Is Our “Modern” Electricity Market Failing Us?
Joint utility interests promised lower prices and faster transition to renewable energy through the historic creation of the MISO electricity market. After twelve years, the move has produced economic and environmental setbacks.
On April 1, 2005, the Midwest Independent Transmission System Operator (MISO) began operation of the world’s largest market for trading electrical power using an increasingly inter-connected transmission system spanning 11 midwestern U.S. states. Today, the market spans all or parts of 15 states, the province of Manitoba, Canada and is re-named, Midcontinent Independent System Operator.
Utility pressures to make the grid bigger and to increase reliance on it started in the early 1990’s. FERC Order 888 in 1996, opened the existing system to access to all utilities arguing it would allow utilities at considerable distance to sell and buy power at reduced costs and then pass savings to customers. Utilities cited 1990s examples such as retail power costing 6 cents per kWh in North Dakota and 10 cents per kWh in Illinois. The possibility of a larger grid increasing consumption of renewable energy was mostly rumored in environmental settings because utilities and their financial partners were not ready to tell their investors that the billions they recently invested in coal and natural gas plants would soon be playing second fiddle in utility PR.
Utility watchdog organizations and engineers observed that supply and demand forces would soon level-out electricity price differences. Utilities successfully countered that the sheer existence of day to day price bidding would insure maximum competition between utilities and lowest possible prices for all. Absent from the debate in the Midwest was the fact that the new market would join forces of more than 50 companies who build, operate and maintain transmission lines and provide these companies majority interest in the deployment of the “the world’s largest machine,” under the auspices of MISO.
With a few clicks on Department of Energy spreadsheets, one can make graphs showing the performance of the electricity market in the Midwest thus far.
A dramatic change in the trend recorded before 2002 is clearly visible. From the first stages of states entering the market, 2002-2005, through 2016, average residential rates In Wisconsin climbed three times faster (5.1% per year) compared to 1.7% per year before influences associated with the market phased in.
Questions arise: Could the cost of generating power from 2002 to 2016 have steadily increased for some reason? Did a huge utility rush on the new market exceed market’s capacity-- the ability of the transmission to support increased trading?
Graphs plotting day to day 2006-2016 trade prices and volume data at a key MISO market “hub” contradict these possibilities. As retail rates soared, the average cost of wholesale, traded power was steadily declining-- to nearly half the wholesale price by 2016.
This means as end cost paid by electric customers over the decade rapidly increased, the price utilities could pay for traded power was decreasing. Instead of a steady rise in market volume, use at the hub peaked in 2008 and by 2016 was only 10% of historic peak.
Economically speaking, the new electricity market produced brief, modest, growth followed by a prolonged decline in relevance This prompts even more questions.
Have utilities since 2008 generated more and more of the power they sell to their customers? If so, did this happen because utilities were encouraged to keep their own power plants running to sustain cost recovery on these investments as electricity use flattened and declined due to increasing energy efficiency? Note that a steady decline in wholesale prices with decreasing use of transmission capacity should have lowered rates as utilities promised. One has to look elsewhere for explanations.
"Recent retail electricity price trends have also been driven by capital expenditures (CapEx), which have risen sharply in recent years. Annual capital spending in the electric power sector roughly tripled from 2000 to 2015, with transmission and distribution investments representing the vast majority of that growth. As these investments enter utilities’ rate bases in subsequent rate cases, the associated costs are passed on to ratepayers. Accordingly, annual depreciation and financing related expenses by major electric utilities grew by roughly 50% over the same time span.” - Galen Barbose, Lawrence Berkeley National Laboratory, January 2017. p.10
"Energy rates continue to increase across customer classes both in Wisconsin and the Midwest. Rate increases are generally driven by sales decline, transmission, generation, distribution and renewable investments, increased federal regulation of pollutants, fuel price volatility and purchased power costs, as well as the high fixed-cost nature of the utility business.” - Public Service Commission of Wisconsin, p.4 SEA 2020, REF#220557
State Level Activities
As customers and state regulatory agencies struggled to understand the profound implications ushered in by the creation of the electricity market, business interests standing to profit from increased dependency on the grid furiously lobbied government and eventually convinced the courts that it was equitable to spread the known, high costs for grid expansion across most, if not all of the 24 million electric customers in the MISO market. None of this strategy was peer evaluated by impartial parties when court-approved regional of cost allocation provided the accelerator.
The first, large-scale promotion of the new, cost-sharing rate design was a 2011 package of seventeen, high capacity transmission facilities coined, “Multi-Value-Projects. The design was created by utility-interests from 2008-2010, who later conducted the need analysis under the banner of MISO. Timing was key. The MVP promotion was launched before any of the first expansion transmission experiments states had approved could demonstrate overall economic savings as required by state law [ Wis. Stat. § 196.491(3)(d)(3t) ] .
The MVP line proposals, made individually to state PSC’s, proved highly challenging for staff and public intervenors to test for potential benefits. Instead of justifying each project uniquely, the MISO report inexplicably assumed that all 17 lines would be built. Then, potential benefits were calculated under high-growth, future scenarios averaging more than 1% per year although use from 2007 was flat or in decline. The reason for the decline was being attributed to improvements in efficiency rather than a slowed economy at the very same moment states were approving MVP proposals based onirrelevant assumptions.
In none of the formulated “economics” does MVP forecasting inform ratepayers what benefits they would see if the same billions did NOT go into transmission expansion but instead to dramatically accelerate spending on energy efficiency, load management and the development of local renewable energy. These "end user" investments have little or no impact on rates and produce impressive savings. State PSC’s held a small fraction of the votes with when majority, utility interests designed the MVP package.
For transmission builders, the new regional cost-sharing basis made it much easier to suggest a proposed MVP line could potentially save money because the end cost to customers in the state reviewing the proposal were slashed 89-90%. This illusionary bargain was crucial in softening PSC’ economic scrutiny even when assumptions were out of step with current conditions.
Today, the great majority of transmission lines that Midwest electric customers are starting to pay for were approved in other states. No states have access to financial or environmental accountability traditionally used to keep electric customers from getting exploited. As the 2017 Lawrence Berkeley National Laboratory study determined, the cost of CapEx, particularly for transmission, is at the heart of the historic rate and fixed fee increases. The increases in fixed meter fees in WI will add another $7 billion in utility revenue.
Paying for transmission expansion involves utilities making regular payments on high interest loans amortized over decades. Costs passed to customers charged on the basis of use- per kWh -- can no longer collect dollars fast enough as consumption falls short of transmission builders' exaggerated growth rates. Utilities are increasingly seeking large hikes in fixed fees to keep pace with mortgage payments. Some utilities have even started rewarding customers to use more by lowering the rate for higher volume use.. These are some of the negative impacts resulting from the “high fixed-cost nature of the utility business.”
Electric customers and news reporters are also mislead by carefully parsed utility terminology. The new breed of independent transmission line builders publicize only the construction costs failing to point out other very considerable costs for operation, maintenance, securitization and high interest financing over 30-40 years.. Reporters repeat misleading construction costs. and fail to explain to cost-conscious ratepayers that they are also paying for many other lines approved in other states.
An Honorable Step Towards Transparency
In January of this year, Alliant electric bills in the state of Iowa started including a “Regional Transmission Service” fee that is currently around 19% of their electricity charges. Depending on the actual costs paid by this fee and extrapolating from other cost breakdowns, its reasonable to estimate that transmission-related charges are somewhere between 19% and 30% of electricity charges whether a utility itemizes transmission expansion costs or not. Alliant-Iowa has also acknowledged that these costs are being paid by all utilities and are likely to increase.
More Cost-Shared Transmission Proposals on the Way
In March of this year, the Economic Planning User Group (EPUG) at MISO released a large list of transmission expansion projects that utility interests hope will qualify for regional cost-sharing. The preliminary list is very ambitious with six lines considered for Wisconsin, eight for Iowa and 70 others distributed from Louisiana to Canada.
Great Plains Wind Power?
Under the electricity market policies determined by utilities, (not state or federal governments) adding wind farms and other utility scale renewables has not proportionally shut down fossil fuel generation. Despite many billions spent on remote wind farms and transmission expansion, wind power in MISO’s fuel mix has only risen a few percent to 8%. Fossil fuel generation was at 73% and nuclear at 16% in 2016. Decades of utility bill inserts have created the false impressions in customers that wind power from the Great Plains is a national elixir. In 2016, MISO imported more power than it exported to other markets by a considerable margin. MVP planning suggests that utilities were comfortable knowing that CO2 emissions would continue to increase over time even with billions more spent on remote renewable energy.
All utility-scale development also adds to fixed costs that under-cut what our utilities can afford to pay per kWh for local and on site renewable energy that customers want to produce. What creates this direct competition ? Under the “high fixed-cost nature,” utilities must make payments to debt every month even when customers slash their use with efficiency, solar, and other local measures. Piling up utility debt creates serious setbacks because Non-Transmission Alternatives (energy efficiency, load management and local renewable power) are the least cost and fastest means to counteract the negative impacts of carbon-laden wholesale power.
If its Broke, Fix it!
An increasing number of electric customers are coming to see cost-shared transmission expansion as a critical “fork in the road” decision. MISO is the only market in the U.S. promoting multi-billion large packages of transmission expansion lines. Avoiding remaining utility expansion proposals including Mark Twain (IA/MO) and Cardinal Hickory Creek (IA/WI) would free-up billions to flow in our local economies for improvements in homes, businesses and local economies instead of flowing out of our communities to pay long term utility debt that increases the cost of electricity.
Extreme transmission expansion pressure is causing municipalities all across Wisconsin to formally petition the PSC of Wisconsin to restore use of comprehensive cost benefit analysis like Wisconsin law required before 1998. The Resolution asks transmission builders and the PSC to inform ratepayers of the benefits we would receive if the same millions utilities want us to spend on transmission expansion was invested, instead, into energy efficiency, modern load management and rooftop/community solar. Click here to ask your Wisconsin State legislator to urge the PSCW to update the High Voltage Transmission Requirements to restore this traditional analysis.
ARE NOT WASTELANDS
Stronger protections are needed for the thousands of miles of electrical transmission right-of-ways (ROW) in Wisconsin and in other states. Property owners deserve the ability to promote environmental health and habitat for plants, animals and local economies.
Transmission line builders are exploiting antiquated state vegetation management policies and turning corridors for utility facilities into dead zones, acquiring excessively wide corridors, fragmenting woodlands, grasslands and wetlands, Through spraying and sawing practices utilities are barring all woody plant life to return and establish essential transitions in vegetation types.
Current vegetation management practices strip and mutilate the branches from the trees at the edge of the ROW turning them into “hazard trees” likely to fall over and cause further damage in the near future. Current policy interprets "overhanging branches” as any vegetation the extends into the ROW space when legally these are branches that hang over wires. Current corridor management can include removing 60-90% of the foliage of trees when pruning more than 25% of the crown threatens the survival of the plant. .
Such extreme pruning is not approved by the American National Standards Institute (ANSI) because it leaves gaping wounds that do not heal opening the trees to disease and micro-organisms. Oak Wilt is just one of the disease organisms that can spread through mis-managed corridors by root grafts.
On our small property in Seymour, WI., we lost 56 trees.
Most of the trees were outside the designated ROW and should not have been cut. According to The North American Electric Reliability Corporation ( NERC ) corridors for 138 kV lined should be 100 ft. wide. Ours is 150 feet.
We feel that Wisconsin corridor vegetation management policy as defined by the Public Service Commission is overdue for updating to federally-defined “Best Management Practices” (BMP). These proven techniques do not threaten electrical reliability and are less costly than frequent mowing, scalping and spraying. BMP restores wildlife habitat and the plantings can be tailored to the preferences of the landowner. Utilities assert that BMP is too challenging with many miles of land to treat and that they do not have the practical knowledge to identify the desirable plants. Landowners do!
We want to help landowners form local teams and meet with educate state legislators. After a group of lawmakers become aware of the scale of the abuse and reasonable practices to substitute we can work on legislation or PSC codes and establish BMP policies.
If you have an easement through your property that you would like to manage yourself or wish to have utilities follow better practices click on this link to send us a message. Out goal is for Wisconsin to adopt federally recommended guidelines for “Best Management Practices” in maintaining electrical powerline corridors.
Lila M. Zastrow, Certified Arborist, International Society of Arboriculture (ISA) and Dave Hendrickson .tronger
Conservation & Efficiency
Five $100 Prize Categories
According to 2014 World Energy Council data, the CO2 footprints of the industrial and commercial sectors in the U.S. are on par with other countries. Our world-leading per capita CO2 binge rests squarely on us, the residential sector.
SOUL’s Wisconsin Meter Watch has proven that average households can cut their CO2 footprints 30% using conservation tips and no more than $50 in minor improvements. This change is equivalent to installing cutting CO2 emissions equivalent to installing 6-8 solar panels. Read more.
Contest categories for 2017-2018 Wisconsin Meter Watch Participants who start use of tracking sheet by October 31, 2017:
- Improve your skills and achieve the biggest percentage reduction in electricity use for the month of May 2018 compared to May 2017 of all participating WI Meter Watch trackers.
- Achieve the largest kWh reduction in electricity use for the month of May, 2018 compared to May, 2017 of all participating trackers.
- Share a success story about teaching someone significantly younger or older than you about ways to conserve electricity.
- By October 31 ,2017 enlist another WI household with high electricity use based on the May 2017 kWh consumption to join the WI Meter Watch and track their use for at least 6, continuous months. The person who enlists the qualifying house with the highest May 2017 usage wins.
- Discover and share an innovative, effective, no-cost electricity saving trick that never occurred to you before.
JOIN WI METER WATCH- FREE
Starting Management by October 31, 2017