Executive Summary

 For the past decade Wisconsin has enjoyed lower electric rates than its immediate neighbors and, except during 1996 and 1997, an adequate supply.  There are several reasons for this: 

• We built nuclear plants prior to the Three Mile Island and Chernobyl events
• We built several efficient coal plants in the 70s and 80s
• We have a minimal reliance on oil and natural gas for electric generation
• We have invested sparingly in transmission facilities
• Wisconsin has had strong regulatory oversight
• Wisconsin utilities have had good access to capital

But Wisconsin’s electric demand is growing 2% to 3% per year. To reliably meet this growth Wisconsin will need to make extensive additions to its transmission and generation infrastructure.  Our most immediate need is to reinforce the high voltage transmission system, both within the state and the segments connecting us to our neighbors.  At a minimum Wisconsin needs the Duluth to Weston line, another interconnection with Upper Michigan, reinforcement between central and eastern Wisconsin and a new interconnection with Iowa or Illinois.  From a generation perspective we will need to build or import the equivalent of one mid-sized electric generating plant every year.  We also need to maintain an optimal mix of generation types and fuel, and meet evolving environmental standards.  All this must be accomplished while maintaining competitive prices to attract new businesses and retain existing ones. Yet competitive pricing alone won’t make Wisconsin a Mecca for business.  We’ll need a flexible, consumer friendly market structure that will meet or beat what’s being offered in retail choice states.

Electricity – The Fourth Fundamental Necessity

Electricity has become as fundamental in developed nations as food, clothing and shelter.  It is intended to be universally available.  So much so, that in northern states, residential customers cannot have their service cut off during the winter months for any reason.  All aspects of our lives rely on the availability of abundant, low priced electricity.  As consumers we expect to buy all the electricity we want without giving notice to the provider.  We plug in an electric heater, buy another computer, or add an air conditioner without so much as a passing thought as to whether the additional electricity is available.  As a result we continue to become more dependent on electricity in our homes and businesses.

Residential use of electricity per household more than doubled in the last 30 years due to air conditioning, home computers, appliances, and entertainment.  By 2011 the electricity used to power home office equipment will more than double; appliance use will increase by 50% and entertainment use by 33%.  Of the total U.S. electric demand 8% is a result of the development of the internet and computer technology.  Fifteen years ago this demand hardly existed.

In the industrial sector manufacturers are adopting electro-technologies to improve productivity and precision in their processes.  Most manufacturing processes are being optimally controlled with computers.  By 2011 electric demand resulting from manufacturers’ use of digital technology will increase by 61% and account for 12% of all industrial use.  Commercial customers are seeing similar increases as the intensity of electricity use increases in storefronts and office buildings.

These trends account for electricity’s growth rate of 2% to 3% per year.  To put that in perspective, Wisconsin can expect its electric load to increase by 260 to 390 megawatts (mW) per year, the equivalent of a mid-sized power plant.  Obviously, it will take significant investment in generating plants and transmission to meet our growing electricity demands.

Planning for this infrastructure has traditionally been done at the state level by public and private utilities with oversight from state regulatory commissions.  Throughout the United States and Canada, electric systems are designed using criteria in which failure to serve firm load is not likely to occur more than once in ten years (similar to a 10-year flood in storm water runoff management).  In Wisconsin this is accomplished by requiring each utility to have 18% more generating resources than their forecasted firm load.  This planned surplus comes at a cost that is assessed against all customers with firm load.

The cost of electricity is important for several reasons.  For consumers, any increase in the cost of electricity translates into a decrease in the amount of money available for discretionary spending.  This is especially important for low income customers.  In Wisconsin Public Service Corporation’s service area 25% of our customers are classified as low income households.  Paying more for electricity means less money is available for other necessities such as food or rent.  Wisconsin’s low income households typically spend 16% of their income on energy.  To the extent they cannot make ends meet, many will become dependent on the social welfare system with those costs passed on to everyone through taxation.  Of course, good jobs paying a living wage can make it possible for people to rise out of poverty.  Electricity costs are a significant factor affecting the competitiveness of Wisconsin’s businesses and manufacturers and, it follows, that job creation is dependent on their competitiveness.

Assessment of Wisconsin’s Existing Electric Infrastructure

Generating capacity

To assure that all firm load will be served on even the hottest day, Wisconsin regulators require each utility to have 18% more generating capability (capacity) than the load they are obligated to serve. This means that for each kilowatt (kW) of firm electric load the responsible utility must have 1.18 kilowatts of generating capacity.  This capacity may be generation owned by the utility or purchased from a third party.  If purchased from a third party, the utility must have a confirmed service agreement to use the transmission system to deliver the purchase from the generator to the load.  Each April, to ensure that utilities have enough generation for the coming summer, the Mid-American Interconnected Network (MAIN) regional reliability council performs an on-site audit of each utility or load serving entity (LSE) within the council’s geographic region (Illinois, most of Wisconsin and Upper Michigan and parts of Iowa and Missouri).  They review each entity’s load forecast, unit capability assessments, purchased power contracts and transmission arrangements.  Making this forecast can be as simple as applying an inflator to last summer’s maximum load or can be very complex, requiring the factoring in variables such as the area’s economic outlook, customer demographics and trends by load segment, all subject to a normalized weather adjustment.  WPSC uses the latter method that, for the summer of 2003, indicates a weather adjusted peak demand of 2,064 megawatts. While the current audit has not been completed, it appears that Wisconsin will have about 19% reserves.

Energy Adequacy

The resource adequacy process doesn’t reveal information regarding the reported capacity’s energy producing capability.  Not all capacity is created equal.  For instance, much of Wisconsin’s hydroelectric resources is not dispatchable.  Widely fluctuating water levels on flowages are not good for the environment or recreation.  The result is that many of the hydroelectric facilities are run-of-river and those that aren’t, have tight limits on the operator’s latitude to raise or lower water levels in the flowage.  Wind turbines are not dispatchable either, except by a higher authority.  Combustion turbine peaking units are dispatchable but are capped on the number of hours they can operate per year.  Conversely, coal-fired and nuclear steam plants have operating issues that require the units to stay on.  They are not designed for cyclical operation and, therefore, must operate around-the-clock.  Coal units can be adjusted up or down (subject to a minimum operating level) to follow changes in load but nuclear plants cannot be cycled at all by order of the Nuclear Regulatory Commission.  They start up after a re-fueling and are expected to operate continuously at their rated output for 18 months. 

This can be quite complicated, so industry participants developed terms to simplify it. Generating resources are generally described as base load, intermediate and peaking capacity.  In general base load capacity is operated continuously.  Intermediate capacity is dispatched on a day-ahead basis for a specified period of time, up to 16-hours a day.  Peaking units are used to meet short-term load peaks or to replace other generation that’s force off for repairs.  They can be started on short notice with some able to achieve their full output in as little as ten minutes.

Cost implications

While the capital cost of generation increases as one moves through the spectrum from peaking to intermediate to base load capacity, fuel cost per kilowatt-hour decreases.  Using peaking capacity as an intermediate or base load resource is fuel intensive and expensive at today’s natural gas prices.  Alternatively, using base load steam facilities as intermediate resources (they cannot be used for peaking purposes) is capital intensive and requires more maintenance due to excessive thermal cycling.  From an energy standpoint, the optimal economic solution is to have a mix of types of generation to meet customer needs.  In a typical week WPSC needs about 1,300 mW of base load energy, 300 mW of intermediate energy and 100 mW of peaking energy.

Having the right fuel mix is also important.  Even though combined cycle generation is 25% more efficient than steam plant generation, it is not an economical choice for base load energy due to the high cost of natural gas.  WPSC’s capacity and fuel mix is well matched to its needs.  The same can be said for the state as a whole, although that is changing as we rely more on natural gas than in the past.  We constructed a number of efficient base load coal and nuclear steam plants in the 70’s and 80’s.  In the 90’s as natural gas became more plentiful we added combustion turbines.  In the late 90’s, we added our first combined cycle facility.  Most of the state’s 18% reserve requirement is met using natural gas or oil-fired peaking resources. 

With respect to capacity, renewable generation recently has been added to the state’s portfolio. This type of resource is meeting the public’s desire for environmentally friendly generation and makes use of wind and fuel resources. WPSC has two wind generation facilities in Eastern Wisconsin, a 9 mW facility in the Town of Rosiere in Kewaunee County and a 1 mW facility in Southeastern Brown County.  The economic effect of a wind resource is difficult to quantify because it’s difficult to predict when and how much energy will be generated.  Operators use day-ahead weather forecasts to predict the next day’s load and the energy production from wind and hydro facilities.  Using that information they create a “least cost” dispatch plan to serve the forecasted load, using the generation and purchases available to the system.  If the planned energy doesn’t materialize because the wind doesn’t blow or a fossil unit is forced off line due to a breakdown, replacement energy, typically from expensive peaking generation, will be called on.

For the Midwest region, wind resources do not have the benefit of mountain induced thermal effects.  The unpredictability of the resource is a significant problem that offsets some of its value.  For example, if system operators could accurately predict those days that energy wouldn’t materialize, they could call on an intermediate resource with a 40% efficiency advantage over peaking generation and, as a result, incur significantly lower system costs.  Using principles of accounting in which cost causation is appropriately assigned, this cost should appear on the wind resource ledger.

Some argue that this is no different than the forced outage of a fossil plant.  This is true only if the reliability of the wind forecast, as determined using accepted statistical analytical methods, is equal to or better than the similarly calculated reliability of the dispatchable unit.  WPSC’s experience does not support that premise.  Additionally, the MAIN regional reliability council does not consider wind resources to be part of capacity.  Because wind is not dispatchable and has a known probability of producing no energy, they believe it cannot be counted on to help maintain the reliability of the system.

Other sources of energy generated by renewable resources include closed-loop biomass and utilization of waste stream products such as landfill gas and methane generated using livestock manure. WPSC believes these evolving technologies offer many opportunities to develop environmentally friendly generating resources that are economical and help the reliability of the state’s electric grid.  WPSC has developed several landfill and dairy farm gas generation projects and expects to add more in the future.

WPSC’s existing fleet of coal generators is aging.  Seven generators with a combined capacity of 380 mW are more than 40 years old.  They are well maintained but are not as efficient as newer, larger plants.  The remainder of the coal generators, totaling about 900 mW are in good shape, well maintained and reasonably efficient.  The Kewaunee nuclear plant is licensed until 2013.  WPSC is studying the viability of seeking a license extension.  A decision is expected within two years. 

Increasingly stringent emission requirements are creating an economic sunset for some of WPSC’s coal plants.  Proposed tighter restrictions for nitrous oxide and mercury emissions would require the addition of expensive control technologies.  The cost to retrofit some of the smaller units would be prohibitive.  In addition, the room needed to add these technologies is simply not available at some of the facilities .

Fuel Availability and Deliverability

Wisconsin’s generating resources are fueled with enriched uranium, eastern and western coal, natural gas, and diesel fuel.  None of these fuels are indigenous to Wisconsin.  Almost all of the coal WPSC uses is mined in Wyoming (western coal) and delivered by rail.  Eastern coal can be shipped in by rail or, for generating facilities located on Lake Michigan or Lake Superior’s shore, by lake freighter.  Natural gas enters the state from the south, west or north in interstate, high-pressure gas pipelines.  Fuel oil is brought into Wisconsin either by pipeline or truck and delivered to the generators by truck.  Except in rare circumstances deliverability for all fuels has not been a problem.

Western coal used in Wisconsin generators is primarily sub-bituminous coal mined in the Powder River Basin (PRB coal) in Wyoming and Southeastern Montana.  It contains between 8 to 9 thousand BTU’s per pound and has lower sulfur content than most eastern bituminous coals.  In 1990, citing research that indicated sulfur dioxide was a primary culprit in the formation of acid rain, the federal government tightened sulfur emissions limits and created the concept of an emissions trading market.  This made it possible to determine the price of emitting sulfur and provided the means to economically compare alternative sulfur dioxide control strategies.  Although there were several technical problems to solve, burning lower sulfur western coal instead of eastern coal became the control method of choice.  The emissions market created an economic reward for those companies that can achieve immediate reductions in emissions.

Boilers designed to burn bituminous coal that could not achieve their full rated generating capability on 100% PRB coal remains a persistent problem.  The loss is as much as 10%.  In situations where generating capability is important operators typically blend coals or co-fire natural gas with PRB coal to minimize or eliminate unit de-rates.  By any standard the emissions trading program was an immediate economic and environmental success.  Most coal-fired electric generators in the Midwest are now using Powder River Basin Coal.  The railroads have adequate capacity to serve today’s need plus some growth.  Proposals to add a new railroad from the Powder River Basin region are being considered. 

PRB coal reserves should be adequate for at least 50 years based on current consumption forecasts.  Because the coal lies in relatively thick veins close to the surface low cost open pit mining techniques are used.  After the coal is removed the land can be satisfactorily reclaimed by re-distributing and leveling the overburden to re-create grazing land.  Eastern coal is more difficult to mine and, therefore, more expensive.  Primary sources are the central Appalachian Mountains and the lower Ohio River Valley.  The eastern reserves are generally deeper, making open pit mining more intrusive and expensive.  Alternatively, some coal is still mined using conventional underground mining techniques.  These regions contain abundant coal resources but the economic and environmental cost is greater.  Rail and lake shipping to Wisconsin from these regions is adequate.

Natural gas used in Wisconsin electric generators is primarily sourced from production wells in the Gulf of Mexico, Texas, Oklahoma and Alberta, Canada.  It is delivered via several large interstate, high-pressure pipelines.  At this time the gas transportation system into Wisconsin is adequate to support both our thermal and electric generation need.  Presently, WPSC is entirely dependent on El Paso Corporation’s ANR subsidiary for natural gas transportation service into and within its service territory.  WPSC believes competition for this service would be desirable and, therefore, willingly evaluates proposals for alternative transportation service.

In Wisconsin, combustion turbines are typically designed for firing with either natural gas or fuel oil.  This allows the operator to use interruptible natural gas transportation service at a much lower cost than firm service.  When natural gas isn’t available fuel oil can be used.  Typically, this only occurs when Wisconsin temperatures are at or below zero during the day.  To make sure that the units can be dispatched during episodes of cold weather, peaking units have enough fuel oil storage on site to operate for about 40 hours.   Combined cycle facilities that have dual fuel capability may or may not have firm gas transportation service.  As a concession to the fact that they are more likely to be operated every day, additional on site fuel storage may be required.

Transmission

Two recent events have changed the transmission landscape in Wisconsin.  First, early in 2001 all Wisconsin and Upper Michigan transmission facilities lying within the MAIN footprint and operating at 50,000 volts (50 kV) or higher were turned over to the American Transmission Company, LLC (ATCLLC).  In assuming ownership they took on the responsibility to maintain existing facilities and plan, permit and construct new ones.  The second important event was that the Midwest Independent System Operator (MISO) assumed operating responsibility for the ATCLLC facilities along with several other transmission systems.  The MISO is located in Indianapolis, Indiana and covers most of the Great Lakes States, the Northern Plains, Missouri, Manitoba and Saskatchewan. 

The backbone of Wisconsin’s system operates at 345 kV although the state relies heavily on lower voltage lines to serve most of its load.  Wisconsin has four 345 kV interconnections with other states, three to Illinois and one to Minnesota.  According to MAIN this is not adequate even for reliability.  In their Summer 2003 Adequacy Assessment they describe Wisconsin’s interconnections with other states’ electric systems to be deficient by more than 200 mW to support the Wisconsin system in the event of an unexpected loss of generation in the state.  This is based on Wisconsin utilities’ plans to import slightly more than 900 mW of capacity this summer.  In addition to reliability concerns, there is the potential for economic harm to Wisconsin electricity consumers.  There’s a price war for capacity in Illinois and, even though WPSC needs capacity for this summer, we cannot get transmission service to import it.  Instead we will lease diesels for the summer at a significantly higher cost than Illinois capacity.

It’s not just Wisconsin consumers that are economically harmed by Wisconsin’s deficient transmission system.  The Minnesota/Wisconsin interconnection is one of the top 5 congested transmission elements in North America as measured by the frequency of service curtailments.  When the line is approaching its operating limit, over 2,200 potential transactions that could place additional load on the line are not allowed to flow.  These transactions include generators and load as far away as Tennessee, Ohio, and Oklahoma.  The risk is a cascading blackout that could shut down the entire Upper Midwest.

Distribution System

The distribution system is adequate to serve existing load in most areas.  As more people move to areas of Northern Wisconsin that have been sparsely populated Wisconsin line upgrades and new substations will be needed.  Power quality is becoming more important to customers as they adopt digital technologies.  Long distribution feeders passing through wooded areas are problematic for maintaining power quality.  Responding to these concerns, WPSC has upgraded most of its rural feeders to minimize costs and maintain voltage to a stricter tolerance.  WPSC’s 20,000 miles of distribution lines require continuous maintenance.  Line clearances, clean power, minimizing outage times, protecting public safety are just a few of the critical tasks that must be done as part of that effort.

Security

The events of September 11, 2000 coupled with conflict in the Middle East have created concern about the security of the United States’ critical infrastructure.  In particular nuclear generating plants, critical transmission facilities and information technology venues are considered vulnerable to terrorist attack.  WPSC has facilities that fall into each of those categories.  Security is at an all time high at the Kewaunee plant.  At our other critical facilities increased security and surveillance has been implemented.  This has also been the catalyst to build and staff a remote system-operating center that will provide a secure backup for our Green Bay system operations center.  Ground was broken for this project in March 2003.

Regulation

The Public Service Commission of Wisconsin (PSCW) is still very much engaged in regulating its utilities.  They use a traditional cost-of-service business model to guide their decisions and have authority to regulate all facets of the state’s electricity system from the siting of generating plants and transmission lines to deciding utility boundaries and who serves whom.  The state does not appear willing to allow any form of retail access in the immediate future.

The wholesale market (utility to utility purchases and sales) is regulated by the Federal Energy Regulatory Commission (FERC).  Jurisdictional studies are used to determine cost allocations between the retail and wholesale markets.  Wisconsin uses the Strategic Energy Assessment (SEA) process to evaluate the adequacy of the state’s electric infrastructure.  Governor Doyle recently announced his preference for expanding the scope of the SEA effort.  Presently, federal legislative efforts are being considered that would usurp some of the state’s rights to regulate transmission.  One of the most controversial issues is the creation of federal rights of eminent domain to site interstate high voltage transmission lines.  That concept is included in a proposed comprehensive energy bill that will be considered by the full House and Senate in 2003.  Giving the FERC this right is intended to deal with states and regions that are unwilling or unable to build needed transmission infrastructure. 

Financial condition of utilities and other electric market participants

With the meltdown of Enron and the effects of the California debacle many utilities, independent power producers (IPP), and electricity merchants have been downgraded by rating agencies, some to junk status.  As a result they are experiencing higher capital costs and liquidity in electricity markets is at a small fraction of what it was in 2000.  The effects are too many to discuss in this paper but the result is that the landscape for financing generating projects has profoundly changed.  Instead of an almost complete reliance on non-utility generating projects to meet growing electric demand, financially strong utilities are now proposing conventional rate-based projects.  The capital markets appear willing to re-embrace this trend.  Utilities benefit by getting supply certainty plus investment opportunities.  Consumers get electricity at predictable prices.  In Wisconsin, both WeEnergies, with their PTF-2 projects, and WPSC, with its Weston 4 project, are choosing this path.  The rating agencies rank WPSC as one of the best utilities in the nation meaning that capital should be readily available at competitive costs for the Weston 4 project.  S&P presently rates WPSC bonds at AA- while Moody’s rates them at Aa1.  Public utilities such as Municipals and Coops have also faired well over the past two years with most still enjoying good credit ratings.

Meeting Wisconsin’s Growing Electric Demand

Transmission

Wisconsin’s most critical need is for more high voltage transmission.  Several generation projects including the PTF-2 units and Weston 4 have been proposed but no significant transmission line except for Duluth to Weston has been proposed.  This has paralyzed generation development because even if the ATCLLC allows the project to be interconnected to the grid, potential customers and utility systems can’t get rights to move the power to their load until a major system upgrade is performed.  As a result generation developers are forced to design their projects around the transmission constraints rather than to build the most economical projects.  Projects that would solve this problem are the Duluth to Weston line, another interconnection with Upper Michigan, reinforcement between central and eastern Wisconsin and another interconnection to Iowa or Illinois.  Most of this infrastructure needs to be operated at 345 kV and could be sited on existing lower voltage transmission rights of way.  These projects would be expensive, about $1 million per mile.

There are several smaller projects that could improve our ability to share power with other utilities within the state.  The ATCLLC recently published a comprehensive ten-year plan in which they proposed several of these projects.  However, from WPSC’s perspective the plan is deficient in several areas and will not create a system that will be robust enough to ensure that consumers in our service area will have access to high liquidity electricity markets.  Without an adequate system, continued strong regulation will be needed to protect consumers from market abuses.

On the other hand, transmission facilities are intrusive to the residents and landowners in their path.  They have a right to make their objections known and offer alternatives.  But the physics of the electric grid and the laws of economics will not change because of these objections.  Ultimately, transmission siting and construction will be major factors in the competitiveness of Wisconsin’s business climate.

Generation need

Depending on generating plant retirement assumptions and load forecasts, Wisconsin will need to build as much as 6,000 mW of generation over the next 10 to 12 years.  

As discussed previously there are several types of generation and Wisconsin needs some of each type.   Base load generation will be the most difficult type to build in Wisconsin.  Our citizens’ strong environmental ethic will require an open and honest airing of all issues during the permitting process.  The PTF-2 coal units and Weston 4 would provide enough base load generation (about 1,500 mW) to meet expected load growth and a minimal number of plant retirements.  If these announced projects get scaled back, more plants are retired than currently assumed, or the economy is stronger than expected additional base load generation projects will be needed.

Currently, there are three primary technologies available to use coal to generate steam for electric turbine generator facilities: 1.) Circulating fluidized bed (CFB). 2.) Pulverized coal (PC). 3. Integrated gasification of coal (IGC).  CFB boilers mix limestone and ground coal or other solid fuels and burn them together.  The limestone bonds with sulfur and other pollutants and its lower combustion temperature limits the formation of damaging nitrous oxides.  Presently, the proven maximum size of these generators is about 250 mW.  A downside to these units is they create twice as much ash as PC units.  The capital cost is about the same as for a PC unit but operating costs are higher.  IGC technology is a two-step process in which volatile gas is extracted from coal in an oxygen-starved environment and then used as fuel in a combustion turbine.  At this time it is not currently considered a proven technology and yields a higher volume of ash.  On the positive side its emissions are about the same as those from natural gas.

PC generation is still the design of choice.  It can be sized up to 1,000 mW offering significant O&M economies of scale.  New units are typically operated in super-critical mode yielding efficiency gains of about 7% or 8%.  Ash volumes are the lowest of the three technologies and, depending on coal type and emissions control technology, may be beneficially re-used as a replacement for cement.  Coal is abundant and inexpensive in North America and expected to remain so.  The cost for CFB or PC base load generation is about$1,500/kW.  Two of the PTF-2 units and Weston 4 will be super-critical PC units.

Much of Wisconsin’s capacity requirement will be met using gas-fired combustion turbines constructed as simple or combined cycle units. The operating characteristics of these units allow them to be more responsive to changing prices and system conditions making them ideal technologies that fit IPP and electricity merchants’ business models.  As a result WPSC anticipates that IPP’s will build combined cycle and peaking projects in Wisconsin.  However, utilities will continue to need some small, fast-start peaking units for system reliability.  IPP’s typically need economies of scale and, therefore, prefer to install larger machines.  Utilities responsible for grid reliability and merchants trying to protect against volatile prices will build small peaking units.

The public demand for renewable generation is increasing.  Wisconsin utilities are required to secure 2.2% of the energy needed to serve load from renewable generation by 2011.  WPSC already has more than enough renewable generation to meet that requirement and intends to secure additional cost-competitive renewable resources.  WPSC is certain it will be able to meet any reasonable increase in the minimum renewable requirement.

One concept that would encourage investment in renewable projects would be the creation of a regional or national market to trade “green” credits.  Because renewable generation projects are generally small it is difficult to physically move energy to customers that want to buy it.  Instead, there is a proposal to develop a market to sell credits for energy certified as having been generated by renewable resources.  Entities or individuals wanting to support the development of renewable generation projects could purchase these credits.   

Cost Implications of Infrastructure Improvements

Infrastructure improvements will increase the price of electricity.  The rate of increase depends on the choice and timing of the improvements.  The cost associated with transmission upgrades was discussed earlier.  The capital cost of generation additions will further increase the price of electricity in Wisconsin.  WPSC has a planning department dedicated to evaluating different options in an effort to find lowest cost/best value for resource additions.  Assumptions made regarding fuel prices, project capital costs and O&M costs can significantly affect the outcome of their studies.  They update assumptions on a regular basis using two or more sources to protect against any inherent bias.  Presently, WPSC is assuming natural gas costs will be almost five times greater than coal prices; coal price increases will track the rate of inflation while natural gas prices will increase at a slightly higher rate.

Project capital costs are the other major component of the electric price equation.  WPSC estimates the capital cost of base load generation at about $1,500/KW, combined cycle at about $800/KW, and peaking at $475/KW.  Using today’s assumptions for fuel cost, the fuel and variable O&M cost per kilowatt-hour or energy for each generation type is $.013 for base load, $.04 for combined cycle and $.058 for peaking.  Combining those costs with capital costs allocated over the expected energy output from each generating type, the all-in cost per kilowatt-hour is $.044 for base load, $.066 for combined cycle and $.13 for peaking capacity.  Even if one assumes energy was supplied 100% of the time from each generating type, all-in per kilowatt-hour costs would be $.0375, $.054 and $.066 respectively.  This illustrates why it is important that coal continues to be the primary fuel used to meet Wisconsin’s base load need and why Weston 4 is necessary to keep WPSC’s costs competitive.

The cumulative effect of transmission upgrades, ATCLLC and MISO costs, generation additions, and security fixes suggests that electricity rates will increase at rates greater than general inflation.  How much greater will depend upon the choices Wisconsin makes and when they make them.  Rates will not increase at a uniform rate.  A project’s benefit is realized only after capital has been invested.  While rates increase during the construction, benefits from the project will not be realized until it is commercially available.

Restructuring of the Electric Industry

Wisconsin cannot remain aloof from the clamor of electric restructuring.  Over the years the term restructuring has had several meanings: retail wheeling, open access, customer choice, de-regulation, and so on.  Currently, the FERC’s Standard Market Design (SMD) effort is the poster child of restructuring.  The FERC is intent on creating an electricity market with standard business practices that will be attractive to at-risk capital.  They intend to create geographically large electricity markets to replace the existing balkanized system with its inherent inefficiencies.  In the FERC’s vision everyone would be able to use the transmission system at any time similar to the way the interstate highway system is used.  The cost of congestion would be determined by market forces and assigned to those creating it. 

Because grid congestion is unpredictable we expect its market determined price will also be unpredictable. The solution will be to create hedging instruments to manage that risk.  Initially they will be granted to the incumbent holders of physical transmission rights.  Eventually, the incumbents will be required to sell them in an open market making them available to whoever values them most.  The assumption is that when these costs are known, the market will find ways to reduce congestion.  Economists believe this will stimulate innovation and least-cost solutions to mitigate grid congestion.

The SMD concept is not without risk.  The results of California’s experiment in restructuring are well known.  As a result the western and southern states are vehemently opposed to the SMD concept.  Presently there are several SMD type markets operating in the United States in the Northeast and Texas.  As mentioned earlier, the MISO is intending to implement such a market by December 1, 2003.  This will have a profound affect on the Midwest’s electric industry.  It will be structured as no other ISO, so as to accommodate existing utilities’ and state regulators’ desire to maintain established service territories.  Although other ISO’s accommodate the concept of defined service territories they operate their system as a single control area.  The MISO member companies are not yet ready to embrace that concept.

The Cost of Restructuring

If the consumer doesn’t see lower costs than they would have seen if we continued with the present model, restructuring will be a failure.  However, that comparison will be subjective because we’ll never know the path not taken.  In the long run a market that can provide accurate, transparent prices should be more efficient.  This means that during most hours the least-cost generation dispatch decision will be based on all of the resources in the ISO where, in the past, dispatch was based only on each utility’s resources. Compared to the entire ISO, each utility’s decisions may have been sub-optimized.  As an example, a situation could occur where one utility system was dispatching gas-fired combustion turbines while another had excess gas-fired combined cycle generation.  At today’s natural gas price, that would be $.02/kW-Hr price difference.  Other benefits of a liquid, transparent market are better capital allocation decisions and more effective risk management tools.  Although restructuring a market will create costs in the short run, long run market efficiencies should create offsetting benefits for the future.

Conclusion