North American Electric Reliability Council. Oct 2006. Summary of 2006 Long-Term Reliability Assessment: The Reliability of the Bulk Power Systems In North America
Capacity Margin — Capacity that could be available to cover random factors such as forced outages of generating equipment, demand forecast errors, weather extremes, and capacity service schedule slippage.
Available Capacity Margin — The difference between committed capacity resources and peak demand, expressed as a percentage of capacity resources.
Potential Capacity Margin — The difference between committed plus uncommitted capacity resources and peak demand, expressed as a percentage of capacity resources.
Committed Capacity Resources — Generating capacity resources that are existing, under construction, or planned that are considered available, deliverable, and committed to serve demand, plus the net of capacity purchases and sales.
Fuel Supply and Delivery for Electric Generation Important to Reliability
• The adequacy of electricity supplies depends, in part, on the adequacy of fuel supply and delivery systems, not just the installed capacity of generators.
• Gas-fired generating capacity additions are projected to account for almost half of the resource additions over the 2006–2015 period.
• Dependence on natural gas for electric generation is projected to increase in most regions
• The supply and delivery of gas to electric generators can be disrupted when electric generation demands for gas coincide with high gas demands for other customers. In some cases, even firm
gas contracts for electric generation can be curtailed in favor of residential heating needs during extreme cold weather.
• Strengthening fuel delivery infrastructures and firming up gas supply and delivery contracts will reduce the potential for shortages in electricity supplies due to fuel disruptions.
Aging Workforce a Challenge to Future Reliability
• The reliability of the North American electric utility grid is dependent on the accumulated experience and technical expertise of those who design and operate the system.
• As the rapidly aging workforce leaves the industry over the next five to ten years, the challenge to the electric utility industry will be to fill this void.
Available capacity margins in the U.S. and Canada are projected to decline over the 2006–2015 period. Margins vary from region to region, as does the amount of uncommitted resources reported.
Transmission Expansion Difficulties
Regulatory and licensing issues continue to push out the in-service dates of needed transmission projects. While most agree that new transmission lines can improve system reliability and enhance economic transfers of energy, siting of lines still runs into the same roadblocks as years past. These delays also can increase the cost significantly. “Not In My Back Yard” (NIMBY) issues apply to many industries besides the electric power industry, but the higher public exposure to long transmission lines with wide right-of-ways seems to cause the most consternation among the public. Concerns about the health aspects of living next to a transmission line still linger.
Recovery of the extreme high cost of acquiring property and building a new line can take years or may even be uncertain. The investment in construction of a new line is considerable. In some areas, recovery of these costs is left up to case by case negotiations between the builder and, possibly multiple state utility commissions. This can be very discouraging on the builder’s part. Other areas may have structured cost recovery mechanisms in place but full recovery may take several decades. Acquiring right-of-way property can be influenced by several aspects including land prices, environmentally sensitive areas, and NIMBY issues. Land prices are increasing along with the quickly rising cost of housing. In some areas, land price inflation is averaging three or four times the general inflation rate. Some environmental groups are well organized with extremely good legal representation. All legal options to stop transmission line development are usually utilized. Many developers are concerned about quicker development of generation in resource limited areas. Average time to plan and build a transmission line is considerably longer than the time it takes to permit and build some generation plants. The need to alleviate a congested path by building a new transmission line into a resource limited area may be made unnecessary by the addition of generation in that area.
Resource adequacy is measured by the capacity in MW of the physical “iron in the ground” represented by the generating plants, both existing and planned. However, an adequate supply of reliable electric resources to the North American electric grid is equally dependent on readily available fuel supported by a secure transportation infrastructure to deliver the fuel to the generating facility. An important element is diversity of fuel. In recent years, the electric industry has witnessed numerous events that can potentially diminish the supply of any given fuel:
• Hurricanes in the Gulf of Mexico in the summer of 2005 threatened the supply of off-shore natural gas to the United States.
• Extended droughts in the west reduced the available energy of several major hydroelectric sites in the late 1990s.
• Tensions in the Middle East continue to result in dramatic fluctuation in the price for fuel oil and could ultimately lead to major supply interruptions.
• In 2003, the political unrest in Venezuela interrupted the only production of fuel.
• Shutting down mines due to safety issues.
• Curtailments of rail delivered/barge delivered coal.
• Short-term fuel acquisition problems driven by global markets.
The security of the supply of off-shore oil may, in future years, be dependent on the political stability of those countries exporting the majority of the world’s oil, many of which are currently experiencing internal turmoil. This also includes the import of liquefied natural gas (LNG), which, although a natural gas product produced by the extreme cooling of natural gas into its liquid state, is supplied by many of the same regions of the world on which North America is dependent for its oil supply. Thus the uncertainty of both the price and availability of imported oil makes it increasingly unreliable as a utility fuel in the years ahead.
Because it is efficient and clean burning, natural gas has become the preferred fuel in North America for new generation additions, and its consumption by the electric utility industry is increasing rapidly. In addition, natural gas is also a prevalent fuel for home heating in many parts of North America, competing with the electric utility for gas supply at peak times. With this continuing growth in gas usage by the electricity sector, the adequacy and security of the natural gas supply and its infrastructure will become ever more critical to the reliability of electric supply.
The North American transmission system has evolved over the last century during periods of rapid growth from the 1950s through the 1970s paralleling the technological advancements in generation. The transmission facilities installed through the 1970s are reaching the end of their projected useful life. These facilities will need to be either replaced or repaired to maintain grid reliability. Over the past decades, the vast majority of transmission investment was directed towards constructing new facilities to meet customer load demands and comparatively little capital investment was expended for the refurbishment of the existing facilities. The aging transmission system infrastructure has many challenges such as: the availability of spare parts; the obsolesce of older equipment; the ability to maintain equipment due to outage scheduling restrictions; and the aging of the work force and lost knowledge due to personnel retirements. The North American transmission owners must take a more proactive approach going forward in replacing obsolete and unreliable equipment including transmission lines. Chronological age is not the only condition that should be used to determine when equipment should be replaced. Potential for increased failure rates should be evaluated. These considerations should consider the diversity of equipment technologies and installation dates. However, implementation of any replacement strategy and in-depth training programs require additional capital investment, engineering and design resources, and construction labor resources, all of which are in relatively short supply
Renewable resources will become an increasing portion of total generation resources in the future. Generation from wind, solar, biomass, geothermal, hydro, and to a lesser extent, wave/tidal, landfill gas, and municipal or biomass-based waste are generally considered renewable sources. Nearly 14,000 MW are projected to be added over the next ten years throughout North America.
Wind generation is expected to provide the bulk of the energy required to meet requirements for additional generation from renewable sources. However, wind generation is often located in remote areas, which requires new transmission construction to deliver its energy to load. Because wind and some other renewable sources of electric power are intermittent in nature, actual generating capacity available at times of peak demand is less predictable than it is for capacity produced from more traditional technologies. Another characteristic of renewable sources is that typically the actual electricity produced in relation to the available capacity is relatively small. Although a large amount of capacity based on maximum output may be planned, these resources will be “energy-limited” and produce a relatively low level of MW-hours compared to their maximum capacity.
Intermittent and energy-limited renewable resources require that sufficient dispatchable resources and transmission capacity be available to assure system resource adequacy and operating security at all times. One way to take this into account in assessing a region’s resource adequacy is to discount the total installed capacity from renewable sources to a level that reflects their expected operating capacity at the time of highest system demand. The appropriate level of assumed reduction is very much dependent upon regional conditions and the mix of renewable energy technologies. These characteristics might require the installation of additional thermal generation [AJF: NG & COAL] to ensure the ability to reliably serve load at the time of system peak.
Further, renewable resources have some unique characteristics that need to be analyzed to determine their ability to operate within the capacity of local transmission facilities. Specific characteristics include reactive power capability, voltage regulation, and low-voltage ride-through capability, which allows generation to remain connected to the bulk system under low-voltage conditions. These characteristics have historically been problematic for wind generation. However, as amounts of wind generation are increasing, the manufacturers are improving the capabilities of the equipment being installed. In the past year, FERC has adopted standard interconnection requirements that apply to new wind generation capacity. These new requirements should help assure that new renewable generation being added does not degrade system reliability.
Aging Work Force
The loss of skilled and experienced technical talent is much more acute in the electric utility industry. According to a Hay Group study, 40 percent of senior electrical engineers and 43 percent of shift supervisors will be eligible for retirement by 2009. That study also found more than two-thirds of utility companies surveyed have no succession plan for supervisors and 44 percent have no plans for vice presidents. Not only does the industry not have enough professionals and managers, but the skilled labor force will be severely affected. Trying to get journeyman electricians and linemen will be more difficult than hiring the professional workforce.
At the same time, the demand for engineers with power background and other utility professionals has increased due to the advent of independent transmission companies, regional transmission organizations, and various markets. This caused the transmission dependent users, independent power producers, and other wholesale entities to increase their professional staff, particularly those with transmission planning expertise. Aggravating the problem of sustaining the essential technical knowledge is the dwindling numbers of students in the power engineering programs of most universities. Currently, the electric power engineering programs within the United States graduate about 500 engineers per year; in the 1980s, this number approached 2,000
The reliability of the North American electric utility grid is dependent on the accumulated experience and technical expertise of those who design and operate the system. As the rapidly aging workforce leaves the industry over the next five to ten years, the challenge to the electric utility industry will be to fill this void. The electric utility industry as a whole has not, however, established the needed cooperative programs with academia to reinvigorate the power engineering education in North America.
Green House Gas Emissions [could reduce electricity generation from fossil fuels and lower production, and depending on source of renewables, make the grid less reliable]
The long-term implications of greenhouse gas (GHG) emissions policies on the adequacy of future electricity supply are a function of the degree to which such policies and regulations limit or reduce the principal power plant sources of GHG emissions — carbon dioxide (CO2) and nitrous oxide (N2O) — and thereby limiting electricity production from fossil fuels. The resulting influence of federal, state, and provincial regulation of GHG emissions on the combustion of fossil-fuels for power generation could restrict electricity production in the 2006–2015 assessment period. The potential reliability impacts of GHG limits on fossil-fueled power generation will depend on the transition period for coming into compliance with any new regulations.
pages 110 to 112 – OVERALL WESTERN REGION
WECC (western region)
Demand: Demand response and interruptible loads are about 3,070 MW, with about 2,060 MW of the 3,070 MW in California.
Summer peak demands may increase region-wide by about an additional 2,100 MW above the forecasted peak and about 2,530 MW above the forecasted 2015 peak, should the region experience a hot spell, similar to that experienced on July 9, 1985. For the winter period, a region-wide increase of almost an additional 2,570 MW in 2006– 2007 to about an additional 3,030 MW in 2015–2016 may occur should the region experience a cold spell similar to that experienced on December 22, 1998. The above peak demand weather sensitivities are equivalent to roughly one year or less of normal expected demand growth.
Annual energy usage increased by 1.9 percent from 816,079 GWh in 2004 to 831,570 GWh in 2005
Gas-fired plants were historically located near major load centers and relied on relatively abundant western gas supplies. While a few of the older gas-fired generators in the region have backup fuel capability and normally carry an inventory of backup fuel, most of the newer generators are strictly gas-fired plants, increasing the region’s exposure to interruptions to that fuel source. This is particularly true for California, which is highly reliant on gas-fired generation and has only three plants that maintain dual-fuel capability.
The natural gas supply system within WECC is fairly robust and the region is not highly dependent on external natural gas supplies. However, the western gas transmission system is interconnected with external transmission systems so gas deliveries can be redirected to other regions. Many individual entities have fuel supply interruption mitigation procedures in place, including on-site coal storage facilities. However, on-site natural gas storage is generally impractical so gas-fired plants rely on the general robustness of the pipeline delivery system and firm supply contracts. WECC does not impose fuel supply requirements on its members.
NWPP planning is conducted by sub-area. Idaho, northern Nevada, Wyoming, Utah, British Columbia, and Alberta individually optimize their resources to their demand. The coordinated system (Oregon, Washington, and western Montana) coordinates the operation of its hydro resources to serve its demand. In 2001, the northwest experienced its second lowest Coordinated Columbia River System volume runoff since record keeping began, with reservoirs refilling to just 71 percent of capacity, the lowest levels in almost a decade. Since 2001, the reservoir refill has ranged between 87 percent and 92 percent of capacity.
The reservoirs are managed to address all of the competing requirements including but not limited to:
current electric power generation, future (winter) electric power generation; flood control; fish and wildlife requirements; special river operations for recreation; irrigation; navigation; and refilling of the reservoirs. In addition to managing the competing requirements, other available generating resources, market conditions, and load requirements are considered and incorporated into the decision for refilling the reservoirs. Any time precipitation levels are below normal, balancing these interests becomes even more difficult. A ten-year agreement was reached in 2000 among parties involved in operation of the Columbia River Basin concerning river operations. However this agreement is subject to three-, five-, and eight-year performance checks and reopening by the parties. The net impact of the agreement is a reduction in generating capability as a result of hydro generation spill policies designed to favor fish migration. The capability reduction, which varies depending on water flows and other factors, is reflected in the margin calculations presented in this report. The agreement includes a provision for negotiating changes in the plan under emergency conditions as occurred in 2001.
Fuel — A significant portion of the electric power generated in the Pacific Northwest is derived from hydroelectric generation. Hence, wide variations in annual precipitation, water storage and flow limitations, and other factors significantly affect energy generation from other resources and complicate the fuel planning processes. Coal-fired generation in the area is also very significant. Much of the coalfired generation has near-fuel sources and is often operated in a base-load mode. Consequently, the area is not highly reliant on gas-fired plants relative to annual energy generation and many of those plants are more often operated as seasonal peaking units. Wind-powered generation is increasing rapidly in the area. Since the wind resources exhibit wide fluctuations in output, areas with relatively large amounts of wind-powered generation are investigating potential interconnection limitations as necessary to minimize adverse consequences that may occur.
Transmission — In view of the longer time required for transmission permitting and construction, it is recognized that network planning should focus on establishing a flexible grid infrastructure. This is being done with the goals of allowing anticipated transfers among NWPP systems, addressing several areas of constraint within Washington, Oregon, Montana, and other areas within the region, and integrating new generation. Projects at various stages of planning and implementation include approximately 986 miles of 500-kV transmission lines. Maintaining the capability to import power into the Pacific Northwest during infrequent extreme cold weather periods continues to be an important component of transmission grid operation. In order to support maximum import transfer capabilities under double-circuit simultaneous outage conditions, the northwest depends on an automatic underfrequency load shedding scheme.
Fuel — California is highly reliant on gas-fired generation and has very little alternate fuel capability for these plants. California is also highly reliant on natural gas imports so gas supply is of concern to area energy planners, including the California Energy Commission. The Commission’s September 21, 2005 Energy Action Plan II Implementation Roadmap For Energy Policies identifies eight key actions to address natural gas supply, demand, and infrastructure. The report is available at: