Michigan PSC judge wants new docket on DTE’s treated coal program

An administrative law judge at the Michigan Public Service Commission had some criticisms for Detroit Edison about its reduced emissions fuel (REF) program, which involves treating stockpiled coal at its power plants to reduce emissions and qualify for a federal tax credit.

ALJ Mark Eyster filed Dec. 4 testimony at the commission in a Power Supply Cost Recovery (PSCR) case that began back in September 2011. Much of Eyster’s testimony was spent summarizing months of testimony from officials at Detroit Edison, a unit of DTE Energy (NYSE: DTE), and also intervenors in the case, including the state Attorney General.

In the area of overall coal procurement, Eyster noted that the utility’s long-term forecast of coal prices assumes that 80% of the coal consumed will be low sulfur western (LSW) coal from southern Montana and northeastern Wyoming (i.e. the Powder River Basin). It is assumed that the remaining purchases will include low sulfur eastern (LSE), mid sulfur eastern (MSE) and high sulfur eastern (HSE) from Central and Northern Appalachia.

In 2011, Detroit Edison’s coal cost was 241.3 cents/MMBtu. Detroit Edison’s 2012 projected coal cost is 262.7 cents/MMBtu. Almost all the increased cost is attributable to the higher cost of LSW. The expiration of an advantageous long-term transportation contract is the primary reason for the increased cost of LSW. These estimates do not reflect price changes after the Sept. 30, 2011, filing date of this PSCR application.

To comply with the currently court-invalidated Cross-State Air Pollution Rule (CSAPR), Detroit Edison was exploring options to reduce emissions via a combination of strategies, such as: the use of existing combustion controls, at the expense of reduced combustion efficiency; by burning a higher percentage of LSW fuel blends; by increased dispatch of lower emission units, and; by lower dispatching of higher emission units, Eyster noted. In addition to operational changes, Detroit Edison planned to purchase emission allowances to cover shortfalls from allocations.

In March 2011, the U.S. Environmental Protection Agency proposed the EGU MACT to limit Hg, acid gases, and other air pollutants from fossil fueled electric generation units (EGUs). To comply with the EGU MACT mercury emission standards, Detroit Edison plans to use wet and dry scrubbers (FGD) at Monroe units 1-4 and activated carbon injection (ACI) at all other units. Detroit Edison expects units with FGD will meet EGU MACT acid gas emission standards. However, on non-scrubbed units, additional control measures will be necessary. Detroit Edison had said it is currently testing dry sorbent injection (DSI) technology at St. Clair Units 3 and 7, to determine its technological and economic feasibility for removal of acid gasses at non-FGD power plants. Detroit Edison said it has no plans to test DSI at its other power plants.

Detroit Edison expects that some of its plants will be unable to comply with EGU MACT standards and are, therefore, candidates for closure. However, because of conflicting evidence provided by Detroit Edison’s witnesses, it is not possible to determine precisely which units Detroit Edison considers candidates for closure, Eyster noted. In their testimony and discovery responses, two utility witnesses did include Harbor Beach and Trenton Channel Units 7 and 8 as possibilities for closure. Beyond that, however, the record is unclear.

  • One Detroit Edison  witness stated that in this PSCR plan, the company is assuming the use of DSI on St. Clair Units 1-4 and 6 and Belle River Units 1-2. Harbor Beach, River Rouge Units 2-3, St. Clair Unit 7 and Trenton Channel Units 7-9 are assumed, for planning purposes, to be retired in 2015. Such assumed retirements should not be construed as certain but present circumstances and expectations suggest the potential for such retirements, the witness noted.
  • However, in a discovery response, another utility witness stated: “[T]he company currently assumes Flue Gas Desulfurization together with Selective Catalytic Reduction technologies will provide compliance with EGU MACT standards at Monroe Power Plant Units 1-4. St. Clair Units 1, 2, 3, 4, 6, and 7, Belle River Units 1 and 2, River Rouge Units 2 and 3, and Trenton Channel Unit 9 are all candidates for DSI and ACI, although additional particulate control equipments may be necessary. Harbor Beach and Trenton Channel Units 7 and 8 are not expected to be candidates for these technologies, which might indicate likely candidates for retirement.”

Point of contention for REF is that profits flow to DTE shareholders

In the area of REF, Detroit Edison sells stockpile coal at the affected power plants to specially-created, non-regulated subsidiaries of DTE Energy, then buys back the treated coal. Detroit Edison expects REF to lower emissions of SO2, Hg, and NOX and to lower associated emission allowance expenses, which is of benefit to ratepayers. But, the state Attorney General recommended that the commission disallow REF project costs in the PSCR plan and designate the projected Hg emission reduction costs as costs for which recovery through the PSCR is not likely to be permitted.

There has been criticism in this case that Detroit Edison’s ratepayers would pay money for REF that DTE Energy’s shareholders would reap as profits. Detroit Edison has said that selling the coal to non-regulated affiliates reduces technology and tax benefit risk to utility ratepayers.

“By artfully structuring layers of corporate ownership and investment partners to take advantage of the available tax credits, DTE Energy has devised a scheme to generate substantial profits from the chemical treatment of Detroit Edison’s coal,” Eyster wrote. “This show of ingenuity is not criticized. However, the issue that must be thoroughly addressed is whether and, if so, to what degree these profits are properly considered a reduced cost of fuel and accounted for in the PSCR process. This issue is not directly addressed by Detroit Edison. Rather, Detroit Edison presents limited explanations for why it hasn’t undertaken the Project itself and steers clear of any suggestion that the REF related profits should actually be considered its property and should flow to its customers. These explanations are not particularly satisfying and are stated in such general terms that detailed fact finding about them is not possible.”

He added: “For instance, one of the problems Detroit Edison cites is that they don’t own the rights to use ChemMod [a chemical additive used to create REF]. In light of all the R&D attributed to Detroit Edison, including its determination regarding ChemMod’s usefulness, some explanation about how this came to be is warranted. In addition, something more than a summary dismissal of ChemMod alternatives should be presented.”

Another rationale Detroit Edison presents is that the tax credits are not available to it because the REF must be provided by an unaffiliated company. “However, the REF is, in fact, supplied by an affiliate,” Eyster noted. “No explanation is presented to explain why Detroit Edison could not, itself, have devised a similar corporate and investor structure to retain these tax credits for its customers. Detroit Edison also referenced avoidance of risk as part of their decision making process, but failed to satisfactorily explain the nature and magnitude of these risks. Detroit Edison cites avoidance of capital expenditures as another reason for the REF Project. However, again, Detroit Edison fails to explain the capital costs involved. This is particularly troubling given that Detroit Edison indicates that, as part of the Adder, Detroit Edison must pay the Fuels Companies for ‘avoided Hg capital amortization’ and that Detroit Edison does not address any of its plans to deal with the 10-year expiration of the Project.”

In short, Detroit Edison presented a number of conclusory statements to explain why it agreed to participate in the REF program, Eyster wrote. Detroit Edison needs to present considerably more evidence to explain, not only the structure of the REF project, but also the rationale for the structure, he added. “Detroit Edison must thoroughly explain the alternatives it considered and why they were rejected. The inability of Detroit Edison to properly explain the Project raises questions as to the proper allocation of REF Project profits between DTE Energy, its investors, and Detroit Edison’s customers.”

Considering the magnitude of the profits DTE Energy expects to generate from REF, something in the range of half a billion dollars, and that the project is the first step in Detroit Edison’s still developing strategy for increased emission control, this project warrants a thorough evidentiary presentation and careful scrutiny, Eyster said.

“It appears clear that the timing of the REF Project was driven more by deadlines associated with the tax credits than by Detroit Edison’s actual needs,” Eyster wrote. “Thus, the Project requires a far more thorough examination than would usually be warranted by the marginal effects it may have on PSCR costs. In this case, Detroit Edison has not presented sufficient evidence to afford such an examination of the Project. Because PSCR Plan contested case hearings may not be the best vehicle by which to examine the REF Project and the long-term emission control strategy that Detroit Edison is developing, it is recommended that a separate docket be opened for such a purpose.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.