants proposed "to conduct two-dimensional (2D) marine seismic surveys using airgun arrays" within the U.S. Exclusive Economic Zone "(i.e., to 200 nautical miles (nmi)) from Delaware to approximately Cape Canaveral, Florida and corresponding with BOEM’s Mid- and South Atlantic OCS planning areas, as well as additional waters out to 350 nmi from shore."
NMFS's proposal to issue the incidental take or harassment permits now faces public comment, before a final agency decision.
ISO-NE winter electricity supply 2016-2017
Thursday, December 8, 2016
New England should have sufficient electricity supplies to meet consumer demand this winter, according to regional power grid operator ISO New England, Inc. But because natural gas pipeline constraints could limit electricity production, the grid operator has implemented a Winter Reliability Program to help ensure supply meets demand.
ISO-NE is the regional transmission organization responsible for most of New England's electric grid. In that role, it forecasts electricity demand, and operates markets to match up generation with demand.
On December 5, 2016, ISO-NE released a statement addressing winter 2016-2017 with respect to electricity reliability. The grid operator projects that at normal winter temperatures of about 7 degrees Fahrenheit, peak demand will reach 21,340 MW, or 22,028 MW if extreme winter weather of 2 degrees F occurs. This would be above the 2015-2016 winter peak demand of 19,545 MW (February 14, 2016, from the hour from 6 to 7 p.m.), and below the all-time regional winter peak of 22,818 MW (a cold snap on January 15, 2004).
According to the grid operator, electricity supplies should be sufficient to meet consumer demand this winter -- but natural gas pipeline constraints and other factors create risks that could affect reliability. Natural gas generated 49% of the region's electricity in 2015, and natural gas-fired power plants represent about 44% (or 14,850 megawatts) of the region's total generating capacity. But ISO-NE views about 3,450 MW of natural gas-fired generating capacity as "at risk" this winter due to the insufficiency of the region's natural gas infrastructure. Despite some new pipeline projects and the present availability of liquified natural gas (LNG), the region faces the loss of 1,500 MW of coal- and oil-fired generation this spring with the closure of the Brayton Point Power Station in Massachusetts.
ISO-NE touts its 2016-2017 Winter Reliability Program as designed to address these "multiple risks" of pipeline constraints and non-gas unit retirement. As previously approved by the Federal Energy Regulatory Commission, the program will run from December 1, 2016 to February 28, 2017, and includes an oil inventory component, an LNG component, and a demand response component.
In light of this planning, and barring "unexpected resource outages or fuel delivery constraints," ISO-NE projects New England's electricity supplies should be sufficient this winter to meet consumer demand.
ISO-NE is the regional transmission organization responsible for most of New England's electric grid. In that role, it forecasts electricity demand, and operates markets to match up generation with demand.
On December 5, 2016, ISO-NE released a statement addressing winter 2016-2017 with respect to electricity reliability. The grid operator projects that at normal winter temperatures of about 7 degrees Fahrenheit, peak demand will reach 21,340 MW, or 22,028 MW if extreme winter weather of 2 degrees F occurs. This would be above the 2015-2016 winter peak demand of 19,545 MW (February 14, 2016, from the hour from 6 to 7 p.m.), and below the all-time regional winter peak of 22,818 MW (a cold snap on January 15, 2004).
According to the grid operator, electricity supplies should be sufficient to meet consumer demand this winter -- but natural gas pipeline constraints and other factors create risks that could affect reliability. Natural gas generated 49% of the region's electricity in 2015, and natural gas-fired power plants represent about 44% (or 14,850 megawatts) of the region's total generating capacity. But ISO-NE views about 3,450 MW of natural gas-fired generating capacity as "at risk" this winter due to the insufficiency of the region's natural gas infrastructure. Despite some new pipeline projects and the present availability of liquified natural gas (LNG), the region faces the loss of 1,500 MW of coal- and oil-fired generation this spring with the closure of the Brayton Point Power Station in Massachusetts.
ISO-NE touts its 2016-2017 Winter Reliability Program as designed to address these "multiple risks" of pipeline constraints and non-gas unit retirement. As previously approved by the Federal Energy Regulatory Commission, the program will run from December 1, 2016 to February 28, 2017, and includes an oil inventory component, an LNG component, and a demand response component.
In light of this planning, and barring "unexpected resource outages or fuel delivery constraints," ISO-NE projects New England's electricity supplies should be sufficient this winter to meet consumer demand.
NPS updates oil and gas rights rules
Friday, December 2, 2016
The U.S. National Park Service has adopted a final rule updating its regulations governing the exercise of non-federal oil and gas rights. The NPS states that the rule improves its ability to protect park
resources, values, and visitors from
potential impacts associated with
nonfederal oil and gas operations
located within National Park Service
units outside Alaska.
While the NPS promulgated regulations in 1978 governing the exercise of non-federal oil and gas rights, it had not updated these rules since then. The final rule issued in November 2016 thus represents the first change in over 37 years. Its changes include a broadening of scope, to cover all non-federal oil and gas operations within the boundary of a system unit outside of Alaska.
This rule is effective December 5, 2016.
At issue are non-federal oil and gas rights within national park system units. According to the NPS, these arise where the United States does not
own the oil and gas interest, either because:
- The United States acquired the property from a grantor that did not own the oil and gas interest; or
- The United States acquired the property from a grantor that reserved the oil and gas interest from the conveyance.
- Alibates Flint Quarries National Monument, Texas (5 operations)
- Aztec Ruins National Monument, New Mexico (4 operations)
- Big Cypress National Preserve, Florida (20 operations)
- Big Thicket National Preserve, Texas (39 operations)
- Big South Fork National River and Recreation Area, Tennessee/Kentucky (152 operations)
- Cumberland Gap National Historical Park, Tennessee (2 operations)
- Cuyahoga Valley National Park, Ohio (90 operations)
- Gauley River National Recreation Area, West Virginia (28 operations)
- Lake Meredith National Recreation Area, Texas (174 operations)
- New River Gorge National River, West Virginia (1 operation)
- Obed Wild and Scenic River, Tennessee (5 operations)
- Padre Island National Seashore, Texas (14 operations)
While the NPS promulgated regulations in 1978 governing the exercise of non-federal oil and gas rights, it had not updated these rules since then. The final rule issued in November 2016 thus represents the first change in over 37 years. Its changes include a broadening of scope, to cover all non-federal oil and gas operations within the boundary of a system unit outside of Alaska.
This rule is effective December 5, 2016.
ISO-NE Winter Reliability Program 2016-2017
Thursday, September 1, 2016
As winter approaches, the operator of New England's wholesale electricity markets is preparing to run another seasonal Winter Reliability Program to address operational concerns related to fuel adequacy.
Since the winter of 2013-2014, ISO New England Inc. has operated a seasonal program to address winter fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints. After two initial program years, last fall the Federal Energy Regulatory Commission approved a three-year plan for ISO-NE's Winter Reliability Program.
That program, developed chiefly by market participant group New England Power Pool (NEPOOL), was designed to address reliability concerns through at least 2017-2018, when new “Pay-for-Performance” incentives and penalties in New England's redesigned capacity market are set to take effect. The winter reliability program encourages generators fueled by oil and liquefied natural gas (LNG) to secure fuel before the winter season begins, by compensating them for some costs related to fuel inventory that remains unused at winter's end, and includes a demand response component. According to ISO-NE, last year's participants included 77 oil-fired units, 8 LNG units, and 6 demand response assets.
The program's rules are specified in Appendix K to Section III of the ISO New England Inc. Transmission, Markets and Services Tariff. As approved by FERC, the current program retains the three core components of the 2014-2015 Winter Reliability Program: (1) compensation for certain oil inventory that remains in New England following the end of each winter period; (2) end-of-season compensation for LNG contract volumes kept available for winter use but not actually called upon to produce energy; and (3) a supplemental demand response program.
ISO-NE has also published a memorandum describing payment rates for the 2016-2017 winter program. Under its tariff, ISO-NE first determines a "Set Rate," representing partial compensation for the per-barrel carrying costs of stored fuel oil. The Set Rate is translated into an equivalent rate for the other, non-oil services that are compensated through Appendix K.
Requests to participate in ISO New England's 2016-2017 Winter Reliability Program are due to ISO-NE by October 1, 2016.
Since the winter of 2013-2014, ISO New England Inc. has operated a seasonal program to address winter fuel security and power system reliability concerns, relating largely to natural gas pipeline constraints. After two initial program years, last fall the Federal Energy Regulatory Commission approved a three-year plan for ISO-NE's Winter Reliability Program.
That program, developed chiefly by market participant group New England Power Pool (NEPOOL), was designed to address reliability concerns through at least 2017-2018, when new “Pay-for-Performance” incentives and penalties in New England's redesigned capacity market are set to take effect. The winter reliability program encourages generators fueled by oil and liquefied natural gas (LNG) to secure fuel before the winter season begins, by compensating them for some costs related to fuel inventory that remains unused at winter's end, and includes a demand response component. According to ISO-NE, last year's participants included 77 oil-fired units, 8 LNG units, and 6 demand response assets.
The program's rules are specified in Appendix K to Section III of the ISO New England Inc. Transmission, Markets and Services Tariff. As approved by FERC, the current program retains the three core components of the 2014-2015 Winter Reliability Program: (1) compensation for certain oil inventory that remains in New England following the end of each winter period; (2) end-of-season compensation for LNG contract volumes kept available for winter use but not actually called upon to produce energy; and (3) a supplemental demand response program.
ISO-NE has also published a memorandum describing payment rates for the 2016-2017 winter program. Under its tariff, ISO-NE first determines a "Set Rate," representing partial compensation for the per-barrel carrying costs of stored fuel oil. The Set Rate is translated into an equivalent rate for the other, non-oil services that are compensated through Appendix K.
Requests to participate in ISO New England's 2016-2017 Winter Reliability Program are due to ISO-NE by October 1, 2016.
ISONE External Market Monitor report 2015
Monday, July 11, 2016
A report by the New England electricity market's external monitor has found that "the markets performed competitively in 2015."
ISO New England operates wholesale electricity markets covering most of New England. It employs two independent market monitors -- one internal to ISO-NE, one a hired external consultant -- to regularly review, analyze, and report on market results, and offer recommendations on market improvements.
Potomac Economics serves as the External Market Monitor for ISO-NE. In this role, it is charged with evaluating the competitive performance, design, and operation of the wholesale electricity markets operated by ISO-NE. Last month, the external market monitor released its "2015 Assessment of the ISO New England Electricity Markets" (102-page PDF), presenting its perspective on the New England electricity markets.
Among other findings, the report notes that energy market trends "have been dominated by reductions in fuel prices over the last two years. In particular, from 2014 to 2015:
ISO New England's internal market monitor released its 2015 Annual Markets Report earlier this year. That report similarly found that overall, "the ISO New England capacity, energy, and ancillary service markets performed well in 2015."
ISO New England operates wholesale electricity markets covering most of New England. It employs two independent market monitors -- one internal to ISO-NE, one a hired external consultant -- to regularly review, analyze, and report on market results, and offer recommendations on market improvements.
Potomac Economics serves as the External Market Monitor for ISO-NE. In this role, it is charged with evaluating the competitive performance, design, and operation of the wholesale electricity markets operated by ISO-NE. Last month, the external market monitor released its "2015 Assessment of the ISO New England Electricity Markets" (102-page PDF), presenting its perspective on the New England electricity markets.
Among other findings, the report notes that energy market trends "have been dominated by reductions in fuel prices over the last two years. In particular, from 2014 to 2015:
- Natural gas prices declined more than 40 percent, falling to multi -year lows in mid -2015 largely because of higher shale production from the Marcellus and Utica regions; and
- Fuel oil prices fell by more than 35 percent because of increased global supply, and world liquefied natural gas (LNG) prices have fallen similarly. These reductions helped limit the increase in natural gas prices during tight gas supply conditions in the winter.
ISO New England's internal market monitor released its 2015 Annual Markets Report earlier this year. That report similarly found that overall, "the ISO New England capacity, energy, and ancillary service markets performed well in 2015."
Canada NEB starts Energy East pipeline review
Friday, June 24, 2016
Canada's National Energy Board has ruled that the applications are complete for the Energy East Pipeline Project and a related gas project. This determination starts the NEB's review process, under which the Board must issue its recommendations to the Minister of Natural Resources within 21 months.
The National Energy Board is an independent federal regulator of several parts of Canada's energy industry, including the regulation of pipelines, energy development and trade in the Canadian public interest.
As envisioned by proponents TransCanada and Energy East Pipeline Ltd., Energy East would be a 4,500-kilometer pipeline that will transport approximately 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick. Some existing natural gas pipeline would be converted to oil transportation pipeline, while other facilities would be newly built. The project is motivated in part by a relative surplus of Western Canadian crude production, with relatively few ways to ship that crude to refineries or ports.
The related Eastern Mainline Project entails about 279 kilometers of new gas pipeline and related components, designed to let TransCanada continue to supply gas after the proposed transfer of certain Canadian Mainline facilities to Energy East Pipeline Ltd. for conversion to crude oil service.
On June 16, 2016, the National Energy Board announced its determination that due to the interconnections between the applications, the Energy East and Eastern Mainline projects are more effectively assessed within a single hearing process, with one record, reviewed by one Panel of Board Members. It also deemed the applications complete to proceed to assessment and a public hearing, starting the 21-month review process.
The Panel must submit a report to the Minister of Natural Resources recommending whether or not the projects should proceed, or on what conditions. This report is due no later than March 16, 2018. According to the NEB, the process will include hearings, panel sessions, and assessments of the upstream greenhouse gas emissions associated with the project.
The National Energy Board is an independent federal regulator of several parts of Canada's energy industry, including the regulation of pipelines, energy development and trade in the Canadian public interest.
As envisioned by proponents TransCanada and Energy East Pipeline Ltd., Energy East would be a 4,500-kilometer pipeline that will transport approximately 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick. Some existing natural gas pipeline would be converted to oil transportation pipeline, while other facilities would be newly built. The project is motivated in part by a relative surplus of Western Canadian crude production, with relatively few ways to ship that crude to refineries or ports.
The related Eastern Mainline Project entails about 279 kilometers of new gas pipeline and related components, designed to let TransCanada continue to supply gas after the proposed transfer of certain Canadian Mainline facilities to Energy East Pipeline Ltd. for conversion to crude oil service.
On June 16, 2016, the National Energy Board announced its determination that due to the interconnections between the applications, the Energy East and Eastern Mainline projects are more effectively assessed within a single hearing process, with one record, reviewed by one Panel of Board Members. It also deemed the applications complete to proceed to assessment and a public hearing, starting the 21-month review process.
The Panel must submit a report to the Minister of Natural Resources recommending whether or not the projects should proceed, or on what conditions. This report is due no later than March 16, 2018. According to the NEB, the process will include hearings, panel sessions, and assessments of the upstream greenhouse gas emissions associated with the project.
Stanford declines to divest fossil fuels
Thursday, April 28, 2016
Should university endowments be invested in fossil fuel companies? Or should they divest such holdings? Universities across the U.S. are considering these questions. In the latest development, Stanford University's Board of Trustees has released a statement on climate change, describing the university's initiatives to battle climate change, but declining to divest Stanford's roughly $22 billion endowment from the fossil fuel industry.
In the April 25 statement, the Board describes climate change as "among the most serious challenges of our time." The statement lists various elements of Stanford's strategic approach to combating climate change, including a $500 million transformative campus energy system, commitments to invest in solar, other renewable energy, wastewater recovery, green transportation, and energy efficiency in campus buildings. The statement also announces the creation of a new climate task force to be composed of undergraduates, graduate students, faculty and staff, to solicit ideas for further action.
Much of the statement is structured as a response to a proposal by student organization Fossil Free Stanford that the university divest its endowment from the fossil fuel industry. The trustees cite the university's Statement on Investment Responsibility as outlining a specific set of criteria by which the trustees may evaluate whether a company is inflicting social injury in a manner that warrants consideration of divestment. The statement notes the establishment of an Advisory Panel on Investment Responsibility and Licensing, which studied the issues and made a recommendation to the Board’s Special Committee on Investment Responsibility, which in turn made a recommendation to the trustees.
According to the statement, the advisory panel "recommended divestment of companies whose primary business is oil sands extraction, a method that studies have found requires more water, and releases more carbon into the atmosphere, than other forms of fossil fuel extraction." It cites Stanford Management Company as saying that the Stanford endowment has no direct exposure to companies whose primary business is oil sands extraction, so the trustees had no action to take on this point.
On the broader fossil fuel industry, the panel "concluded that it could not evaluate whether the social injury caused by the fossil fuel industry outweighs the social benefit it provides, and therefore did not recommend divestment." The trustees agreed that the criteria were not met, and declined to divest.
That said, the statement expressed the trustees' belief "that the global community must develop effective alternatives to fossil fuels at sufficient scale, so that fossil fuels will not continue to be extracted and used at the present rate... the long-term solution is for all of us to reduce our consumption of fossil fuel resources and develop effective alternatives."
But despite investment and progress in research, including by Stanford, the trustees note that "at the present moment oil and gas remain integral components of the global economy, essential to the daily lives of billions of people in both developed and emerging economies." The statement also notes the efforts of some oil and gas companies to explore alternatives. The statement notes that "the trustees do not believe that a credible case can be made for divesting from the fossil fuel industry until there are competitive and readily available alternatives."
The statement also notes that the university's investment program does take climate change into consideration when evaluating the economic attractiveness of various investments. In the trustees' words, "Prudent investors acknowledge that the world is beginning a transition away from carbon-based energy sources and that pricing for fossil fuels will reflect this transition." The statement also notes the efforts of the endowment managers to "identify and support industry best practices that, in addition to positively impacting investment results, may pay significant environmental dividends."
This is not the first time Stanford has considered divesting from fossil fuels. In 2014, after pressure from Fossil Free Stanford, the trustees announced a decision that Stanford would not make direct investments in coal mining companies, in recognition of "the availability of alternate energy sources with lower greenhouse gas emissions than coal."
In the April 25 statement, the Board describes climate change as "among the most serious challenges of our time." The statement lists various elements of Stanford's strategic approach to combating climate change, including a $500 million transformative campus energy system, commitments to invest in solar, other renewable energy, wastewater recovery, green transportation, and energy efficiency in campus buildings. The statement also announces the creation of a new climate task force to be composed of undergraduates, graduate students, faculty and staff, to solicit ideas for further action.
Much of the statement is structured as a response to a proposal by student organization Fossil Free Stanford that the university divest its endowment from the fossil fuel industry. The trustees cite the university's Statement on Investment Responsibility as outlining a specific set of criteria by which the trustees may evaluate whether a company is inflicting social injury in a manner that warrants consideration of divestment. The statement notes the establishment of an Advisory Panel on Investment Responsibility and Licensing, which studied the issues and made a recommendation to the Board’s Special Committee on Investment Responsibility, which in turn made a recommendation to the trustees.
According to the statement, the advisory panel "recommended divestment of companies whose primary business is oil sands extraction, a method that studies have found requires more water, and releases more carbon into the atmosphere, than other forms of fossil fuel extraction." It cites Stanford Management Company as saying that the Stanford endowment has no direct exposure to companies whose primary business is oil sands extraction, so the trustees had no action to take on this point.
On the broader fossil fuel industry, the panel "concluded that it could not evaluate whether the social injury caused by the fossil fuel industry outweighs the social benefit it provides, and therefore did not recommend divestment." The trustees agreed that the criteria were not met, and declined to divest.
That said, the statement expressed the trustees' belief "that the global community must develop effective alternatives to fossil fuels at sufficient scale, so that fossil fuels will not continue to be extracted and used at the present rate... the long-term solution is for all of us to reduce our consumption of fossil fuel resources and develop effective alternatives."
But despite investment and progress in research, including by Stanford, the trustees note that "at the present moment oil and gas remain integral components of the global economy, essential to the daily lives of billions of people in both developed and emerging economies." The statement also notes the efforts of some oil and gas companies to explore alternatives. The statement notes that "the trustees do not believe that a credible case can be made for divesting from the fossil fuel industry until there are competitive and readily available alternatives."
The statement also notes that the university's investment program does take climate change into consideration when evaluating the economic attractiveness of various investments. In the trustees' words, "Prudent investors acknowledge that the world is beginning a transition away from carbon-based energy sources and that pricing for fossil fuels will reflect this transition." The statement also notes the efforts of the endowment managers to "identify and support industry best practices that, in addition to positively impacting investment results, may pay significant environmental dividends."
This is not the first time Stanford has considered divesting from fossil fuels. In 2014, after pressure from Fossil Free Stanford, the trustees announced a decision that Stanford would not make direct investments in coal mining companies, in recognition of "the availability of alternate energy sources with lower greenhouse gas emissions than coal."
ISO New England Regional Electricity Outlook 2016
Wednesday, March 2, 2016
The New England regional power system is in a state of major transformation, according to regional grid operator ISO New England, Inc.'s 2016 Regional Electric Outlook.
ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England. In this role, the ISO plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.
The 2016 Regional Electric Outlook report is the latest annual installment of the grid operator's update on the state of the grid and the ISO’s efforts to ensure reliable electricity and to improve services and performance. This year's report describes the New England grid administrator as "in the vanguard of a major transformation in how electricity is produced and delivered in the US."
Three waves of change -- natural gas, renewable energy and demand resources, and distributed generation -- are affecting New England's fleet of power resources, according to the report:
The report also describes the ISO's tactics for managing the reliability risks associated with these shifts in the region's energy mix, including stronger "pay for performance" financial incentives for power resources to perform as required. It cites various ISO studies indicating "that, ultimately improving the natural-gas-delivery infrastructure in New England" will best address reliability concerns, price spikes, and unnecessary emission impacts from oil and coal units during winter.
The report, along with previous years' reports, are available on the ISO's website.
ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England. In this role, the ISO plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.
The 2016 Regional Electric Outlook report is the latest annual installment of the grid operator's update on the state of the grid and the ISO’s efforts to ensure reliable electricity and to improve services and performance. This year's report describes the New England grid administrator as "in the vanguard of a major transformation in how electricity is produced and delivered in the US."
Three waves of change -- natural gas, renewable energy and demand resources, and distributed generation -- are affecting New England's fleet of power resources, according to the report:
Natural-gas-fired generation has displaced older coal, oil, and nuclear plants. Weather-dependent renewable power resources and energy-efficiency measures are multiplying. On the horizon comes a “hybrid grid”—a combination of large power resources supplying the regional system while smaller ones directly supply consumer sites.According to the report, coal, oil, and nuclear resources are retiring; it noted that resources representing about 30% of regional capacity have committed to cease operation or are at risk of retirement by 2020. Most power plants planned to replace them will rely in part or in whole on natural gas or renewable generation. The report notes:
Our region's natural-gas-fired power resources are among the newest, most efficient, and lowest-emitting plants in the country. When their access to low-priced gas from the Marcellus shale is unrestricted, New England has reliable, low-priced electricity.The report also states that "wintertime access to natural gas has grown tight over recent years because the regional fuel transportation network has not kept up with demand from both generation and heating sectors." As a result of pipeline constraints, the ISO notes "grid reliability challenges, emission increases during winter, and spikes in wholesale electricity prices."
The report also describes the ISO's tactics for managing the reliability risks associated with these shifts in the region's energy mix, including stronger "pay for performance" financial incentives for power resources to perform as required. It cites various ISO studies indicating "that, ultimately improving the natural-gas-delivery infrastructure in New England" will best address reliability concerns, price spikes, and unnecessary emission impacts from oil and coal units during winter.
The report, along with previous years' reports, are available on the ISO's website.
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