IndianaDG Joins as Friend of the Court in Duke Case

Posted by Laura Arnold / September 06, 2018 / Posted in wind / No Comments

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Several documents of interest to IndianaDG readers were filed on 9/4/18 with the Indiana Supreme Court. IndianaDG has joined with several other groups as a Friend of the Court or Amici Curiae in a Legal Brief that was filed.

The attorney representing Michael Mullett and his wife Patti March who are Duke Energy Indiana customers in Columbus, IN, framed the issue on transfer on the first narrative page of the Petition:

Whether the Court of Appeals’ decision conflicts with multiple decisions of this Court and departs from fundamental principles of Indiana utility and appellate law by upholding a provision of a final order of the Indiana Utility Regulatory Commission which authorized the recovery through customer rates of $29 million paid by an investor-owned utility as damages for its breach of a purchased power agreement with an energy supplier which had previously been fully and finally adjudicated by the Seventh Circuit of the United States Court of Appeals and had caused energy not to be generated or delivered for the benefit of customers?

The arguments explaining why the Supreme Court should grant transfer, vacate the Court of Appeals decision, and remand the case to the Commission for additional proceedings and relief for Duke Energy Indiana customers (including but not limited to a refund of the $29 million) is then set forth in detail in the remainder of the Petition.

Here are the documents filed 9/4/18 with the Court that includes Indiana Distributed Energy Alliance (IndianaDG):

Mullett v DEI--Motion to Appear as Amici Curiae--9-4-18

Mullett v DEI--Appearance of Counsel for Amici Curiae--9-4-18

Mullett v DEI--Amici Curiae Brief--9-4-18

Here is an excerpt from the Amici Curiae brief:

SUMMARY OF ARGUMENT
This case presents a fundamental question of law and fairness about whether Indiana utility consumers should be forced to pay higher rates and charges when a monopoly electric utility breaches a contract with a third-party energy provider, and the Indiana Utility Regulatory Commission (“Commission” or “IURC”) fails to fully analyze and determine the reasonableness and prudency of the utility’s breach of contract actions that created the financial liability. Duke Energy Indiana LLC (“Duke Energy”) breached its contract with the Benton County Wind Farm (“Benton”) that required Duke Energy to purchase 100 megawatts of wind energy and to procure
transmission to deliver the energy to the electricity grid managed by the Carmel, Indiana based Midcontinent Independent System Operator (“MISO”). Benton sued Duke Energy for damages
due to the breach of contract. In 2016, the United States Court of Appeals for the Seventh Circuit ultimately ruled in Benton’s favor. The U.S. Court of Appeals held that Duke Energy was at fault and liable for breach of contract based on its failure to reserve transmission capacity to carry the wind energy that was generated, and ordered Duke Energy to pay Benton damages for its breach of contract:

….Duke must pay Benton. The risk of inadequate transmission was contemplated by the contracting parties and allocated to Duke. By accepting this risk, Duke enabled Benton to finance its project; otherwise potential investors might have feared exactly the overcapacity situation that has come to pass. Duke wanted
Benton’s facilities to exist and called them into existence by promising to pay even if a shortfall of transmission services should lead to curtailment of deliveries.

Benton County Wind Farm v. Duke Energy Indiana, 843 F. 3d 298, 303-04 (7th Cir. 2016). The U.S. Court of Appeals remanded the case to determine damages, and the parties reached a settlement by which Duke Energy agreed to pay damages of $29 million to Benton.

After the settlement, Duke Energy filed a fuel adjustment case at the Commission requesting authorization to charge consumers for the entirety of the $29 million of its damages resulting from its breach of contract with Benton County. Application of Duke Energy Indiana for a Change in Its Fuel Cost Adjustment, Cause No. 38707 FAC 113, Sept. 27, 2017. Under Indiana law, the Commission must specifically examine and find any such charges to be just and
reasonable before it can permit a utility, such as Duke Energy, to force consumers to pay the charges–here, the $29 million in damages. Ind. Code. §8-1-2-4. Instead of analyzing the reasonableness of Duke Energy’s actions in breaching the contract, however, the Commission only looked at whether the amount of the settlement was reasonable. By asking and addressing
the wrong question, the Commission reached the wrong answer by failing to properly apply the just and reasonable standard and violating Indiana law in a manner that raises rates to Indiana
consumers without fundamental fairness. That result is unfair and is contrary to law.

Appellants Mullett and March argued on appeal that forcing consumers to pay these higher charges of $29 million was unreasonable as a matter of law because Duke Energy’s
breach of contract caused the financial damages and the loss of wind energy service.

Accordingly, Duke Energy and its shareholders should be responsible for Duke Energy’s errors. The Indiana Court of Appeals ruled in Duke Energy’s favor by joining the Commission in again
focusing on the reasonableness of the settlement amount, rather than Duke Energy’s breach that caused the damages and loss of service. Mullett v. Duke Energy Indiana, Court of Appeals Case
No. 93A02-1710-EX-2468 Opinion (May 21, 2018). With due respect, the Indiana Court of Appeals’ decision is erroneous and contrary to law. If left to stand, it sets an unfortunate precedent allowing consumers to be charged for a monopoly utility’s unreasonable decision to breach its contractual obligations, and it risks continued unfairness and illegality in future such
cases. Consumers should not be forced to pay for these types of utility mistakes.

The Supreme Court should grant the Petition to Transfer in this case in order to fully consider the important issues on appeal. The Supreme Court should then reverse and remand the Indiana Appellate Court’s decision and require the Commission to fully and fairly determine the reasonableness of Duke Energy’s actions in breaching its contract, as well as the fairness and legality in these circumstances of charging the entirety of the consequent damages to consumers who bear no fault at all.

ARGUMENTS:

Indiana law does not allow Duke Energy to force customers to pay unreasonable and unjust higher utility charges for damages resulting from its breach of contract.
Both the Indiana Utility Regulatory Commission and the Indiana Appellate Court asked the wrong question and then reached the wrong answer.

Here is what the Indiana Court of Appeals said in their order dated 5/21/18:

Case Summary

Appellee Duke Energy Indiana, LLC (“Duke”) and Benton County Wind Farm (the “Wind Farm”) entered into a contract under which Duke agreed to buy power from the Wind Farm. In 2013, a dispute arose after Duke failed to buy energy from the Wind Farm. The Wind Farm filed suit claiming that Duke owed it money for lost production under the parties’ contract. The parties eventually settled and Duke went to the Indiana Utility Regulatory Commission (the “Commission”) seeking to recover its costs from ratepayers. Appellants Michael A. Mullett and Patricia N. March (the “Appellants”) intervened in the proceeding and objected to Duke’s request. After a hearing on the matter, the Commission approved Duke’s request to recover the costs from its ratepayers over a twelve-month period.

Appellants now appeal arguing that the Commission’s order is contrary to law because the damages are “liquidated” and “hypothetical” and it amounts to impermissible retroactive ratemaking. Finding that substantial evidence supports the Commission’s order and no other error, we affirm.

The Indiana Court of Appeals goes on as follows:

Facts and Procedural History
In 2006, Duke and the Wind Farm entered into a Renewable Wind Energy Power Purchase Agreement (“PPA”) in which Duke agreed to purchase a portion of the energy generated by the Wind Farm. After purchasing the energy from the Wind Farm, Duke would immediately sell it into the Midcontinent Independent System Operator (“MISO”) wholesale energy market. The Indiana Utility Regulatory Commission (“the Commission”) approved the PPA in its entirety in 2006, concluding that “the terms of the Wind [PPA were] reasonable.” Duke App. Vol. II, p. 17.

The Commission also recognized that Duke would be incurring significant costs in connection with the PPA. Consequently, in order to further the Commission’s policy of encouraging the development of renewable resources, the Commission authorized Duke to recover all of its PPA costs from ratepayers for the entire twenty-year term:

[T]he Commission finds that Duke Energy Indiana should be authorized to recover the Wind [PPA] costs provided for in the contract for the full 20 year term of that contract[.]
Duke App. Vol. II, p. 19.

Following changes to certain rules and regulations in 2013, a dispute arose regarding the extent of Duke’s contractual obligations to the Wind Farm. Duke believed that based upon the parties’ contract, it was only required to accept and pay for energy that the Wind Farm generated and delivered to Duke. The Wind Farm, however, interpreted the contract to mean that Duke had to pay for lost production in addition to the power it delivered to Duke.

The Wind Farm sued Duke in federal court to resolve the disputed contract interpretation. The federal district court agreed with Duke’s interpretation and granted Duke’s motion for summary judgement in 2015. The Wind Farm appealed to the Seventh Circuit, which agreed with the Wind Farm’s interpretation, reversed the district court’s ruling, and remanded with instructions for a determination of damages, i.e. how much Duke owed the Wind Farm for lost production.

The Wind Farm and Duke entered into settlement negotiations. At the conclusion of the settlement negotiations, the parties agreed on $29 million, which Duke believed was approximately equal to what it would have cost Duke and its ratepayers had the parties agreed with the Wind Farm’s contact interpretation at the outset.

Duke reported to the Commission in its Fuel Cost Adjustment (“FAC”) filing on July 27, 2017, that the dispute between Duke and the Wind Farm had settled.1 In its report, Duke also indicated its intention to recover the lost production costs from ratepayers over a six-month period.2 The Office of Utility Consumer Counselor (the “OUCC”) had no objection to Duke’s recovery of the $29 million as costs Duke incurred under the PPA, but requested that the recovery be spread over a twelve-month period rather than the six-month period Duke had proposed. Duke agreed to spreading the recovery out over a twelve-month period. On September 21, 2017, Duke filed its Proposed Form of Order in which it proposed to recover the $29 million through rates over a twelve-month period.

Meanwhile, Appellants intervened in this proceeding as ratepayers and filed a Brief in Opposition to Approval of Liquidated Damages Payment as an Expense Recoverable through Rates as their legal objection to Duke’s Proposed Order. Thereafter, Duke filed its Response to Appellant’s Brief in Opposition. On September 27, 2017, the Commission entered its final order approving proposed Duke’s rate recovery over a twelve-month period.

SEPA: The Four Dos of Green Tariffs (and One Don’t)

Posted by Laura Arnold / September 01, 2018 / Posted in Uncategorized / No Comments

The Four Dos of Green Tariffs (and One Don’t)

August 30, 2018 | By Jared Leader

More than 90 percent of the world’s largest companies put out a sustainability report. Two-thirds of the Fortune 100 have renewable energy goals and, according to the Business Renewables Center Deal Tracker. So far this year, companies have publicly announced their intention to purchase 3.86 gigawatts (GW) of renewable energy.

U.S. Renewable Energy Map: A Guide for Corporate Buyers

Where customers can buy large-scale renewable energy through the grid. Visit the World Resources Institute website for the full interactive map. (Source: World Resources Institute)

How will these customers access renewable energy? The answer may be green tariffs. Green tariffs make sense as a next-generation renewable power solution for customers, utilities and regulators due to the confluence of two trends:

A growing number of commercial and industrial electricity customers want to significantly increase their use of renewable energy to meet sustainability initiatives and contribute to carbon emissions reductions.
As the cost of renewable energy continues to decline, customers have become more likely to seek potential economic benefit by including long-term renewable contracts as part of their power mix.

Traditional green pricing programs provide access to renewable energy, but typically at a premium tied to the utility’s regular rate and often without access to the corresponding renewable energy credits, or RECs. Green tariffs, on the other hand, provide economic benefit by providing a long-term hedge against fluctuating fossil fuel prices because customers have locked in a fixed price for renewable energy that isn’t pegged to the regular rate.

Additionally, because green tariffs are bundled with renewable energy credits, they provide a verifiable way to achieve sustainability objectives, to which many large companies increasingly have pledged. A Smart Electric Power Alliance (SEPA) survey of a small sample of Fortune 500 companies found that 90 percent of their reported renewable energy consumption in 2016 was based on unbundled renewable energy credits. As I wrote in March, green power pricing generally involves unbundled renewable energy credits that neither add new renewable generation resources to the local grid nor provide the customer with renewable energy credits to retire or sell.

Green tariffs are more attractive to some customers than behind-the-meter alternatives, such as installing their own solar panels. Aside from the practical difficulty of generating large-scale power on their own, companies may prefer to focus on their own core business while leveraging the utility’s expertise in generation and distribution.

For utilities, green tariffs can be an improvement over historical green pricing plans in several ways. First, and importantly, they provide another attractive option for larger customers, helping retain and/or attract major commercial and industrial customers in their service territory.

Utilities also benefit from continued engagement in the decision process about where best to site new renewable generation resources, which helps ensure optimal operation of and value to the local grid. For example, as part of the negotiation of a new green tariff involving a power purchase agreement between a large industrial customer and a solar generation company, the utility is best positioned to know which points on the system are best suited to accommodate new generation, potentially reducing the overall project cost.

For regulators and other policymakers, green tariffs provide the opportunity to create an economic “ring fence” around contracts between utilities and their largest customers, ensuring that additional renewable capacity is built without subsidization to or from customers in other rate classes. Over the long term, this benefit should enable more approval of renewable projects with less controversy.

Dynamic Duos: Utility Green tariffs and Corporate Buyers

What should utilities look to do when creating green tariff deals – and what should they avoid? We’ll explore those questions during this Nov. 8 webinar while I speak with representatives of both sides of the same green tariff deal. I ask utilities and customers to describe the process from day one to execution. Heather Mulligan, market manager for solar programs at Puget Sound Energy – a pioneer in green tariffs – and Patrick Leonard, manager of energy and resource management at Starbucks, which signed a green tariff agreement with Puget Sound Energy to power dozens of its Washington state stores with renewable energy, will be my guests.

Dos and Don’ts

In the meantime, our discussions with utilities across the country point to some clear lessons for those considering green tariff development.

Do diversify renewable energy offerings to meet market demand. Large commercial and industrial customers are looking for alternatives to either their own behind-the-meter renewable capacity or green pricing programs. Community solar programs continue to gain traction in many markets as a viable alternative, while green tariffs provide another path to renewable power for a utility’s larger customers.
Do engage early and often with customers, regulators and stakeholders. As the market for renewable energy expands, utilities will be responsible not only for rolling out new products but for educating the community about a market that isn’t intuitively easy to understand. Take the time to develop a strategic process of dialogue, education and negotiation with the goal of ensuring all parties are on the same page.
Do offer flexibility in green tariff design. Among early green tariff programs, success stories include a range of designs. These include asset ownership by the utility or the customer; sleeved power purchase agreements vs. a subscriber model; and various lengths of power purchase agreement or contract duration. Tailoring the tariff to the customer’s needs and constraints helps ensure a positive experience that will attract more customers.
Do transfer renewable energy credits to the customer or retire them on behalf of the customer. Including renewable energy credits with electrons is one of the prime benefits of green tariffs, helping commercial and industrial customers nail down sustainability goals over a multi-year period.
Don’t develop products without understanding your customers. Successful pioneers in the market took the time to research their customer bases’ preferences, both through conversation and market research.

ABOUT THE AUTHOR

Jared Leader

Senior Associate, Utility Strategy

Jared joined SEPA in June 2017, where he joins SEPA’s Advisory Services team of experts in utility business and distributive energy to provide strategic and operational planning that drives integration of distributed energy resources into utility resource portfolios.

Prior to joining SEPA, Jared spent three years as a consultant at Arcadis US. Jared was responsible for the design, implementation, and management of several environmental programs for both municipal and commercial clients in the energy and water sectors.

Jared holds a bachelor’s degree in civil and environmental engineering from the University of Virginia, where he conducted research on algae-based bio-fuels and focused in sustainable practice. He is currently earning his MS in Energy Policy and Climate from Johns Hopkins University in Washington, DC

Salesforce invests in wind farm as it grows in Chicago area

Posted by Laura Arnold / August 31, 2018 / Posted in wind / No Comments

Salesforce invests in wind farm as it grows in Chicago area

Corilyn ShropshireChicago Tribune

Tech firm Salesforce said it will back the construction of a new renewable energy wind farm in McLean County, a project that has been in the planning stages for 10 years.

The Bright Stalk Wind Farm will be built near Bloomington-Normal, and owned and operated by EDP Renewables North America, the Houston-based company behind five other renewable energy projects in Illinois. Bright Stalk will produce enough electricity to power 71,000 average homes, the company said.

The 15-year deal will allow Salesforce to balance out a portion of the energy the company consumes from its offices and data centers with “renewable energy.

EDP Renewables hopes to begin construction on the roughly $300 million project by next spring, according to Ryan Brown, EDP Renewables’ North America executive vice president, Eastern Region & Canada.

The deal helps solidify the company’s presence in Illinois, Brown said. “This is an area of the country where you have very strong wind resources and communities and landowners with an interest in hosting new projects,” he said.

Salesforce executives declined to disclose the size of the wind farm investment.

Salesforce, based in San Francisco, has plans to expand its presence in the Chicago area. The company already employs nearly 1,500 workers in Chicago. It is in talks to take up to 500,000 square feet of new office space on the north side of the Chicago River.

The wind farm’s location in rural McLean County is important because it is halfway between Salesforce’s data centers south of Chicago and near Indianapolis. While the wind farm may not power Salesforce’s Midwest operations, it helps offset the number of megawatt-hours used by the business. For each megawatt-hour of electricity produced by the wind farm, Salesforce earns the revenue generated by the electricity and a renewable energy credit.

In recent years, other businesses have upped their investments in renewable energy. In 2016, Chicago-based Invenergy partnered with Google to support the tech firm’s large data center operations. In 2015, Amazon invested in a wind energy farm near Lafayette, Ind.

In 2015, Salesforce committed to powering 100 percent of its operations with renewable energy by 2022. “Our real end goal is a fully de-carbonized (electricity) grid globally,” said Patrick Flynn, the company’s vice president of sustainability.

crshropshire@chicagotribune.com

Twitter @corilyns

Ohio business community backs 2.2 GW of Ohio solar

Posted by Laura Arnold / August 31, 2018 / Posted in solar, Uncategorized / No Comments

Ohio business community backs 2.2 GW of Ohio solar

Speaking the language of manufacturing, employment, and economic opportunity, five prominent corporations have backed a 2.2 gigawatt solar goal for Ohio by 2030.

AUGUST 30, 2018 WILLIAM DRISCOLL

Five prominent firms with operations in Ohio are endorsing a report advocating 2.2 gigawatts (GW) of solar for Ohio by 2030, lending their corporate logos in support.

“The U.S. energy industry is undergoing a transition toward clean energy,” said JPMorgan Chase executive Matthew Arnold in the report’s foreword. He noted that his company “has seen firsthand an increase in investments in sustainability. Individual states have a unique opportunity to encourage, and benefit from, this evolution.” His firm is developing 20 MW of solar at its corporate center in Columbus, Ohio, he said.

Other “logo-level” backers are Owens Corning, Walmart, Eaton, Whirlpool, and Ohio-based GEM Energy. Advisory council members include these firms plus Procter & Gamble, EDP Renewables, and the Ohio Manufacturers Association.

Reaching 2.2 GW of solar in Ohio would involve $3.6 billion in investment, and “sustain 800 direct jobs and over 1,700 indirect and induced jobs each year,” said the report, and would boost the state GDP by $1 billion per year.

As of July 2018, Ohio had 176 MW of installed solar, and four solar projects under development totaling 550 MW.

The report highlights First Solar’s 600 MW solar panel factory in Perrysburg, Ohio, and its nearby 1200 MW factory now under construction, which together will employ 1250 people. Two in-state manufacturers of racking and mounting hardware are also featured.

The report conveys pride in the state’s manufacturing strength, as it ranks third in the nation in manufacturing jobs, has 34 accredited engineering programs, graduates 20,000 students per year in the STEM fields (science, technology, engineering and math), has “150 apprenticeship programs to train Ohioans to be machinists,” and “supports over 11,000 registered apprentices in construction.”

To derive the 2.2 GW solar target, the report’s author Synapse Energy Economics first ran the Regional Energy Deployment System (ReEDS) model, developed by the National Renewable Energy Laboratory. Synapse, however, developed its own solar projection, “because recent demonstrated commercial interest in utility-scale solar development in the state has far exceeded what ReEDS projects for development.”

The report also makes recommendations regarding wind power, electric transportation, energy efficiency, and grid modernization.

The report invites “Ohioans with diverse perspectives” to “join the conversation” at the report’s website.

Synapse Energy Economics prepared the report in partnership with the Great Lakes Energy Institute at Case Western Reserve University, with support provided by Environmental Defense Fund.

Technical note: Synapse Principal Associate Asa Hopkins explained how the 2.2 GW solar target was derived: “The 2.2 GW is composed of 1.2 GW of utility-scale PV and 1 GW of distributed generation (DG). The potential DG PV value was derived based on growth of about 30 MW per year rising up to 80 MW per year by 2023, then continuing at that level. Recent DG growth in Ohio has been about 30 MW per year, and we expect increases in the pace of solar deployment are possible with falling component costs (and possibly contingent on changes in Ohio policies and further maturation of the market). We modeled the utility-scale PV as more near-term, encouraged by the expiring ITC. There are 550 MW of large projects that are either approved or proposed (filed with the Siting Board), in addition to about 60 MW of operating projects, and we conservatively estimated that at least this many projects again could be constructed before 2030.”

Trump takes coal proposal on tour of Southern Indiana

Posted by Laura Arnold / August 30, 2018 / Posted in 2018 Midterm Elections, Hoosier Energy (HE), solar / No Comments

Coal mines around the Hoosier state and country could see fewer regulations with President Donald Trump's Affordable Clean Energy or ACE proposal.

Trump takes coal proposal on tour

Mike Grant, Washington (IN) Times Herald, Aug 29, 2018

President Donald Trump is headed to southwestern Indiana. There is no guarantee he will talk about his new Affordable Clean Energy rule for the Environmental Protection Agency but it only makes sense that he would while making a stop in an area that sits in the middle of coal producing areas in Illinois, Kentucky and Indiana.

Trump announced the plan last week in Charlestown, West Virginia. It would do away with the Obama Clean Power Plan rule, and replace it with one that allows individual states to set limits for carbon dioxide emissions.

“We are putting our coal miners back to work,” said Trump, in an Associated Press story last week.

“The Obama Administration put in the Clean Power Plan which really was the death knell for the coal industry,” said Bucshon. “What they were doing in the previous administration was putting in regulations that could not be met with current technology. It would shut down the coal industry.”

During Obama’s second term, the coal industry in Indiana began to slow down. That happened even though a U.S. Supreme Court decision in 2016 stopped the provisions of the EPA rule from being put into effect.

“I am an ‘all the above’ energy believer and coal is a piece of that,” said Bucshon. “This area of the country is rich in coal and every coal miner in the state of Indiana is in my district.”

Bucshon’s opponent in the fall election, William Tanoos, questions who will really benefit from the change.

“I understand the President is trying to bolster coal, and coal is important in the Eighth District,” said Tanoos, a Democrat from Terre Haute. “My concern is with the miner. This will benefit those at the top but not the worker and at the same time increase pollution and the negative health impacts that brings.”

He called the measure disappointing.

“There is a lot that could be done to improve the plight of miners, and this does nothing to address that,” said Tanoos. “It just takes the cap off of pollution.”

In Daviess County, Solar Sources still operates mines in the eastern part of the county. Earlier this year the company reopened the Billings Pit that had been closed. The Trump plan seems to be getting a warm reception.

“It could be beneficial to eliminate the clean power plan and allow the states to regulate carbon dioxide emissions,” said Mike Owen, regulatory consultant for Solar Sources . “If they let each state set limits on carbon dioxide it will look much different than the national, one size fits all system, that Obama was pushing. This recognizes that there are different kinds of coal in different regions. Illinois basin coal is different from Powder River coal and that is different than Texas coal.”

Owen says the change of EPA rules could have a positive impact on mining in the area.

“In the short term, I believe it could mean more mining,” he said. “I am not sure how quickly it can all go into effect. These rules will probably be challenged in court. The Hoosier Environmental Council and the Sierra Club are still around.”

The last coal burning power plant built in southern Indiana was the $1 billion Edwardsport Plant constructed by Duke Energy in northern Knox County. While the coal industry may have been struggling, renewable power operations began popping up in the area. Hoosier Energy built a solar farm along Interstate-69 near the Crane exit. Indiana Municipal Power Agency built a 4-megawatt solar operation in Washington and Duke Energy is in the process of constructing a solar operation at the Crane Naval Warfare Center.

“The old rules were forcing out older coal plants and forcing others to go natural gas,” said Owen. “Older coal plants have been shutting down and they were not coming back. Hoosier Energy closed a plant at Petersburg. Marginal plants that had reached 30 years on line were being shut down. This will allow them to continue to operate at an economic advantage to rate payers. Utility companies will be able to make small changes to improve air quality instead of trying to reach for everything at once.”

“What the Trump administration is doing is putting in regulation that is reasonable, that can be met with reasonable technology,” said Bucshon. “That will help the coal industry here in Indiana. We need to continue to advance innovation and technology which we will, but you just can’t put onerous regulation in place like the Clean Power Plan.”

Still, Tanoos believes the Trump bill could have put in some regulations that did more than turn the coal companies and the utilities loose.

“They could have tied the emission levels to job training or put more money toward retirement for the workers,” he said. “I understand the intent of the rule. It does nothing for the workers and only helps those at the top and in the end, the EPA estimates as many 1,400 deaths could be tied to this proposal.”

The Indiana Coal Council contends Indiana has around 24 active mines operated by a dozen companies that produce 32 million tons of coal. Including trucking and other ancillary workers, the mining industry supports 2,500 jobs in Indiana.

“I see this change as positive, but we will still have to see what the full impact will be,” said Owen.

Officials point out that since 2010, utilities have retired or announced plans to retire 630 coal-fired power plants in 43 states. That is roughly the equivalent of 40 percent of all coal-fired power plants in the country.

Still, the change is expected to make a difference in the coal fields.

“I am very excited they have decided to put in regulation that backs up a little bit and lets us work where we are,” said Bucshon. “We can still try to do what we can to make the air as clean as possible, but now do it with the available technology, so I’m pleased.”