Market forces are creating a power delivery squeeze on Midwestern utilities, causing them to carefully consider their power generation mixes as older generation and transmission assets reach the end of their useful lives.
From 1996 to 2016, transmission investment jumped from less than $4 billion to more than $20 billion, creating a crunch on utilities striving to keep rates stable (U.S. Energy Information Association).
What’s behind the increase? After the 2003 Northeast Blackout that resulted in 50 million people being out of power for two days causing 11 deaths and costing $6 billion, the U.S. Congress put new reliability standards in place. It is part of the reason for higher transmission costs, which started spiking in 2006. Older asset replacement, improved monitoring, controls and switching technology and accommodating renewable energy is also part of the picture.
Government data shows the largest expenditures are related to power lines – overhead conductors, poles, fixtures, towers and substation equipment. Regional transmission organization fees have risen swiftly as well. The EIA forecast calls for flat generation prices – thanks to low natural gas costs – for the next decade with a slow growth in transmission investment. Most of the costs can be passed through to customers, but in a distributed energy world where customers have more generation choices, utilities are better served to keep costs down.
The power gen dilemma: Coal and nuclear are out, natural gas in. What about renewable energy?
Each Midwest utility’s situation is unique, but there are three or four typical scenarios and power generation mixes:
Type 1. No generation. Purchase from wholesale market via contract.
Type 2. Smaller market. Some generation.
Type 3. Larger market. Some or mostly self-generated, purchase from wholesale market for rest.
Type 4. Self-generation. Self-generates or owns shares from major generation facility and receives allotted power supply.
Market conditions for both power generation and power delivery present opportunities and challenges for Midwest utilities. The first and most important question owners should ask is should they own, co-own or buy generation from the market?
Next comes an analysis of a realistic expectations from existing assets; the type of future you are planning for; what assets you will need and how you value reliability and resiliency. Only then can a utility decide a course of action.
Case study: City of Lebanon, Ohio
To understand how to approach the power gen dilemma, it is illustrative to look at the city of Lebanon, Ohio. We performed a detailed municipal utility study for Lebanon, a city of 25,000 located in the Cincinnati metropolitan area in southwest Ohio. Lebanon’s municipal utility illustrates both the opportunities and the challenges presented by today’s power markets. Lebanon asked us to study its alternatives and consider renewable energy generation.
Lebanon’s issues are applicable to many Midwest utilities: It has a long history of self-generation; owns and operates mostly older generation assets with minimal incentive to invest in new generation and renewables are starting to have an impact. Dispatch patterns on non-renewable generation are driving the need for more flexibility, and, finally, transmission costs are rising.
The renewable energy impact has just begun. For example, the Midcontinent Independent System Operator (MISO) projects that renewable energy additions in its system – less than 20 GW in 2017 – will rise every year and total 35 GW in 2021. Renewables significantly impact both transmission and generation operations.
Lebanon’s peak load is 75 MW, maintained by power supply contracts with the grid and a fleet of dual-fuel combustion turbines and reciprocating engines ranging in ages from 50- to 78 years, used for emergency generation. During the past decade, the city followed the national trend of higher transmission and distribution investment and paid higher transmission fees to the grid as well.
Given the age of its fleet, Lebanon faces either replacing it or buying most of its power from the grid, a scenario that can lead to sudden and sharp cost increases that get passed to the customer base. Lebanon needed to understand what type of future it was planning for by analyzing contemporary trends and forecasts.
Forecasting has its risks
Forecasting is a tricky and often fruitless business. For example, a 1973 forecast for the year 2000 by a high-level government and industry committee predicted coal would be 20 percent of U.S. generation, oil 10 percent, natural gas 3 percent and nuclear 62 percent. The 2000 actual numbers were 52-, 3-, 16- and 20 percent respectively.
By 2030, transmission costs are projected to grow from 1.32 cents per kilowatt hour to 1.57; and up to 1.64 by 2050, according to EIA’s Energy Outlook. The agency’s economists predict distribution costs to rise from 2.98 cents per kilowatt hour in 2017 to 3.7 in 2030 and 3.73 by 2050. Generation costs are predicted to drop. Natural gas is expected to stay stable for 10 years and reserve margins for most regions are considered more than adequate, even with coal retirements, according to NERC’s 2017 Long-Term Reliability Assessment.
If transmission costs are going to rise, Lebanon will consider strategies to minimize those costs. The major component of future transmission charges from the power pool are for capacity and demand and importing less energy would reduce those charges. For example, Lebanon could have saved $580,000 in transmission charges by importing 10 percent less energy in 2017.
The city could reduce usage through demand reduction programs, but its customer mix would not allow a large enough total percentage reduction. It could run peaking generation at expected peaks, run base load generation to continuously reduce the amount of electricity that is imported, build a new transmission line to a different generation node, or install energy storage to use during peak hours to minimize imported power.
Generation options limited in the Midwest
The city of Lebanon made the following considerations for future generation: non-renewables renewable energy, regulatory issues, financing and cash flow and battery storage.
The study team eliminated nuclear, coal, fuel oil and diesel and combined heat and power because of cost and scale. Combustion engines, simple cycle combustion turbines were considered, both new, retrofit of current assets and the grey or aftermarket.
As for renewable energy, photovoltaic and wind are the only options, because there is no local resource for biomass, geothermal, hydroelectricity, concentrating photovoltaic and concentrating solar thermal energy.
Financial considerations and modeling
Stanley Consultants built financial models on several different alternatives, including four alternatives using either combustion gas turbines and reciprocating combustion engines, all producing close to the 20 MW of power that would reduce transmission costs. Four other scenarios involved a full 20 MW of solar power on purchased land, the same including battery storage, 1.5 MW on city-owned land and 2.3 MW on city land. The chart below shows the relative capital costs of each approach. The models considered such factors as inflation, projected natural gas prices and the low amount of solar irradiance and intermittent wind in the region.
Source: Stanley Consultants
The models showed that the payback period on the generation assets did not vary greatly. The shortest payback period was 8 years on grey market Warsila engines; the longest 14.2 years on the small solar on city property. Most of the rest of the options would pay back within a couple years of each other.
Engineers prepared “tornado charts” that illustrated how different generation decisions would be affected by a plus or minus 20 percent change in a variety of market variables. From the tornado charts, the high sensitive variables were put through a parametric analysis to investigate impact on payback from potential ranges. Bill escalation rate, capacity factor and natural gas prices can affect the economic feasibility of self-generation. In other words, a small bill escalation rate, a spike in natural gas prices or low capacity factor may not justify self-generation. However, if general trends continue, the parametric analysis shows benefit from running a 30- to 40 percent capacity factor on overall payback.
Source: Stanley Consultants
Financing. Lebanon has $10 million in its electric fund. If it chooses to spend that, it would have to finance 60 percent of the remaining $20-plus million cost if the city chose to build a 20 MW facility as part of the 3-year plan. There are many benefits to financing for project funding. The project can be completed sooner and provides revenue and self-generation benefits sooner. Also, due to the current generation market, there is a buyer’s market for gensets and financing can allow city to take advantage of low prices and good lead times for RICE (reciprocating internal combustion engine) gensets.
Stanley Consultants also developed a 10-year plan for building a 10 MW facility with provisions for adding another 10 MW in year 10. The funding gap is in consideration of the city’s cash flow.
Permitting. Operating existing generation assets more than just in emergency and backup situations would have regulatory and permitting impacts, with respect to both the Ohio EPA and federal EPA. Similarly, adding new generation in the form of new combustion turbines or reciprocating engines would also have regulatory and permitting impacts. With respect to new generation options, new greenfield sites were considered and not expanding generation at the current site. The simple cycle combustion turbine option offers the most operational flexibility to avoid a major source operating permit. A new combustion turbine would require on-going annual performance testing to demonstrate continuous compliance with the NOx standard.
Energy storage. Don’t expect 50 percent drops in battery costs going forward. The way the market’s going, the City of Lebanon would need four hours of storage with a 7.5 MW load. If the peaking system is 10 MW or less, storage might have an application. For larger utilities, cost makes storage difficult.
The three basic options to consider as part of the upcoming capital planning schedule are:
Option 1 – Decommission existing generation, monitor wholesale market conditions and add new generation when generation becomes more cost-effective, with payback in 5- to 7 years. Continue to purchase power off the market as contract prices have declined. This option is a short-term approach that avoids issuance of debt and the risks associated with capital investment. In the event new generation is decided upon, it will be difficult to cost-effectively time the investment.
Option 2 – Decommission existing generation, move forward with 10 MW of new generation ($15.7 million) and plan to begin installing an additional 10 MW of new generation in year 8 ($8.5 million). While this option lowers the maximum capital investment in any one year, it will add more capital cost by breaking the investment into two phases versus one.
Option 3 – Decommission existing generation, move forward with 20 MW new generation ($23.4 million) using financing for a portion of the investment. This takes advantage of low new generation demand and better prices for equipment and services.
The City of Lebanon chose to perform an electric rate analysis in early 2019 and use that information to choose either option 2 or 3.
Like other Midwest utilities, considering their delivery node within the Midwest grid, renewables are not a slam dunk decision. Reliable, cheap coal generation abounds in the region, despite many coal plant retirements, and therefore remains an attractive choice.
Likewise, after being in business for 100 years, conservative Midwest utilities don’t want to be at total risk to inevitable market fluctuations. They want to retain some control of their rate structure and to fulfill commitments to their customers. The Lebanon City Council understood and approved the plan to retain some control over power generation. That scenario is likely to repeat itself in other Midwest cities during the next decade.
About the authors: Joe Jancauskas, P.E., is an electrical power consultant with Stanley Consultants in the firm’s Denver office. He has more than 30 years of experience in the design, analysis, construction, modification, operation, maintenance and asset management of power systems. He also served as a national spokesperson for the industry as an expert for the U.S. Council for Energy Awareness.
Matt Irvin, P.E., is a mechanical engineer with Stanley Consultants in the Denver office. His experience includes design engineering, feasibility studies, plant decommissioning planning and engineering, plant condition assessments, controls design, owner’s engineer services, expert witness testimony and performance testing and tuning.