Between the Poles

Transmission and cost could inhibit the continued expansion of renewable energy generation

Transmission constraints

Estimates of the transmission buildout required in the US to reduce congestion and to bring renewable electric power to market have ranged from 19,000 to 50,000 miles of new transmission lines.  The Brattle Group has estimated the total investment in transmission required between 2010 and 2030 to be on the order of $300 billion.  One of the most important provisions of the Energy Policy Act of 2005 was to encourage expansion of the transmission grid in the U.S.

In the United States it has been estimated that it requires 12-20 years to plan and build a new transmission line.  In October, 2009, nine Federal entities signed a Memorandum of Understanding increasing their coordination to expedite and simplify building of transmission lines on Federal lands. The Obama administration has announced pilot projects to streamline the permitting of transmission lines, to speed up integration of renewables.

It was reported from the recent NARUC Summer Committee Meetings that some U.S. states may not be able to meet their renewable portfolio standards (RPS) goals because of a lack of transmission to carry the power to market. "Transmission constraints are impeding RPS implementation in large portions of New England, transmission congestion is inhibiting renewable energy use in New York."

In California a state Commissioner said that Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) are currently each obtaining approximately 21% of their energy from renewable resources and he expects that California will be able to meet its mandated target of 33% renewable.

Costs

Another important factor is the continued low cost of natural gas generation and what some forecast will be the increasing cost of renewable energy generation.   For example, Texas has already met its 2020 RPS objective of 10 GW of renewable energy capacity, mostly through wind generation.  It is projected that because of competition from low cost natural gas generation, the transmission lines built as part of the the competitive renewable energy zone (CREZ) with a capacity of 18 GW from West Texas, may not be used to their full capacity.  One prediction is that only 11 GW of the transmission capacity will ultimately be used.  One regulator said that the cost of renewable generation including the necessary transmission and the cost of the dispatchable backstop generation could get too expensive and cause consumer backlash.  A FERC commissioner expressed the opinion that ultimately coal and natural gas generation will become more expensive than renewable.  The imponderable is when the price of natural gas will rise to what some forecast will be about $8/Mcf from the current economically unsustainable $2.00/Mcf. 

$23 billion investment in transmission projected under FERC Order 679 through 2016

Estimates of the transmission buildout required in the US to reduce congestion and to bring renewable electric power to market have ranged from 19,000 to 50,000 miles of new transmission lines.  The Brattle Group has estimated the total investment in transmission required between 2010 and 2030 to be on the order of $300 billion.

I have blogged about the Energy Policy Act of 2005 before.  It has had far reaching implications for many energy-related sectors including nuclear power and the shale-gas industry.  One of the most important provisions was to encourage expansion of the transmission grid in the U.S.

One of the specific measures of the bill required FERC to establish rules for incentive-based rates to encourage investment in transmission to reduce congestion.  What this means is rules that allow utilities to set rates to recover the cost (plus a specified rate of return) of building new transmission capacity.

FERC Order 679 came into force in September 29, 2006 and established rules to encourage investment in transmission infrastructure to reduce transmission congestion. Among its provisons were full recovery of construction, pre-operations costs, and costs of abandoned facilities; accelerated depreciation; and a higher rate of return on equity for utilities that join and/or continue to be members of transmission organizations, such as regional transmission organizations (RTOs) and independent system operators (ISOs).  The rule also streamlined procedures for the approval of incentives.

According to a recent analysis by the Transmission Hub, Order 679 is expected to lead to nearly $23 billion investment in electric transmission investment between 2012 and 2016.  The estimated total from 2008 to 2016 could reach $36.2 billion.  According to the report the companies with the highest projected investments are:

• Southern California Edison - $4.9 billion for 25 transmission projects.
• Dominion Resources - $2.9 billion for 30 projects
• PacificCorp - $2 billion for the Energy Gateway transmission expansion project
• Exelon - $2.1 billion for several projects including the Reliability Interregional Transmission Extension line (RITELine).

Aggressively transforming the German power grid

The Federal Ministry for the Economy and Technology has published a most interesting overview of how Germany plans to transform the German electric power grid.  It is based on the 40 year energy plan that was released in 2010, but incorporates the 2011 decision to shut down all nuclear power plants in Germany by 2022.

Ensuring adequate power supply at affordable prices is essential for the future development of the German economy.  By 2022 Germany intends to shut down existing nuclear power plants. Together with the requirement to reduce emssions this is forcing a fundamental restructuring of the German energy supply including a new, intelligent and efficient power grid.

Another important factor is reliability.  A measure of reliability is the total time of nonavailability - the total number of minutes annually that the avereage consumer is without power.  In Germany this is about 14.63 minutes annually, reflecting a very high level of reliability.  It will be necessary to maintain this high level of availability as the grid is radically transformed.

German electric power generation is currently 80% fossil and nuclear fuels.  In 40 years it is planned that it will be over 80% renewable energy and CO₂ emissions will be at least 80% below the 1990 emissions level.  To do this will require a new power grid, new power generation plants, new storage facilities, and new technologies. In 2008 power consumption in Germany was about 625 TWh.  By 2030 consumption is expected to drop to about 500 TWh, of which about half will be derived from renewable sources.  In 2030 it is projected that roughly 50 TWh net will be imported.

Transforming the grid

The German electric grid consists of 1.7 million km of conductors.  It will need to be expanded and reinforced to support new onshore and offshore wind turbines, thousands of new solar power generator installations as well as new conventional power plants to replace nuclear and older fossil fuel plants.

To develop the new grid, the highest priorities are

• New transmission capacity to link 25 GW of offshore wind generation in the Baltic by 2030,
• In addition to the new natural gas and coal power plants that are already being constructed, an additonal 17 GW of conventional power generation will be required by 2022.
• In 2010 about 880,000 photovoltaic installations produced about 11,500 GWh.  By 2020 the number of solar installations will continue to increase.
• By 2015 about 400 km of high tension transmission lines will need to be reinforced and an additional 850 km constructed.  By 2020 several thousand km of new transmission capacity will be required.
• In 2010 a total of 22,500 GWh were generated from biogas and biomass sources.  By 2020 this will increase to about 50,000 GWh
• Currently the German power grid has storage capacity of about 10 GW from storage and pumped storage power plants - about the equivalent of 10 large power plants.  By 2020 storage it is projected that storage capacity will increase to 13 GW.

Streamlining planning and regulatory approval

Until now the construction of new transmission capacity has been seriously delayed by a very cumbersome planning and regulatory process, especially for lines crossing multiple states (This situation is even worse in the U.S.).  In the summer of 2011 the Federal and State governments agreed on a foundation for streamlining the planning and regulatory approval process for expanding the transmission grid.  Two new laws, EnWG and NABEG, were passed.  The objective of the new laws is to reduce the time required for planning and regulatory approval for new transmission lines from ten years to four years.  A key provision of NABEG is that when proposed transmissiion lines cross multiple States, the Federal regulator (BNA) will be responsible for planning and approval using an open and transparent process.

U.S. Department of Energy's vision of the power grid in 2035

The U.S. Department of Energy (DoE) has decided to share its vision of the electric power grid in 2035 with industry, vendors, regulators and consumers.

Seamless, cost-effective electricity system from generation to end use

This means supporting both AC and DC and designed to optimize asset utilization and operating efficiency.  It should have different characteristics in different regions, reflecting local circumstances, but be part of a shared national vision.  It should be reliable and resilient, enable new products and services to be added, and help the U.S.'s global competitiveness.

Meeting the clean energy demands and capacity requirements of this century

The DoE sees a dramtic increase in clean energy generation, suggesting 80% by 2035, and accommodating a wide range of generation and storage options.  It would be reasonable to assume that by clean energy is meant the very broad range of options as defined in the current Clean Energy Standard before the Senate.

Allowing consumer participation and electricity use as desired

The DoE vision means informed participation by consumers with complete choice of how they want to participate. It includes distributed resources, demand response, demand-side management, electrification of transportation, and energy efficiency.

Getting there

These are all things that have been part of the vision of renewable energy and smart grid for some time.  What is emerging is a better idea of how to get there.  Jesse Berst sees several things that we need to do to enable the DoE vision of the grid in 2035 to happen.

• AC-DC hybrid systems
• Different degrees of power quality for different customer sets
• Making it easy for outsiders to offer new products, services and markets
• Making it easy for any form of generation or storage to hook into the system
• Giving choice to 100% of customers
• The substation will morph into an "Electricity Systems Hub"

Intelligent substations will become the “pinch point” for end-to-end integration.  The DoE sees a blurring of the distinction between transmission and distribution, which will create opportunities for industry and  make life interesting for regulators.

State regulatory commissioners express concerns to FERC over Order 1000

According to a very recent article at the Annual Meeting of the National Association of Regulatory Utility Commissioners (NARUC) state commissioners met with two FERC commissioners and FERC staff to discuss FERC Order 1000 which is intended to provide the basis for a national policy for transmission planning and cost allocation in the U.S.

State commisioners raised a number of issues ranging from how to protect a state's ratepayers from decisions made in a neighbouring state to the economic implications of the new planning and cost allocation policy.  FERC has asked the states and regions to come up with a way to comply with Order 1000 within a year.  Some state commissioners thought this was too tight a timeframe given the potential impact that the wide ranging changes that Order 1000 will have on existing planning processes.  The FERC commissioners said that Order 1000 is general enough that it gives the states and regions lots of room to come up with their own solutions.

European Commission proposes trans-European electric transmission development plan

In major economies transmission is the enabler for getting electric power to electric distribution companies, for creating a single market for electric power and for integrating major sources of renewable energy.  

Two persistent issues have held up development of new trasmission lines, planning and cost allocation. In the US in June, 2010 the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, which began the process of addressing these issues from a regulatory perspective.  FERC recently issued Order 1000, which is designed to address transmisssion planning and cost allocation.

The European Commission (EC) has recently issued a Proposal for a Regulation on Guidelines for Trans-European Energy Infrastructure.  The objective of the new regulation is the full integration of the EU energy market to ensure that no Member State is isolated from the European network, help the EU achieve its 20-20-20 energy and climate targets by 2020, and ensure security of supply.

The initiative identifies trans-European priority corridors and areas covering electricity and gas networks as well as oil and carbon dioxide transport infrastructure. It also proposes several measures to facilitate the development of transmission lines

• streamlining permit granting procedures to speed up the regulatory and public review process
• allocating costs depending on the benefits provided and ensuring allowed returns are in line with risks incurred
• providing direct EU financial support under the "Connecting Europe Facility", a €50 billion fund to improve Europe's transport, energy and digital networks

The  EC estimates that the total investment required for EU energy infrastructure from now to 2020 at about € 200 billion;

• €140 billion for high voltage electricity transmission systems, both onshore and offshore, storage, and smart grid applications at transmission and distribution level
• € 70 billion for high pressure gas transmission pipelines (coming into the EU and between EU Member states), storage, liquefied/compressed natural gas (LNG/CNG) terminals and reverse flow infrastructure
• € 2.5 billion for carbon dioxide transport infrastructure

Energy infrastructure will be prioritized because energy networks are a precondition for reaching the 2020 energy and climate targets. The main obstacles that have been identified that will hinder putting this infrastructure in place are protracted permit granting procedures, conflicting Member State regulations and financing.  Not that different from the issues facing the US, except for one big difference.  In the US there is no federally mandated organization responsible for planning a national transmission grid.

Priority Electricity Corridors

Northern Seas offshore grid (“NSOG”)

Member States concerned: Belgium, Denmark, France, Germany, Ireland, Luxemburg, the Netherlands, Sweden, the United Kingdom

North-South electricity interconnections in Western Europe (“NSI West Electricity”)

Member States concerned: Belgium, France, Germany, Ireland, Italy, Luxembourg, Netherlands, Malta, Portugal, Spain, the United Kingdom

North-South  electricity interconnections in Central Eastern and South EasternEurope ("NSI East Electricity")

Member States concerned: Austria, Bulgaria, Czech Republic, Cyprus, Germany, Greece, Hungary, Italy, Poland, Romania, Slovakia, Slovenia

Baltic Energy Market Interconnection Plan in  electricity ("BEMIP Electricity")

Member States concerned: Denmark, Estonia, Finland, Germany, Latvia, Lithuania, Poland, Sweden

Streamlining the transmission permitting process in the US

As a speaker said at a recent conference, building a transmission line used to take 90 days, now it takes between 12 and 20 years because of the complicated permitting process,

• Planning 1-2 years
• Cost allocation 6-12 months
• Federal approval 3-5 years
• State approval and siting 3-5 years
• Construction including access roads 2-7 years

The Brattle Group has estimated the total investment in transmission required between 2010 and 2030 to be on the order of $300 billion.  With an estimated 50,000 miles of new transmission lines required in the US primarily to bring renewable energy to market, something needs to be done to speed up the cumbersome permitting process

As a first step in October of 2009, nine Federal entities including, the White House Council on Environmental Quality (CEQ), the Department of the Interior (DOI), the Department of Agriculture (USDA), the Department of Energy (DOE), the Department of Commerce, the Department of Defense, the Environmental Protection Agency, the Federal Electric Regulatory Commission (FERC), and the Advisory Council on Historic Preservation, signed a Memorandum of Understanding increasing their coordination to expedite and simplify building of transmission lines on Federal lands.

The Obama administration has just announced pilot projects to streamline the permitting of transmission lines ,to speed up integration of renewables and electric vehicles integration, increase the reliability of the grid, and reduce the need for new power plants.

The transmission line permitting process involves many federal agencies including DOE, FERC, Interior, Defense, Agriculture, the Council on Environmental Quality, and the EPA.  This is in addition to state regulators, local government and tribal stakeholders.

The administration's transmission pilots will focus on accelerating permitting for seven proposed transmission lines affecting 12 states: Arizona, Colorado, Idaho, Minnesota, New Mexico, Nevada, Wyoming, Utah, New Jersey, Pennsylvania, Oregon and Wisconsin.  The accelerated process involves coordinating statutory permitting, review and consultation schedules and processes among the federal and state agencies; applying a consistent approach to consultations with tribal governments, and quickly resolving interagency conflicts and ensuring that all participants are fully involved and meeting schedules.

Toward a US national transmission grid for renewable energy

Estimates of the transmission buildout required in the US to bring renewable electric power to market have ranged from 19,000 to 50,000 miles of new transmission lines.  The Brattle Group has estimated the total investment in transmission required between 2010 and 2030 to be on the order of $300 billion.  But unlike the EU, there is no federally mandated carbon or emissions objective in the US.   However, 36 states have some form of renewable energy portfolio standards (RPS or RES). 

The length of time it takes to develop a new transmission line is clearly a deterrent to rapid transmission build-out. At a recent transmission conference a speaker estimated the time required to develop a new transmission line is 10-20 years, or broken down

• Planning 1-2 years
• Cost allocation 6-12 months
• Federal approval 3-5 years
• State approval and siting 3-5 years
• Construction including access roads 2-7 years

Section 216 of the Energy Policy Act of 2005, passed during Bush/Cheney administration, was intended to address the problem of accelerating the expansion of a national transmission network by giving the federal Department of Energy (DoE) the power to designate National Interest Electric Transmission Corridors (NIETCs) where there are significant transmission limitations adversely affecting the public and giving the Federal Energy Regulatory Commission (FERC) the power to authorize federal permits for transmission projects in these regions.  These permits included giving the transmission providers the power of expropriation.  But there have been two successful court challenges against Section 216.  It had become hard to see how a national transmission grid was going to be built in the US.

Two persistent transmission construction issues have held things back, planning and cost allocation. 

• Who should plan for new transmission ?
• Who should pay for new transmission?

In June, 2010 the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, which began the process of addressing these issues from a regulatory perspective.

Order No. 1000

FERC has approved a rule, Order No. 1000, for transmission that indirectly makes renewable energy allocation an important component in planning and cost allocation.  The rule establishes requirements for transmission planning and cost allocation and takes effect within 60 days of publication.

Planning

• Each public utility transmission provider must participate in a regional transmission planning process
• Local and regional transmission planning processes must consider transmission needs driven by federal or state public policy requirements [which includes state renewable energy portfolio standards (RPS or RES)]
• Public transmission providers in neighboring transmission planning regions must coordinate to determine if there are more efficient solutions to their mutual transmission needs.

Cost allocation

• Each public transmission provider must participate in a regional transmission planning process that has a regional cost allocation method for new transmission facilities
• Public  transmission providers in neighboring planning regions must have a common interregional cost allocation method
• Participant-funding of new transmission facilities is permitted, but is not allowed as the regional or interregional cost allocation method

The renewable energy industry, such as the American Wind Energy Association (AWEA), are very supportive of FERC's new rule.  Some transmission developors such as ITC believe that the new rule will help create a framework which will allow large scale transmission proposals to receive a fair evaluation that accounts for all of the benefits they generate for an entire region.