S T A T E O F M I C H I G A N BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION * * * * * In the matter of the application of The ) Detroit Edison Company for authority ) Case No. U-17097 to implement a Power Supply Cost ) Recovery Plan in its Rate Schedules ) for 2013 Metered Jurisdictional Sales ) of electricity. )

NOTICE OF PROPOSAL FOR DECISION

The attached Proposal for Decision is being issued and served on all parties of

record in the above matter on November 8, 2013.

Exceptions, if any, must be filed with the Michigan Public Service Commission,

4300 West Saginaw, Lansing, Michigan 48917, and served on all other parties of record on

or before December 3, 2013, or within such further period as may be authorized for filing

exceptions. If exceptions are filed, replies thereto may be filed on or before December 17,

2013. The Commission has selected this case for participation in its Paperless

Electronic Filings Program. No paper documents will be required to be filed in this

case.

At the expiration of the period for filing exceptions, an Order of the Commission will

be issued in conformity with the attached Proposal for Decision and will become effective

unless exceptions are filed seasonably or unless the Proposal for Decision is reviewed by

action of the Commission. To be seasonably filed, exceptions must reach the Commission

on or before the date they are due.

MICHIGAN ADMINISTRATIVE HEARING SYSTEM For the Michigan Public Service Commission _____________________________________ Sharon L. Feldman Administrative Law Judge

November 8, 2013 Lansing, Michigan

S T A T E O F M I C H I G A N

MICHIGAN ADMINISTRATIVE HEARING SYSTEM

FOR THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * * In the matter of the application of The ) Detroit Edison Company for authority ) Case No. U-17097 to implement a Power Supply Cost ) Recovery Plan in its Rate Schedules ) for 2013 Metered Jurisdictional Sales ) of electricity. )

PROPOSAL FOR DECISION

I.

PROCEDURAL HISTORY

On September 28, 2012, The Detroit Edison Company (DTE Electric or DTE)

filed an application for approval of its 2013 Power Supply Cost Recovery (PSCR) plan

and factors. DTE’s application was accompanied by the testimony and exhibits of nine

witnesses: Kathik Krishnamurthy, Markus B. Leuker, James J. Musial, Kevin L. O’Neill,

Robert E. Palmer, William C. Rogers, Michael W. Shields, James D. Wines, and Angela

P. Wojtowicz. The application seeks a maximum PSCR factor of 4.74 mills/kWh, based

on projected 2013 PSCR costs of $1.51 billion and an underrecovery from prior years of

$81.2 million, and presents a five-year forecast.

At the November 27, 2012 prehearing conference, DTE and Staff appeared, and

the following parties appeared and were granted intervention: Attorney General Bill

Schuette, the Michigan Environmental Council and NRDC (MEC/NRDC), Michigan

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Community Action Agency Association (MCAAA), and the Association of Businesses

Advocating Tariff Equity (ABATE). A consensus schedule was established at the

prehearing conference, and subsequently revised by agreement of the parties.

In accordance with the revised schedule, on March 7, 2013, the Attorney General

filed the testimony of Michael J. McGarry, Sr., MEC/NRDC filed the testimony and

exhibits of Pamela H. Richards and George E. Sansoucy, and MCAAA filed the

testimony and exhibit of Geoffrey C. Crandall. On April 11, 2013, DTE filed the rebuttal

testimony of five of its witnesses, Messrs. Krishnamurthy, O’Neill, Palmer, and Rogers,

and Ms. Wojtowicz. At the evidentiary hearings on May 2 and 3 and May 20, 2013, the

witnesses who filed rebuttal testimony appeared and were cross-examined; the

testimony of all remaining witnesses was bound into the record by agreement of the

parties. Also at the hearings, in addition to the admission of exhibits, official notice was

taken of Exhibits A-30 and A-30 Supplement from the record in Case No. U-16434-R.1

DTE, Staff, the Attorney General, MEC/NRDC, and MCAAA filed briefs on June 27,

2013, and reply briefs on July 18, 2013.

The evidentiary record is contained in 822 pages of transcribed testimony in four

volumes and 103 exhibits, as well as the identified portions of the record in Case No.

U-16434-R, and is discussed in more detail below.

II.

OVERVIEW OF THE RECORD AND POSITIONS OF THE PARTIES

This section presents a general overview of the direct and rebuttal testimony, and

the positions of the parties as presented in their briefs. The record and arguments will 1 See 2 Tr 111.

U-17097 Page 3

be discussed in further detail in sections III through V below, as necessary or

appropriate to address the disputed issues.

A. DTE

Mr. Leuker is the Manager of Corporate Energy Forecasting, responsible for the

development of the economic and electric sales forecasting activities for DTE.2 He

presented DTE’s current electric sales and system output forecast for 2013 through

2017. His Exhibit A-8 presents annual electric sales forecasts for the four major rate

classifications, with net system output (including losses) and peak demand also shown.

The historical information is not weather-adjusted, while the forecasts assume normal

temperatures. Exhibit A-9 presents the sales and net system output on a monthly basis,

while Exhibits A-10 and A-11 present the annual sales forecasts for the four rate

classifications with the choice customer forecasts stated separately. Exhibit A-12

identifies major economic assumptions used in the forecast models.

Mr. Leuker testified that overall DTE is projecting a decrease in the temperature-

normalized sales of approximately 0.2% per year over the forecast period, with annual

sales increases for three of the four major customer classes projected, Residential,

Commercial, and Industrial. The 0.2% annual average decrease is driven by the

expiration of two wholesale contracts in the “Other” classification. He also testified that

DTE is not projecting any change in the Electric Choice sales.

Mr. Leuker testified that the sales forecasts are developed separately for

manufacturing, non-manufacturing, residential, and other categories, and gave

examples of the forecast for the automotive sector of the manufacturing category and

2 Mr. Leuker’s testimony is transcribed at 2 Tr 76-91.

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for the residential category. He testified that DTE’s Energy Optimization Plan under

2008 PA 295 is reflected in the company’s forecasts. He also testified regarding the

economic assumptions used in the modeling. Monthly sales forecasts were developed

based on modeling of hourly demand profiles into a system annual loadshape using a

model developed by EPRI, and the same HELM model was used to forecast annual and

monthly peak demands.

Mr. Palmer is Manager of Asset Optimization in the Fossil Generation

Organization. He presented DTE’s projected non-nuclear generation forecast for 2013

through 2017, including capacity, as shown in Exhibit A-24, as well as emissions as

shown in Exhibit A-25.3

He testified that these projections were made using the PROMOD model, and

that the 2013 projected capacity decrease is based on the retirement of the Dayton and

Conners Creek diesel peaker plants, with a projected capacity increase beginning in

2014 due to Ludington upgrades, another capacity decrease associated with the

auxiliary power usage from the FGD units scheduled to be installed in late 2013 or early

2014 on Monroe units 1 and 2. In 2015, he projects retirement for Harbor Beach and

Trenton Channel units, with a second Ludington upgrade completed. He testified that

based on anticipated environmental standards and the company’s expectations for the

use of certain emission control systems (Activated Carbon Injection and Dry Sorbent

Injection), River Rouge Units 2 and 3, St. Clair Unit 7 and Trenton Channel Unit 9 will be

able to cost-effectively meet the HCl and mercury emission limits, and Trenton Channel

3 Mr. Palmer’s testimony, including his rebuttal testimony and cross-examination, is transcribed at 3 Tr 437-535.

U-17097 Page 5

7 and 8, currently planned for retirement, may not actually be retired. He noted that

prior to retiring a unit, MISO must study the company’s proposal.

Mr. Palmer testified that emissions are also projected as an output of the

PROMOD modeling, and include NOx annual and ozone season emissions. In

projecting NOx emissions, he also projected the urea expense to control those

emissions, as shown in Exhibit A-26. Additionally, Mr. Palmer testified regarding DTE’s

plans to use REF coal to meet emission requirements, obtained through DTE’s REF

project described by Mr. Krishnamurthy, and provided expected usage rates for Monroe,

St. Clair, and Belle River. Mr. Palmer also presented rebuttal testimony and was cross-

examined.

Mr. Wines is Lead Engineer for Nuclear Generation with DTE.4 He presented

DTE’s nuclear fuel expense forecast for 2013 through 2017, as summarized in Exhibit

A-1. His testimony described the steps involved in a nuclear fuel cycle from mining to

disposal, and explained the company’s contracts for uranium ore, enrichment, and

fabrication. He characterized these as “front end” costs, with additional costs including

“in-core interest expense” recovered in base rates, and regulatory costs including the

SNF disposal fee of $1.00 per net MWh sold. He testified that the cost projections

underlying Exhibit A-1 are tied to projected generation, including planned outages for

refueling, surveillance and core management, as well as an allowance for unplanned

outages. Based on the generation forecast, the front end costs are amortized over a

specified number of fuel cycles, and total SNF disposal fees are projected. He testified

to his opinion that Fermi 2 projected fuel costs are reasonable and prudent by

4 Mr. Wines’ testimony is transcribed at 2 Tr 24-35.

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comparison to long-term price indicators for the ore and enrichment prices, and that

fabrication costs are well-controlled by maintaining small reload batch sizes.

Mr. Musial is Manager for Federal Regulatory Affairs for DTE, responsible for

managing the company’s participation in FERC proceedings, including those relating to

MISO.5 He testified to explain ongoing proceedings that could increase DTE’s PSCR

costs. These include MISO’s Transmission Expansion Plan, and its proposed

modifications to resource adequacy requirements currently pending before FERC. He

identified the positions DTE has taken in these proceedings, and provided his opinion

that DTE has taken all appropriate legal and regulatory actions to address matters

before the FERC that could impact PSCR customers. Mr. Musial testified that

transmission projects identified in his testimony are included in Mr. Shield’s projected

transmission cost estimates, and that the potential increased capacity obligations are

discussed further by Ms. Wojtowicz.

Ms. Wojtowicz is Manager of the Wholesale Power Group in the Generation

Optimization Department of DTE. In her position, she is responsible for the acquisition

of wholesale power. She testified to support the company’s PSCR year and five-year

forecast of its generation expenses, including purchase power requirements and

emission allowance expense, and to support approval under section 6j(13) of Act 304 of

capacity purchases under contracts in excess of six months.6

She presented Exhibits A-13 through A-19 in support of her testimony.

Exhibit A-13 contains projected fuel quantities and costs, projected purchases and sales

with associated costs and revenues, and total PSCR expenses for the five-year period

5 Mr. Musial’s testimony is transcribed at 2 Tr 93-108. 6 Ms. Wojtowicz’s testimony is transcribed at 3 Tr 536-600.

U-17097 Page 7

2013-2017. Exhibit A-14 shows monthly MISO wholesale energy price projections

based on forward trades on the International Exchange at the Indiana Hub, adjusted by

a $1.06 per MWh “basis adder”. It also separately projects MISO capacity prices, and

emission allowance expenses.

Regarding SO2 allowance projections, she testified that the company expects to

use 215,261 allowances in 2013, but will not make additional purchases to meet this

need. Exhibit A-19 shows beginning balances, annual allocations from EPA, and

expected sales and consumption for each year, along with the cost of allowance

consumed and a calculation of the REF SO2 emission benefit. Ms. Wojtowicz testified

that based on Mr. Palmer’s projected 4,198 ton decrease in SO2 emissions in 2013,

DTE will attempt to sell the corresponding 8,396 allowances at a rate of $0.75 per

allowance, resulting in $6,297 in avoided cost. Exhibits A-17 and A-18 contain Ozone

Season and Annual NOx allowance projections, including projected balances, annual

requirements and costs.

Exhibit A-15 shows for each year the capacity resources the company plans on

to meet MISO Resource Adequacy requirements, while Exhibit A-16 contains projected

volumes, costs, and revenues associated with power purchases and sales, including the

purchase of renewable energy under power purchase agreements, and purchases from

PURPA/Public Act 2 Qualifying Facilities. Ms. Wojtowicz also described the impact of

the company’s REF project on contracts DTE entered under 1989 PA 2.

Ms. Wojtowicz also testified in rebuttal and was cross-examined.

U-17097 Page 8

Mr. Shields is Manager of the Wholesale Market Developments unit in the

Regulatory Affairs department of DTE.7 Mr. Shields testified regarding the expenses

associated with DTE’s position as transmission customer of ITC Transmission and a

participant in the MISO market. His Exhibit A-5 presents projected network

transmission expenses and MISO Energy Market and Ancillary Services Market Cost

items, separately stated by MISO Tariff Schedule, including network transmission

services and upgrade charges, Reactive Supply services, MISO operating costs and

FERC assessment fee, as well as the MISO energy market and ancillary services

market participation charges and credits. Of the $251 million total cost in Exhibit A-5,

the base transmission cost is $247.5 million, and approximately $200 million of that

amount represents the ITC Transmission Zone charges. Exhibit A-6 shows a typical

MISO Settlement Statement, and Exhibit A-7 reflects DTE’s projections of the more

significant charges and credits for the forecast period 2013 to 2017.

Mr. Rogers is Senior Technology Specialist for Environmental Strategies,

Environmental Management, and Resources for DTE.8 His responsibilities include

managing and coordinating the company’s air quality strategy for all air toxics, and

focusing in particular on mercury emission requirements. Recognizing that DTE faces

more stringent environmental controls under the federal Mercury and Air Toxics

Standards (MATS) and the Michigan Part 15 Air Pollution Control Rules, which take

effect in 2015, he testified to DTE’s plans to meet these requirements. He explained

that DTE plans to use Wet Flue Gas Desulphurization (Wet FGD) in combination with

Selective Catalytic Reduction (SCR) to meet these requirements at its Monroe plant,

7 Mr. Shields’ testimony is transcribed at 2 Tr 37-74. 8 Mr. Rogers’ testimony, including rebuttal and cross-examination, is transcribed at 2 Tr 112-234.

U-17097 Page 9

and to use an Activated Carbon Injection system (ACI) for mercury control and Dry

Sorbent Injection (DSI) for acid gas control at its other units.

Mr. Rogers also testified that DTE has determined that using Reduce Emissions

Fuel (REF), obtained through the REF project described by Mr. Krishnamurthy,

improves the performance of both the FGD and ACI systems in meeting mercury

emission limits in the most cost-effective manner. He presented Exhibit A-2 showing

the cost of certain chemicals used to meet environmental restrictions for the five-year

forecast period, although no such costs are expected prior to 2015. DTE is requesting

that the Commission indicate that the cost of these chemicals may be recovered

through the PSCR factor and reconciliation. Exhibit A-2 also presents Mr. Rogers’

estimated savings of $5.6 to $5.9 million from the use of refined coal beginning in 2015,

attributable to the reduced use of PAC and BrPAC additives at the Belle River and St.

Clair plant to control mercury emissions, based on tests conducted at St. Clair.

Mr. Rogers also presented rebuttal testimony, and was cross-examined.

Mr. Krishnamurthy is Supervisor of Fossil Fuel Resources, Business

Development and Administration in the Fuel Supply department for DTE. He testified in

support of DTE’s fossil fuel expense projections for 2013 through 2017, shown in his

Exhibit A-20.9 He testified that the company plans to supply coal to its plants from a mix

of long term and spot term contracts. A chart in his testimony shows coal costs for each

numerically-identified supplier. He also discussed the oil and natural gas price

projections underlying the company’s PSCR plan.

9 Mr. Krishnamurthy’s testimony, including rebuttal and cross-examination, is transcribed at 3 Tr 601-720 and 4 Tr 726-809.

U-17097 Page 10

He also testified in support of the reasonableness and prudence of the

company’s Recued Emissions Fuel (REF) project. His calculations in Exhibit A-20

include a forecast of the “Coal Fee Rate” and “Refined Coal Adder” arising from

agreements between DTE and affiliated fuel companies formed to handle REF

transactions.10 Exhibit A-21 provides an overview of the projections; Exhibit A-22 shows

an example of the calculation of the Refined Coal Adder for the Saint Clair power plant

for July 2012. He also testified that the agreements with the affiliated fuel companies

comply with the Code of Conduct, presenting Exhibit A-23 in support of this testimony.

He testified that available tax credits available for production of the treated REF fuel

could only be used by a company other than a public utility, that one of DTE’s affiliates

(DTE Energy Services) obtained an exclusive license to use the REF chemical additives

at DTE’s plants, and that the arrangements subsequently entered with the fuel company

subsidiaries of that affiliate provide benefits to ratepayers that make DTE’s contracts

with those fuel companies reasonable and prudent.

Mr. Krishnamurthy also presented rebuttal testimony and was cross-examined.

Mr. O’Neill is Principal Project Manager for Regulatory Policy and Operations

Organization, responsible for the coordination and management of various MPSC filings

and other regulatory issues.11 He testified to the calculation of the PSCR factors for

2013, as well as projections for the years 2014 through 2017. These calculations are

presented in his Exhibits A-3 and A-4. Mr. O’Neill testified that the company’s PSCR

factor calculations include a projected underrecovery for 2012 of $81.182 million,

10 As discussed below, these fuel companies are Belle River Fuels Company, St. Clair Fuels Company, and Monroe Fuels Company. 11 Mr. O’Neill’s testimony including his rebuttal testimony and cross-examination is transcribed at 2 Tr 235-324.

U-17097 Page 11

pending a final order from the Commission in Case Nos. U-16047-R and U-16434-R.

And referencing Ms. Wojtowicz’s testimony, Mr. O’Neill testified that the company’s

power purchases are consistent with the company’s renewable energy plan.

Regarding the projected use of sorbents to control mercury and acid gas (HCl)

emissions beginning in 2015, Mr. O’Neill testified that the Company is seeking guidance

from the Commission regarding whether it is unlikely to approve recovery of these costs

in the company’s 2015 PSCR plan. He testified that the sorbents at issue (PAC and

BrPAC to control Mercury, and Trona or Sodium Bicarbonate to control HCl) are

analogous to the urea expenses the Commission has already approved for recovery

through the PSCR clause, citing the Commission’s November 13, 2008 order in Case

No. U-15415.

Mr. O’Neill also testified regarding the REF project, indicating that the use of REF

impacts many cost elements in the PSCR cost calculation, including the costs of NOx

and SO2 emissions allowances, payments to 1989 PA 2 suppliers, and the consumption

of Powered Activated Carbon (PAC) to dispose of fuel burned. He referred to Mr.

Krishnamurthy’s testimony for details regarding the implementation of the project at the

Belle River, St. Clair, and Monroe power plants, and to Mr. Rogers’ testimony regarding

the impact of REF on the company’s cost of Mercury emission reductions beginning in

2015.

Regarding the impact of REF on the PSCR factor, he testified that consumption

of REF will never increase the Company’s requested maximum PSCR factor, asserting

that the costs to customers are zero or less. Specifically addressing the REF Adder, he

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testified that the REF Adder will be zero if use of the REF does not reduce SO2

emission allowance expenses or provide cost savings in reducing mercury emissions.

He further testified that on a total rate basis, base rates plus PSCR, no costs

associated with the use of REF are borne by DTE customers, and on a PSCR basis, the

costs to customers are zero or less. He also testified that customers have already

experienced a benefit of the program through a reduction in working capital expense

due to the company’s sale of coal inventory to the fuel companies.

Mr. O’Neill also presented rebuttal testimony and was cross-examined.

B. MEC/NRDC

Ms. Richards is Senior Consultant with the energy consulting firm La Capra

Associates.12 She testified regarding DTE’s PSCR plan and five-year forecast,

identifying a concern that the company had not provided sufficient data or performed

sufficient analyses to justify what she characterized as its “business as usual”

projections. She presented an overview of historical and projected coal and PSCR cost

increases based on DTE data and projections, testifying that DTE’s coal and total PSCR

costs have been increasing and are projected to continue to increase at average annual

rates of 7% and 9% respectively. She further testified that DTE’s older coal plants are

running less, and producing less power, spreading plant costs including PSCR costs

over fewer MWhs and leading to higher customer bills. She testified that DTE’s power

supply plan does not consider lower-cost opportunities from declining natural gas prices

and wholesale energy prices, and that it should be exploring alternatives such as

12 Ms. Richards’ testimony is transcribed at 2 Tr 340-374.

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natural gas combined cycle (CGCC) capacity, increased demand-side management,

and increased renewable energy.

She also took issue with the analysis that DTE relies on to show that adding DSI

and ACI systems to its older plants is a reasonable and prudent investment. She

presented DTE’s analysis in her Exhibit MEC-10, along with related discovery

responses from DTE, and provided numerous criticisms of DTE’s analysis. She testified

that DTE failed to include a sensitivity analysis of key assumptions, failed to consider

alternatives other than a new gas-fired plant such as retirements, market purchases, or

PPAs, failed to recognize limitations in the ability of DSI systems to meet applicable

SO2 emission requirements, used a time frame that may extend beyond the retirement

of certain plants, assumed no carbon regulation, and used gas price projections above

EIA’s current projections.

In the short term, she testified, DTE could pursue actions to optimize its power

supply mix including reducing minimum run times on some of its coal plants,

investigating boiler operational changes to allow more flexible dispatch, and adjusting

coal purchasing agreements to provide greater flexibility to reduce purchase volumes.

Over the long term, she testified, DTE should evaluate the economics of continuing to

operate each of its older coal units. She presented data to show that utilities across the

country are increasingly retiring older coal plants.

Ms. Richards also took issue with DTE’s capacity cost projections, characterizing

them as inflated, and testifying that these capacity cost projections could not only raise

PSCR costs, but could affect other decisions underlying the company’s plan, including

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its decision to invest in emissions control technology for plants that she testified is not

cost-justified.

She presented Exhibits MEC-1 through MEC-22 to support her testimony.

Mr. Sansoucy is a consulting engineer with his own firm, George E. Sansoucy,

P.E., LLC. He testified regarding DTE’s REF project.13 After describing certain

elements of the transactions, and reviewing some of the available evidence, including

prior testimony submitted by DTE and discovery responses, he testified that the benefits

to DTE customers are not proportional to the benefits received by the fuel companies

from the transactions. He took issue with DTE’s quantification of a working capital

benefit to ratepayers, noting that although Mr. Lapplander in previous cases testified to

benefits on the order of $140 to $166 million, DTE was not planning to file a rate case

until 2015. He testified that DTE has refused to provide important information including

details of agreements between DTE Energy Services and the fuel companies. He also

took issue with DTE’s characterization of its agreements with the fuel companies as

arms-length agreements, arguing that DTE did not have access to its own counsel, and

reviewing some terms of these agreements to conclude that they were “unusual to say

the least”. As an example, he testified that DTE indemnifies the fuel companies’ risk by

guaranteeing to repurchase their investment in raw material if they are unable to

perform, with no corresponding remedy for damages to DTE if an adequate supply of

treated coal is not produced. He further testified that the transactions do not conform to

the Code of Conduct, or to the requirement of MCL 460.6j(13)(e), which requires the

Commission to disallow the cost of fuel purchased from an affiliate to the extent it is

more costly than fuel of requisite quality available at or about the same time. He 13 Mr. Sansoucy’s testimony is transcribed at 2 Tr 376-400.

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testified that DTE has failed to establish that it charges the fuel companies for storage in

the coal yard, or supported its claim that the coal handling and consulting agreements

are based on DTE’s actual costs of furnishing the services. Mr. Sansoucy

recommended that the Commission decline to approve any aspect of the program

based on a lack of sufficient information. He further recommended that if the

Commission does approve the program, it should impose certain conditions including

the incorporation of the full working capital benefit into PSCR rates, and a revision to the

Belle River agreements to parallel the discount paid by the Monroe Fuel Company.

Mr. Sansoucy provided Exhibits MEC-23 to MEC-43 in support of his testimony.

C. Attorney General

Mr. McGarry is President of Blue Ridging Consulting Services, Inc. He testified

to his concerns regarding the REF project costs, including his conclusion that the REF

Adder is not appropriate for Act 304 recovery because it is not a booked cost of fuel or

disposal.14 He testified that REF coal is not analogous to urea because it is applied

before the coal is burned and is thus more akin to coal handling than disposal. In

support of this testimony, he cited the Commission’s decision in Case No. U-14702 that

Mg(OH)2 costs are not recoverable under Act 304, and explained that boiler

improvements could also reduce emissions, but would clearly not be a recoverable

PSCR expense.

14 Mr. McGarry’s testimony is transcribed at 3 Tr 412-436.

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D. MCAAA

Mr. Crandall is a principal and Vice President of MSB Energy Associates, a

consulting firm in Wisconsin.15 He also testified regarding DTE’s REF project, providing

his opinion that the tax credits the fuel companies were created to take advantage of

should be recognized as a reduction to fuel costs in this proceeding. He testified that

$300 to $400 million in tax credits would not be available to the fuel companies or their

owners but for the existence of the ratepayer supported power plants and the services

provided by DTE. He recommended that the revenues should be recognized as an

offset to PSCR costs.

Mr. Crandall also took issue with Mr. Krishnamurthy’s claim it is reasonable for

DTE to sell coal to the fuel companies at its booked cost, without regard to the market

price, because increasing the sale price to reflect a higher market price at the time of

the transaction would only increase the resale price to DTE. Mr. Crandall testified that

this argument fails to recognize that the affiliated fuel companies may sell coal to third

parties, and generate a profit retained by the fuel companies rather than the ratepayers.

Mr. Crandall acknowledged DTE’s prior testimony in Case No. U-16434-R, confirming

that the fuel companies had not sold any refined coal to third parties, but testified that

future off-system sales are not foreclosed by the requirement that DTE consent to the

sale of refined coal. Mr. Crandall testified that requiring DTE to follow the Code of

Conduct by charging its affiliates the higher of fully allocated cost or market price for

coal would address this concern.

Additionally, Mr. Crandall took issue with DTE witness claims that DTE contracts

with the fuel companies were “arm’s-length transactions”. He asserted that the 15 Mr. Crandall’s testimony is transcribed at 2 Tr 327-338.

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affiliation between the companies, with all owned by the same parent, precludes the

contracts from being considered arm’s length, and reviewed Mr. Lapplander’s role as

negotiator for DTE and the complexity of the contracts to contend that Mr. Lapplander

was not put in an equal position in negotiating the contracts.

E. Rebuttal

DTE was the only party to present rebuttal testimony. Mr. Krishnamurthy and Mr.

O’Neill provided rebuttal regarding the REF fuel issues, while Mr. Palmer, Ms.

Wojtowicz, Mr. O’Neill, and Mr. Rogers provided rebuttal to Ms. Richards’ testimony

regarding DTE’s fuel supply diversity and power supply plan.

Mr. Palmer testified in support of the company’s PSCR plan, responding to Ms.

Richards’ criticisms that the plan lacked supporting data and analysis. He testified that

the company had provided an extensive amount of data in its filing, and in 300

discovery responses, including voluminous files containing PROMOD simulations. Mr.

Palmer testified regarding the company’s fuel mix that DTE has the ability to consume

alternative fuel as shown in his Exhibit A-27, including over 2000 MW of gas capacity, or

approximately 16% of its total generating capacity. He testified that this capacity is not

used significantly because MISO determines it is not economical. And he testified that

the company promotes fuel diversity through an extensive fuel blending program for its

coal units, presenting Exhibit A-29 to show its coal blending decisions to minimize the

cost of energy offered to MISO.

He characterized Ms. Richards’ testimony as recommending generally that the

company should retire some coal plants and replace them with a combined cycle

natural gas plant, due in part to the low capacity factors of those coal plants. He

U-17097 Page 18

testified that the low capacity factors for the coal plants were due in part to the

conversion over time from high BTU eastern coals to lower BTU western coals,

although the company has not reduced the MISO “Net Demonstrated Capacity” for

those units.

Regarding Ms. Richards’ testimony that natural gas prices are expected to be

lower than the forecast DTE used in its analysis, he presented Exhibit A-28 containing a

2013 forecast of natural gas prices. He testified based on this forecast that gas prices

are expected to increase significantly by 2035. He testified that the company has

increased the natural gas capacity of its Greenwood Unit from 550 MW to 785 MW, and

also gets the benefit any lower natural gas prices through MISO. And he testified that

the company does look for opportunities to cycle its coal plants by reducing minimum

output levels to take advantage of potentially-lower cost MISO energy resources.

He further testified that DTE has evaluated alternatives such as a new natural

gas plant as shown in Exhibit MEC-10, testifying that in this analysis, the company

compared the levelized cost of adding new environmental control equipment to existing

coal units to the cost of building new combined cycle and determined it is not the least

cost alternative for its customers.

Ms. Wojtowicz also testified in rebuttal to Ms. Richards’ testimony regarding

DTE’s fuel supply diversity, DTE’s power supply plans, and its forecast of future MISO

market power purchase costs. Responding to Ms. Richards’ testimony regarding that

the company’s fuel mix in 2017 was projected to the same as 2008, Ms. Wojtowicz

testified that the company’s fuel mix includes 9% renewable energy by 2017. She

testified that MISO determines the lowest possible cost to serve demand and reserve

U-17097 Page 19

requirements while maintaining transmission system reliability, and thus determines the

dispatch of the company’s coal units when they are economic compared to other

generating resources. She further testified that natural gas plants have been

dispatched at capacity factors significantly less than coal plants.

Ms. Wojtowicz took issue with Ms. Richards’ testimony that DTE is overprojecting

power supply costs, arguing that Ms. Richards did not increase Indiana Hub prices by

the additional $1/MWh average cost at DTE’s load node.

And she testified in defense of the company’s strategy for bidding resources into

MISO’s Planning Resource Auction, testifying that DTE’s strategy protects PSCR

customers from paying for more capacity than needed. Ms. Wojtowicz also took issue

with Ms. Richards’ testimony regarding the capacity price projections in Exhibits A-14

through A-16. She testified that actual PSCR costs will be based on actual costs, and

that PJM capacity prices are not comparable for projecting MISO capacity prices.

Mr. Rogers’ rebuttal testimony addressed DTE’s ability to comply with potentially

more stringent SO2 emission limits using DSI. Responding to Ms. Richard’s testimony

that more stringent emission limits should be expected that would require an FGD

system, Mr. Rogers testified that additional SO2 reductions can be achieved using the

DSI system by increasing sorbent injection rates.

Mr. O’Neill testified in rebuttal to Ms. Richards regarding the DTE PSCR plan’s

compliance with Act 304. He testified that DTE’s plan complies with the statutory

requirements and prior Commission orders, and relies on “existing assets instead of

hypothetical assets” for the plan year.

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Mr. O’Neill also testified in rebuttal to Messrs. McGarry, Crandall, and Sansoucy

regarding their objections to the REF project, including project compliance with Act 304

and the Code of Conduct, and the project working capital benefits identified by DTE

304’s directive to minimize the cost of power. He explained DTE’s position that the REF

project costs meet the requirements for recovery under Act 304 because REF facilitates

the separation and disposal of various byproducts and emissions associated with the

combustion of coal, likening REF to urea costs that reduce emissions. He testified that

the REF project costs are not fuel handling costs, which are not recoverable under Act

304, in part because they are incurred before DTE receives the coal. Mr. O’Neill cited

Mr. Krishnamurthy’s testimony in explaining DTE’s position that the Code of Conduct

did not anticipate the situation where DTE and an affiliate would plan to buy and sell

identical assets to each other. Addressing Mr. Sansoucy’s testimony regarding the

working capital benefit DTE ascribes to the project, he acknowledged that the benefit

included in Exhibit MEC-32 has not been entirely reflected in rates, but also testified that

current DTE fuel inventory values are significantly above the rate case values.

Mr. Krishnamurthy’s rebuttal testimony also responded to Mr. Crandall’s and Mr.

Sansoucy’s testimony regarding the REF project. He testified to DTE’s position

regarding the production tax credits sought by the fuel companies, asserting that DTE

would not have been eligible for those credits, and presented Exhibits A-31 to A-32 to

further explain this position. He also reviewed the structure of the REF transactions,

and testified to his opinion that the benefits DTE customers receive under these

transactions are equivalent or better than similar REF projects undertaken by other

utilities or available to DTE. He presented Exhibits A-33, A-34 and A-37 to provide

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information regarding these alternative projects.16 Additionally, he testified that the

project complies with the Code of Conduct, and reviewed the benefits of the project,

concluding that DTE has negotiated a reasonable and prudent arrangement for REF at

its facilities. His Exhibit A-35 contains additional information to support DTE’s

contention that it was not eligible for tax credits for the production of refined coal, and

Exhibit A-38 contains calculations to show the working capital benefit.

F. Issues presented

The briefs generally reflect the positions and disputes identified and addressed

by the witnesses as discussed above. DTE argues that its plan and proposed factors

are reasonable and prudent, and takes issue with the concerns raised by the

intervenors. Staff supports the company’s plan and proposed factors, arguing that they

are reasonable and prudent.

MEC/NRDC contends that the company has not adequately demonstrated the

reasonableness of its forecast of generation and purchased power, and also challenges

the company’s decision to upgrade some of its plants with DSI and ACI when it was

planning to retire those plants in its last plan case. MEC/NRDC also objects to the REF

project as providing insufficient benefits and violating the Code of Conduct and Act 304.

MEC/NRDC does not specifically challenge the purchased power or capacity price

projections in DTE’s plan. MCAAA and the Attorney General focus only on the REF

project. MCAAA broadly argues that the REF project is unreasonable, and violates Act

304 and the Code of Conduct. The Attorney General argues that the project costs are

not appropriate for PSCR recovery.

16 Exhibit A-33 was not admitted by agreement of the parties. See 4 Tr 817-818.

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DTE responds that its forecast is reasonable, that its analysis of the best

interests of its customers as reflected in its plan is reasonable, and that the REF project

provides ratepayer and PSCR customers benefits without increasing costs.

In the discussion that follows, the forecasting issue is discussed in Section III,

DTE’s plan to install ACI and DSI systems at plants slated for upcoming retirement in its

last plan case is discussed in Section IV, and the REF project is discussed in Section V.

III.

GENERATION FORECASTS

DTE’s plan relies in part on the generation and emission forecasts produced by

the PROMOD model testified to by Mr. Palmer. In its brief, MEC/NRDC takes issue with

DTE’s forecasting methodology, contending that the company has consistently

overprojected its own generation, and correspondingly underprojected MISO market

purchases and cost. MEC/NRDC presents tables in its brief containing a review of the

history of DTE’s projections of generation, MISO purchases, and the total cost of MISO

purchases, over the time period 2005 to 2012. Noting that actual MISO purchase

volumes were more than double projected purchases in several years during that

period, MEC/NRDC argues that these underprojections are in part responsible for large

underrecoveries identified by DTE in prior PSCR reconciliation cases, also listed in a

table in MEC/NRDC’s brief.

On this basis, MEC/NRDC argues that the company’s current forecast of

generation and market purchases should be considered unreliable, and thus the plan

based on that forecast should be considered unsupported and unreasonable. In further

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arguing that the Commission should not view the forecasting errors as simply an issue

for the reconciliation, MEC/NRDC argues that the forecasts form the basis for planning,

and this is the appropriate case in which to review the company’s plans:

Allowing DTE Electric to punt issues regarding the reliability of its projections to the reconciliation process would undermine the value of the five-year power supply forecasting by enabling the Company to continue to present an overly-rosy view in support of its increasingly costly and decreasingly competitive business-as-usual strategy.17

Additionally, MEC/NRDC argues that the company’s PSCR spending is based on its

plan, and that the company’s burden to show the reasonableness and prudence of its

actions in a reconciliation is different if the company has complied with an approved

plan.

In its reply brief, MEC/NRDC further argues that the only testimony DTE cited in

its initial brief in support of the reasonableness of these projections is Ms. Wojtowicz’s

testimony at 3 Tr 565: “[T]he projection of Detroit Edison’s generation and purchased

power were developed from an economic dispatch forecast.”18 MEC/NRDC also notes

Mr. Palmer’s testimony that DTE’s forecast uses a methodology that is “largely the

same as that used in General Electric Rate Case Nos. U-13808, U-15244, U-15768,

and U-16472, the Show Cause Case U-14838, and in the 2005, 2006, 2007, 2008,

2009, 2010, 2011, and 2012 Power Supply Cost Recovery Plan Case Nos. U-14275,

U-14702, U-15002, U-15417, U-15677, U-16047, U-16434 and U-16892.”19

In response to MEC/NRDC’s critique of its forecast, DTE cites Ms. Wojtowicz’s

testimony and exhibits,20 as well as Mr. Palmer’s testimony and exhibits.21 DTE asserts

17 See MEC/NRDC brief, page 15. 18 See MEC/NRDC reply brief, page 5. 19 See 3 Tr 449-450. 20 See 3 Tr 544-565, 558-559, and Exhibits A-13 to A-19.

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that Ms. Wojtowicz explained how the company reasonably and prudently developed its

projections for generation and power, and Mr. Palmer also supported DTE’s projected

generation, capacity and emissions, and associated expenses as reasonable and

prudent.22 DTE argues that MEC/NRDC concedes in citing Mr. Palmer’s testimony that

DTE’s projections are consistent with the methodology approved by the Commission in

prior cases.23 Characterizing its forecast as a “well-established methodology,” DTE thus

argues that MEC/NRDC has the burden to establish a contrary position based on new

evidence or changed circumstances, and objects to MEC/NRDC’s failure to present

witness testimony on this topic.24

DTE further argues that statistics on past accuracy are necessarily based on

“impermissible hindsight”, citing Detroit Edison Co v Public Service Comm, 264 Mich

App 462, 465; 691 NW2d 61 (2005) as well as Const 1963, art 6, § 28. DTE then

asserts:

The company produces reasonable forecasts based on numerous factors with the best information that is available at the time of filing, which is three months before the beginning of the PSCR plan year. It is unrealistic to expect to predict the future with precision as MEC/NRDC suggest. Furthermore, what MEC/NRDC conveniently omits to mention when comparing the Company’s projections for generation, MISO market purchases, and market purchase costs provided in PSCR Plan cases with actual results for the same in subsequent PSCR reconciliation cases is that both projections and actual results were approved by the Commission as reasonable and prudent. . . Moreover, the fact that MEC/NRDC concedes in its Initial Brief that the Company’s present projections for the 2013 PSCR Plan case are consistent with the methodology approved by the Commission in the Company’s past PSCR Plan cases only supports approval of such projections in this PSCR Plan case. (See MEC/NRDC Initial Brief, p. 9)25

21 .See 3 Tr 446-452 and Exhibit A-24 to A-26 22 See DTE reply brief, page 5. 23 See DTE reply brief, pages 7, 9. 24 See DTE reply brief, pages 7-8. 25 See DTE Reply Brief at pages 8-9.

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Finally, on this topic, DTE argues that MISO dispatch considers numerous factors in

addition to cost, including reliability, minimum run time and ramp rates, availability of

generating units and transmission lines, and that actual weather will differ somewhat

from the normalized weather used in forecasting.26

This PFD finds that DTE provided only a very limited discussion or explanation of

its forecasting method on this record. Mr. Palmer identified himself as the witness

supporting the company’s projected generation in Exhibit A-24. As MEC/NRDC and

DTE quote, Mr. Palmer testified that the methodology used to develop the information

for the projections of power generation “is largely the same as that used” in DTE’s prior

PSCR and rate cases.27 In addition, Mr. Palmer testified:

The projections for generation were developed utilizing PROMOD IV, which is a production cost simulation computer program. The program simulates the economic dispatch of the resources available to develop the generation projections, fuel consumption requirements and emissions (which impacts emissions allowance expense). The heat requirements associated with the fuel consumption are then utilized by Company Witness Krishnamurthy to develop unit fuel cost and fuel expense.28

He further testified on cross-examination that the PROMOD modeling was done under

his direction29 and that he reviewed the inputs.30 But Mr. Palmer did not provide

testimony generally describing the inputs to the PROMOD model, indicating how the

inputs were chosen within any available range, or asserting that the values used were

reasonable and prudent choices, or based on the most recent information available.

26 See DTE reply brief, page 9. 27 See 3 Tr 449-450. 28 See 3 Tr 447. 29 See 3 Tr 517. 30 See 3 Tr 468.

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Instead, the most detailed testimony regarding the PROMOD projections came

from Ms. Wojtowicz. She sponsored Exhibit A-13, which contains DTE’s projected fuel

requirements, purchases and sales of power, and PSCR expense. She indicated that

the forecast generation was based on Exhibit A-24 supported by Mr. Palmer.31 She

then testified that the wholesale energy price projections for 2013 to 2017 shown in her

Exhibit A-14 are reasonable,32 and that the emission allowance expense projections

shown in Exhibits A-17, A-18, and A-19 are reasonable.33 Regarding Exhibit A-16,

which projects purchases under purchase power agreements, including renewable

energy agreements and agreements with PURPA/PA 2 Qualifying Facilities, wholesale

energy purchases and sales, and MISO energy market expenses, she testified that the

methodology used to develop the projections of MISO spot energy purchases and sales

is “largely the same as” the method used in prior rate cases and PSCR cases, and

further explained:

The wholesale energy purchases and sales were modeled in PROMOD based on projections of wholesale energy market prices, projected load, and generating unit projections. Wholesale energy purchase projections are a result of hours where the load is projected to be higher than the projected generation from the company’s generating units. Wholesale energy sale projections are a result of hours where the projected generation from the Company’s generating units is higher than the projected load.34

Ms. Wojtowicz presented the clearest testimony in support of the reasonableness and

prudence of DTE’s generation projections as follows:

As has been previously described, the projection of Detroit Edison’s generation and purchased power were developed from an economic dispatch forecast designed to reliably and economically serve the energy

31 See 3 Tr 545. 32 See 3 Tr 547-548. 33 See 3 Tr 564. 34 See 3 Tr 558-559.

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and demand requirements of the Company’s customers based on fuel cost, electricity market costs, and emission allowance costs. The forecast was evaluated based on historical operation and expected changes due to maintenance schedules, fuel costs, market-based electricity prices, shifting environmental regulations, and changes in Net System Output. The emissions were projected from the economic dispatch taking into account the market price of emission allowances required for generation. All relevant power supply elements were evaluated and reasonable and prudent projections were utilized to arrive at a reasonable and prudent power supply plan for Detroit Edison for 20123 and for the “out years” of 2014-2017.35

Ms. Wojtowicz has previously testified regarding the PROMOD model.36

While DTE objects to what it characterizes as “speculation” by MEC/NRDC legal

counsel regarding deficiencies in its forecasting, DTE itself speculates regarding what

MEC/NRDC witnesses would be willing to testify to when it argues: “Apparently even

MEC/NRDC’s witnesses would not support their proposition that projection should

achieve a certain level of precision.”37 Further, DTE attempts to supplement the record

by asserting without citation that DTE “produces reasonable forecasts based on

numerous factors with the best information that is available at the time of filing, which is

three months before the beginning of the PSCR plan year,” and that it is “unrealistic” to

expect more precise predictions.38

Although there is no direct testimony regarding the timeliness of the information

used to produce the forecasts presented, and no analysis of the accuracy of the model

or of the potential accuracy of generation forecasting models generally, it is difficult to

conclude on the basis of this record that DTE’s forecast methodology is flawed.

MEC/NRDC is essentially asking the Commission to conduct its own analysis of the

35 See 3 Tr 564-565. 36 See Palmer, 3 Tr 465. 37 See DTE reply brief, pages 7-8. 38 See DTE reply brief, page 8.

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forecast accuracy based on a review of the projections submitted in prior cases

compared to the actual results. Exhibits MEC-54 and MEC-55 contain the projected

and actual values, but DTE’s projections are weather-normalized, and the actual results

presumptively are not weather-normalized. Nor is it clear that prior underprojections of

MISO market purchases have contributed to the company’s past underprojections of

PSCR costs. Note that the actual purchases shown in the tables in MEC/NRDC’s brief

take place at lower average unit costs than projected. That is, looking at 2012 for

example, the projected market purchases shown in Table 3 of MEC/NRDC’s brief had a

unit cost of $40.20 per Mwh, using the volumes from Table 2, while the actual market

purchases had a lower unit cost of $36.00 per Mwh.

Nonetheless, while this PFD does not conclude that DTE’s PROMOD forecasts

are unreasonable, this PFD recommends that the Commission caution DTE that it has

an obligation to continually evaluate the reasonableness of its projections when making

decisions that impact PSCR costs, and additionally, caution DTE that witnesses

sponsoring PROMOD projections in future cases need to provide detail to support the

reasonableness and prudence of the inputs chosen, identify key assumptions that have

a significant impact on the output of the model, and explain how the company evaluates

the reasonableness of the overall results. Acknowledging that DTE provided extensive

information to the parties to this proceeding through the discovery process,39 the record

lacks much of this explanatory material. Only Ms. Wojtowicz testified that the company

made an effort to evaluate the reasonableness of the PROMOD results. In contrast, Mr.

Leuker’s testimony explaining the sales forecasts by rate classification contains

39 See Palmer, 3 Tr 456.

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substantially more detail regarding the assumptions and inputs to the regression

analysis, and the use of the HELM model.40

IV.

DSI/ACI PLANS FOR MID-TERM COAL PLANTS

MEC/NRDC challenges DTE’s plan to use Dry Sorbent Injection (DSI) and

Activated Carbon Injection (ACI) systems to meet stricter environmental requirements

expected to take effect in 2015, arguing that several of DTE’s older plants were

candidates for retirement in DTE’s last plan case, and DTE has not established that it is

economically justified to incur the additional costs necessary to operate these plants in

compliance with the stricter environmental requirements. MEC/NRDC’s argument

focuses on a Levelized Cost of Electricity (LCOE) analysis DTE provided in response to

discovery (Exhibit MEC-10), and Ms. Richard’s testimony.

Following up on its criticisms of the company’s projection of its own generation,

MEC/NRDC agues as background that DTE has been experiencing and is projecting

sharply increasing PSCR costs. Ms. Richards testified to annualized average cost

increases of 7% per MBtu for coal, and 9% per kWh for PSCR costs, with per unit

PSCR costs projected to triple over the time period 2004 to 2017.41 MEC/NRDC

asserts that a reason for the cost increase is DTE’s failure to recognize changed market

conditions that make its aging generating fleet less competitive. In this context, Ms.

Richards presented statistics showing increasing numbers of coal plant retirements

across the county, and indicating the average age of these plants is in the range of 50 40 See 2 Tr 76-91. 41 See 2 Tr 349-351, Exhibits MEC 3 and MEC 4.

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to 57 years, and that these plants have higher heat rates indicating they are less

efficient.42 She also presented information showing the ages and average heat rates of

DTE’s coal plants.43 Focusing on DTE’s levelized cost analysis in Exhibit MEC-10,

MEC/NRDC argues that numerous shortcomings cause the analysis to understate the

costs of DSI and ACI, and overstate the cost of alternatives.44

DTE argues in response that MISO dispatch decisions and DTE’s use of lower

Btu-content Western coal are responsible for declining capacity factors, and

characterizes MEC/NRDC as pursuing an anti-coal agenda. It does not dispute the past

and projected cost increases, or the age of its plants.

DTE also argues that the Commission has already approved recovery of sorbent

costs in its June 28, 2013 order in Case No. U-16892.45 DTE argues that in this earlier

case, it established that ACI is the most efficient and cost effective method for mercury

emission reductions. It also cites Mr. Rogers’ testimony regarding the company’s

planned use of sorbents to meet federal Mercury and Air Toxic Standards (MATS)

requirements beginning in 2015, including mercury and acid gas limits.46 DTE

addresses MEC/NRDC’s critique of its levelized cost analysis as follows:

MEC/NRDC criticize the Levelized Cost of Energy (“LOCE”) analysis that is one of the bases of support for using DSI and ACI as part of a least cost strategy to comply with environmental requirements (MEC/NRDC Initial Brief, pp 30-37). There is no substance to the criticisms, however, which instead merely suggest that different results could be obtained through the speculative use of different inputs, such as the possibility of additional costs to control SO2 emissions, or the possible creation of a carbon tax or other cost at some assumed price. The Company has and will continue to consider such matters, but presently it is more economical to adapt

42 See Exhibits MEC-17 through MEC-19. 43 See Exhibit MEC-20. 44 See e.g. MEC/NRDC brief, pages 32-33, citing Richards, 2 Tr 357-359. 45 See DTE reply brief, pages 13-14. 46 See DTE reply brief, page 14.

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Edison’s existing generation fleet to comply with environmental regulations than it would be build a new generation fleet as MEC/NRDC suggests.47

DTE is correct that the Commission has ruled that sorbent expenses may be

recovered through the PSCR process, but incorrect that the Commission has approved

DTE’s plans to use sorbents at plants it was previously considering for retirement. In its

June 28, 2013 order in Case No. U-16892, DTE’s 2012 PSCR plan case, the

Commission ruled that such expenses are recoverable, as the cost of urea is

recoverable:

Sorbent expenses could be considered a cost of disposal because similar to urea, PAC and BrPAC are applied to reduce various emissions. Although the Commission declines to issue a warning, Section 7 does not preclude the Commission from disallowing recovery after a current PSCR plan year. The company will be required to show that these expenses are reasonable and prudent disposal costs in a future Act 304 proceeding.48

The Commission has thus concluded that the cost of sorbents used to meet emission

requirements may be recovered as PSCR costs, but only if the utility shows that its

decision to incur these costs is reasonable and prudent. MEC/NRDC argues that DTE

has not made this showing.

As referenced in the quoted passage above, in its June 28 decision in Case No.

U-16892, the Commission declined to issue a warning under MCL 460.6j(7) regarding

DTE’s planned use of ACI at several generating units. The Commission explained

MEC/NRDC’s position as follows:

MEC/NRDC stated that Detroit Edison did not evaluate whether retiring and replacing some of its aging coal units with other energy sources would reduce PSCR costs. MEC/NRDC recommended that the Commission indicate that it is unlikely, based on the evidence presented by Detroit

47 See DTE reply brief, page 15. 48 See June 28, 2013 order, Case No. U-16892, page 30.

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Edison, to allow fully recovery of its requested PSCR costs due to the company’s continued operation of its aging coal plants.49

As the Commission also explained, DTE had indicated that it expected to retire several

of its coal plant units in the 2015 to 2016 time period:

Detroit Edison also takes exception to the ALJ’s finding that it has not identified which coal plants are candidates for the emissions reduction system or closure in its five-year plan. Detroit Edison cites numerous exhibits that demonstrate that, following testing conducted in September and October 2011, specific units were recognized as candidates for dry sorbent injection and ACI, and other units, which are not expected to be candidates for these technologies, might indicate likely candidates for retirement.50

Because the Commission was not presented with the question whether DTE should add

DSI and ACI systems to plants planned for retirement, the Commission reviewed only

DTE’s proposals regarding St. Clair units 1 to 4 and Belle River.

Mr. Palmer explained the change from Case No. U-16892 in his testimony in this

case:

In Case No. U-16892 Company Witness Ms. Wojtowicz indicated that “the projected capacity decrease in 2015 is associated with possible retirements of Harbor Beach, River Rouge Units 2 and 3, St. Clair Unit 7, and Trenton Channel Units 7, 8, and 9 which are offset by the assumed addition of a combined cycle unit and the Ludington 5 upgrade”. Modified environmental rules and combined Dry Sorbent Injection (DSI) / Activated Carbon Injection (ACI) testing performed by the Company indicate that River Rouge Units 2 and 3, St Clair Unit 7 and Trenton Channel Unit 9 can cost effectively comply with the MATS rules utilizing DSI for acid gas emissions reductions and ACI for mercury emissions reductions. See testimony of Company Witness Mr. Rogers for additional discussion of this topic. Operation of River Rouge Units 2 and 3, St Clair Unit 7 and Trenton Channel Unit 9 beyond 2015 will also allow the deferral of the assumed need to build a new combined cycle power plant. The Company has assumed for PSCR planning purposes the retirement of Trenton Channel Units 7 and 8 in 2015; however, the ultimate retirement remains uncertain.51

49 See June 28, 2013 order, Case No. U-16892, pages 2-3. 50 See June 28, 2013 order, Case No. U-16892, page 17. 51 See 3 Tr 448-449.

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MEC/NRDC focuses its arguments in this case on those plants DTE excluded from its

five-year forecast in Case No. U-16892.

Mr. Rogers generally discussed the technology available to meet emission

requirements, and the projected cost of the chemicals or sorbents used with that

technology, but he did not discuss the economics of using either DSI or ACI at River

Rouge, St. Clair, or Trenton Channel in particular. Mr. Rogers’ discovery response in

Exhibit MEC-10 identified the company’s levelized cost analysis as the basis for his

conclusion that it is economically feasible for DTE to operate these plants using ACI and

DSI, and both Mr. Rogers and Mr. Palmer referred to this analysis in their rebuttal

testimony.

In the levelized cost analysis contained in Exhibit MEC-10, DTE compares the

cost of operating individual plant units using a combination of DSI/ACI as one

alternative, and using wet Flue Gas Desulphurization (FGD) with ACI as a second

alternative, levelized over the expected generation for each unit over a fifteen year

period to determine a per MWh price for each alternative. The units evaluated include

Belle River 1 and 2, River Rouge 2 and 3, St. Clair 1 through 4, 6 and 7, and Trenton

Channel HP and Trenton Channel 9. For each plant unit under each alternative, the

colored bar graph on page 2 of the exhibit identifies the component costs, including fuel,

emissions and disposal costs, and operating costs, as well as the DSI/ACI or FGD/ACI

costs. The analysis also presents the levelized cost of a combined-cycle gas-fired plant

over the 15-year period, based on an analysis Staff performed in Case No. U-16656. A

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23-page attachment to the discovery response (Attachment 3.114e) presents additional

detail regarding these costs.

In large part because the capital costs of FGD are higher than the capital costs of

the DSI/ACI combination, the analysis shows a higher levelized cost for meeting

environmental requirements using FGD compared to DSI with ACI. In this analysis, the

levelized costs computed for the units using FGD exceed the levelized cost of the

combined-cycle gas plant, while the levelized costs using DSI fall below the levelized

cost of the combined-cycle gas plant, to varying degrees. Page 1 of the Attachment to

Exhibit MEC-23 shows the computed levelized costs: the value assigned to the

combined cycle plant is $71.16 per MWh, while the levelized costs estimated for

DSI/ACI option at River Rouge 2 and 3, St. Clair 1 through 4, 6 and 7, Trenton Channel

HP and Trenton Channel 9, are as follows: $68.10, $67.90, $60.41, $61.41, $54.21,

$66.77, and $52.71 per MWh, respectively.

Ms. Richards criticized this analysis for several reasons, principally focusing on

the company’s failure to include any sensitive or error analysis that would reflect the

uncertainties surrounding the underlying assumptions:

In discovery response included in Exhibit MEC-10, the Company acknowledged that it did not perform any sensitivity analyses to test the comparative economics of its proposed continued reliance on existing coal units under varying market assumptions. Nor did the company look at retirement or replacement scenarios involving a combination of resources such as increased renewable generation or energy efficiency, market purchases, PPAs, purchase of existing NGCC capacity, expansion of existing NGCC generation, and increased demand response.52

Ms. Richards took issue with DTE’s assumption that it could meet all SO2

requirements with DSI, noting that the River Rouge and Trenton Channel units are

52 See 2 Tr 357-358.

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located in an area the U.S. E.P.A. is proposing to designate as a non-attainment area

for SO2, making it likely additional controls would be required. She also objected to

DTE’s use of a 15-year time frame for its analysis, given the age of the plants. In its

analysis, DTE assumed that the plants would face no additional future costs to control

carbon emissions, which Ms. Richards testified is an unreasonable assumption. And

she testified that recent natural gas prices she reviewed are lower than the natural gas

price assumptions underlying the levelized cost of the natural gas combined cycle plant

presented in Exhibit MEC-10. She summarized the analysis that in her opinion DTE

should have performed:

I would expect the Company to provide cost benefit analysis in which it compares it current mix of resources using a number of varying capacity factors, fuel price assumptions, cost assumptions, needed investments, etc., to alternative resource options such as switching existing coal plants to natural gas, building new power plants, greater investment in renewable energy, energy efficiency, and demand side management, and larger purchases from the market.53

Mr. Rogers also provided rebuttal testimony in response to Ms. Richards’

testimony, disputing that DTE might need additional controls in addition to DSI to meet

future SO2 limits. He testified that Ms. Richards “mischaracterizes both DTE Electric’s

DSI testing results and the certainty of any potential requirements resulting from future

rules or regulations,”54 testifying that more stringent SO2 limits could be met with

additional sorbent injections.55 He also testified that it is too early to determine whether

additional SO2 reductions will be required to bring the SO2 non-attainment area into

compliance.

53 See 2 Tr 360. 54 See 2 Tr 133. 55 See 2 Tr 134.

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In his rebuttal testimony, Mr. Rogers also directly addressed the portion of the

LCOE analysis that assumed zero carbon control costs over the fifteen year period

2015 to 2030:

The likelihood, timing and impact of any potential carbon cost vary year to year depending on various factors including political and public opinions, as well as the regulatory rulemaking process. While the LCOE analysis that was provided in discovery did not include an assumed cost for carbon, the company has and will continue to consider the potential for carbon costs in future PSCR plan cases. Nonetheless, the LCOE estimate provided demonstrates that the significant cost difference between the majority of the Company’s coal units and a new combined cycle is large enough to support the inclusion of carbon costs. This is especially true the further past 2020 the carbon cost is implemented.56

Mr. Palmer testified that the analysis in Exhibit MEC-10 shows that building a new

combined cycle plant is not the least cost alternative for customers.57

This PFD finds that Ms. Richards has identified a general deficiency in DTE’s

analysis, in that DTE has not fully evaluated the reasonableness of its assumptions.

The capital costs associated with the ACI/DSI systems are shown on page 7 of

Attachment 3.114e in Exhibit MEC-10. For those coal plants Mr. Palmer identified that

DTE was considering retiring in Case No. U-16892 (River Rouge 2 and 3, St. Clair 7

and Trenton Channel 9), the capital costs total approximately $99 million for DSI, and

$18 million for ACI. The two River Rouge units will be 58 years old in 2015, and 73

years old in 2030. The capital cost of adding ACI/DSI to these units is approximately

$45 million. Particularly with regard to these units, DTE has not explained why it is

reasonable to assume that they will be able to continue to operate over this 15-year

time span, without major capital repairs.

56 See 2 Tr 135. 57 See 2 Tr 461.

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The other two units, St. Clair 7 and Trenton Channel 9, are younger, and would

be only 61 years old at the end of the 15-year cost-recovery period. But for these units,

DTE’s levelized cost analysis assumes that the units will have average capacity factors

69% and 73% respectively over that period, as shown in Exhibit MEC-10, page 2 of the

23-page attachment. These capacity factors are above the reported capacity factors for

these units for each of the last five years, as shown in Exhibit MEC-5, page 1. Because

DTE’s analysis does not evaluate the sensitivity of the results to potential variation in

underlying assumptions, it has not shown that it has a reasonable basis for making the

capital investments in these units.

Accepting Mr. Rogers’ testimony that no additional capital costs will be required

to control SO2 emissions, nonetheless additional sorbent costs for the River Rouge and

Trenton units in an area EPA proposes to designate as a non-attainment area for SO2

should be considered in a reasonable analysis. Likewise, looking over a fifteen-year

period, it is reasonable to consider whether a decision to retro-fit these plants would be

reasonable if additional costs to address carbon emissions were required.

DTE’s argument that it will continue to evaluate issues such as the potential cost

of carbon does not address the point that such uncertainties call into question the

reasonableness of investing $100 million or more in plants near the end of their useful

life. DTE has not included in its analysis any additional capital costs that could be

expected to keep these plants running for the full fifteen-year period of its evaluation, at

the same time it seems to acknowledge that 65 years is a reasonable estimate of the

life-expectancy of the plants. 58

58 See Exhibit MEC-13, page 2, relying on an MPSC Capacity Needs Forum Report as the basis for the 65-year life expectancy.

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To argue as MEC/NRDC does that DTE has failed to justify the costs of adding

DSI and ACI systems to coal plants nearing the end of their useful lives does not equate

to a conclusion that DTE should build new generation. The cost of the gas-fired plant

was the benchmark DTE chose to use in its levelized cost analysis, presumably

because based on its prior planning, that was its next preferred alternative. But DTE

could have evaluated the levelized cost of its alternatives against any number of

benchmarks, including the cost of operating fewer units or the cost of purchased power.

Indeed, Ms. Richards recommended that the company perform this evaluation, as

quoted above. And Ms. Wojtowicz testified that DTE is already planning to obtain

additional capacity to meet its reliability requirements as follows:

The Required Capacity Purchases [shown on Exhibit A-15] are the forecasted amount of additional capacity needed to be acquired in order to achieve the amount of total resources required to serve Detroit Edison’s forecasted adjusted full service customer peak demand including the MISO planning reserve margin. The Company currently anticipates purchasing this capacity from the wholesale electric power market. The Company expects to purchase 1, 071 MW of capacity for the 2013 Resource Adequacy Planning Year. At this point, planning to purchase capacity from the wholesale power market is the economic, reasonable and prudent decision given the uncertainties regarding the amount of Electric Choice load, market prices, and environmental regulations.59

She testified that DTE would procure capacity “through one, or a combination of, the

following competitive processes; (1) a competitive auction, similar to the ones held by

the Company for procuring capacity for the summers of 2008 through 2012, (2) a

request for proposals, and/or (3) participation in the MISO PRA which will award bids

based on least-cost offers.”

59 See 3 Tr 552.

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Because DTE has not fully analyzed the economics of upgrading River Rouge

Units 2 and 3, St Clair Unit 7 and Trenton Channel Unit 9 with ACI and DSI systems,

this PFD recommends that the Commission caution DTE that notwithstanding that

sorbent costs are recoverable PSCR costs, DTE should not expect to recover PSCR

costs associated with uneconomic investment in plants that were considered for

retirement in Case No. U-16892. Recovery of such costs in 2015 and beyond will turn

on whether DTE can show that its investment was economically justified based on a

more comprehensive analysis that reasonably considers the uncertainties associated

with its assumptions.

V.

REF PROJECT

DTE entered into a series of contracts beginning in 2009 providing for the

purchase of treated coal from affiliated fuel companies formed by DTE’s parent

corporation for the purpose of producing the treated coal and to take advantage of

federal tax credits available under section 45 of the Internal Revenue Code. DTE

argues that the treated coal, known as “Reduced Emissions Fuel” (REF) or “refined

coal”, will enable it to meet emission requirements at its Belle River, St. Clair, and

Monroe plants at zero or less cost to PSCR customers, and an overall benefit to

ratepayers.

In order to produce the treated coal, the affiliated fuel companies own pug mills

at the plant sites; coal is fed into the pug mills and proprietary chemicals Mersorb and

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S-Sorb are mixed with the coal before it is delivered by conveyor to the plant.60 Cement

kiln dust used in the process is also stored on site in a silo. Mr. Krishnamurthy

presented testimony to explain the benefits and costs of the project for DTE. Although

he did not negotiate the agreements, he was involved in a supporting role to DTE

employee Gary Lapplander, who did negotiate the agreements. Mr. Krishnamurthy

presented Exhibit A-21 to provide an overview of the project. Other DTE witnesses also

testified regarding benefits and costs of the project, including Mr. Rogers and Mr.

O’Neill, as well as Mr. Palmer and Ms. Wojtowicz.

Intervenor witnesses Mr. McGarry, Mr. Sansoucy, and Mr. Crandall each took

issue with DTE’s reliance on the REF project. MEC/NRDC and MCAAA argue that the

REF project is unreasonable, asserting that there are not clear benefits to ratepayers,

there are additional risks, as well as the potential for affiliate abuse. The Attorney

General also challenges whether the costs of the REF project can be recovered under

Act 304.

In addition to the testimony and exhibits of these DTE and intervenor witnesses,

which include as exhibits portions of the testimony from prior proceedings, the record

also includes Exhibits A-30 and A-30 (Supplemental) from Case No. U-16434-R,

officially noticed by agreement of the parties at 2 Tr 111. These officially-noticed

exhibits contain the contracts between DTE and the fuel companies which DTE

provided in discovery in that case.61

60 See Lapplander, Exhibit MEC-34, pages 57-58; also see Exhibit A-21, page 4. 61 As discussed below, the record does not contain all the “Project Documents” referred to in those agreements.

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The arguments of the parties are reviewed below, followed by a review of the

Commission’s recent orders, and a review of the record regarding the REF project

elements.

A. Arguments of the Parties

As noted above, DTE argues that the REF project is a reasonable means of

meeting environmental standards at no cost to PSCR customers, with additional

benefits to ratepayers through reduced working capital costs from the transfer of a

portion of the utility’s coal inventory to the fuel companies:

On a total rate basis (base rates plus PSCR), there are no REF Project costs to Detroit Edison customers. On a PSCR basis, the costs of the REF Project to Detroit Edison customers are effectively zero or less and constitute a risk free option to help Detroit Edison attain the mercury emission reduction requirements contained in Michigan Rule 1503 beginning in 2015. . . Additional benefits also inure to Detroit Edison customers, including an immediate reduction in annual working capital expense through the sale of a portion of Detroit Edison coal inventory to the Fuels Companies. Edison customers are experiencing this benefit right now, every year, through reduced Detroit Edison base rates. . . REF also provides a cost-free reduction in NOx emission allowance expense. . . Edison’s customers will also befit from reduced SO2 emissions, and the reduced cost of mercury emissions compliance.62

DTE argues further that the project complies with the Code of Conduct adopted in Case

No. Case No. U-12134, and that none of the criticisms leveled by witnesses for the

intervenors are meritorious.

MEC/NRDC argues that DTE has not demonstrated that the REF project

represents “all appropriate actions to minimize the cost of fuel”, that the project as a

whole represents a “reasonable and prudent course of utility conduct”, or that it

complies with the Commission’s Code of Conduct and the Affiliate Transaction

62 See DTE brief, page 18, citations omitted.

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Guidelines adopted for DTE.63 MEC/NRDC further argues that the project

disproportionately benefits DTE’s parent corporation and affiliates, while increasing risks

to the utility. MEC/NRDC argues that DTE has substantially overstated the benefits of

the project, which may increase PSCR costs. MEC/NRDC also argues that the

agreements are not arm’s-length agreements, were not reasonably negotiated, and are

not justified by reference to the benchmarks relied on by DTE, contending that DTE

failed to pursue alternative structures for the project.

MCAAA argues that the Commission should disallow costs associated with the

REF transactions, contending that DTE has overstated any ratepayer benefits from a

reduction in working capital requirements and that future benefits from emission control

savings are small and speculative.64 MCAAA further argues that the transactions curtail

or greatly complicate the audit trail for DTE’s fuel expense, and that the transactions

violate Act 304.65

MCAAA also argues that that the tax credit revenues captured by the affiliate fuel

companies are only possible due to DTE’s coal supply chain, and coal burning plants,

all developed and supported by the ratepayers, and should therefore be recognized as

an offset to DTE coal costs, contending further that DTE’s recent reported PSCR

underrecovery of $148 million in Case No .U-16434-R resulted in part from failure to

properly recognize the REF transactions. MCAAA argues that imputing the tax credits

to offset the PSCR costs is a reasonable regulatory response to what it characterizes as

abuse of the affiliate relationships.

63 See MEC/NRDC brief, pages 39-92. 64 See MCAAA brief, pages 39-40. 65 See MCAAA brief, pages 40, 52.

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The Attorney General argues that the money DTE pays its affiliates should be

considered part of the unloading and handling expenses incurred after receipt of the fuel

by DTE, and thus not eligible for recovery as a PSCR cost. In his reply brief, the

Attorney General also argues that DTE’s arrangements with its affiliates provide them

with the production tax credits that DTE could have obtained.

DTE responds to these arguments in its reply brief, contending that customers

benefit from the REF program through reduced compliance costs, the Coal Fee Rate or

discount paid by MFC, and base rate reductions. Further, DTE argues that the

Commission has already approved the REF project in Case No. U-16892, and the

doctrine of collateral estoppel should be applied to preclude further review of the

reasonableness and prudence of this project.

DTE disputes the Attorney General’s argument that the REF project costs do not

qualify for recovery as PSCR expenses, arguing that Act 304 only limits recovery of

unloading and handling expenses incurred after the utility receives the fuel at the power

plant.66 DTE argues that DTE does not receive the fuel from the fuel companies until the

REF enters the power plants for “just in time” consumption. DTE cites the Commission’s

June 28, 2013 order in Case No.U-16892, and further argues that the REF project costs

are “disposal and processing costs” of fuel burned by the utility within the language of

MCL 460.6j(1)(a).

DTE argues that as the utility consuming the coal, it was not eligible to receive

tax credits under section 45 of the Internal Revenue Code, and that Act 304 does not

permit the Commission to impute tax credits realized by an affiliate company.67 DTE

66 See DTE reply brief, page 18-19. 67 See DTE brief, pages 18-34.

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also argues that there are no abuses of affiliate relations, asserting that there is no

basis for claims that the fuel companies do not adequately compensate DTE for coal

handling activities, and that such services are provided at cost because they are “only

supporting the provision of REF feedstock coal”.68 And DTE argues that the

transactions do not violate the Code of Conduct or Affiliated Transactions Guidelines,

citing the Commission’s order in Case No. U-16892 as well as Exhibit A-23. DTE

argues that shipments of coal are sold at the MERC transshipment facility for Belle

River and St. Clair, and rail shipments for Monroe are sold FOB mine and vessel

shipments are sold FOB vessel at MERC. DTE argues that the coal always remains

under the supervision and control of DTE and MERC, and separate books and records

are maintained.69

DTE further disputes characterizations by MEC/NRDC and MCAAA that the

transactions are not “arm’s-length”, arguing that MCAAA has failed to identify any “non-

arm’s-length” provisions in the agreements, and contending that it obtained benefits that

were equivalent, if not better than, similar REF projects elsewhere.70 DTE also argues

that there is no need for a comprehensive audit and review of the books and records of

DTE and its affiliates, noting that the Commission has broad audit authority under MCL

460.556, and has access to the books and records of the fuel companies pursuant to

the Guidelines for Affiliate Transactions contained in the January 21, 2003 order in

Case No. U-13502.

68 See DTE reply brief, pages 35-36. 69 See DTE reply brief, pages 39-43. 70 See DTE reply brief, pages 44-52.

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B. Prior Commission Orders

Because DTE argues that the Commission has already resolved the issues

raised by the intervenors regarding the REF project, it is appropriate to first review the

Commission’s prior orders. The Commission reviewed the REF project first in Case No.

U-16434, and again in Case No. U-16892. In its June 28, 2013 order in Case No.

U-16892, the Commission concluded that the REF project should be approved and

complies with the Code of Conduct and Guidelines:

The commission believes that the REF project is a reasonable means of attaining maximum emission reductions for minimum cost. AS explained by Detroit Edison, at SCPP and BRPP, PSCR customers will receive a reduction in annual working capital expense through the sale, at market price, or a portion of the company’s coal inventory to its affiliated fuels companies. The affiliated fuels companies will treat the coal with REF adder and then resell the treated coal to Detroit Edison. The cost of the REF adder will be offset by a corresponding savings in PSCR emissions allowance expense, resulting in a net cost of zero or less to PSCR customers. At MPP, Detroit Edison receives a coal fee rate from the affiliated fuels company, reducing the cost of every ton of coal treated with REF adder that is consumes, which translates into a credit for the company’s PSCR customers.71

MCAAA sought rehearing, arguing that more expansive records were being created in

other cases, including this one:

MCAAA argues that there are two other existing cases involving the issues surrounding the reduced emissions fuel (REF) program whose records are more complete than the record in this case, and urges the Commission to “resolve the REF regulatory and ratemaking issues on a more comprehensive basis, incorporating a review of the evidence and arguments made in the nearly contemporaneous cases, including DTE Electric’s PSCR reconciliation case for 2011, MPSC Case U-16434-R, and also DTE Electric’s Plan Case for 2013, MPSC Case U-17097.” . . . MCAA suggesting that the Commission may find that its holdings in the June 28 order on issues such as the Code of Conduct were premature. MCAAA asserts that the parties to the aforementioned cases have expended considerable resources on the REF program issues, and urges the

71 See June 28, 2013 order, pages 31-32.

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Commission to issue this order on rehearing contemporaneous with its orders in those two cases.72

Denying MCAAA’s petition for rehearing on the basis that it did not satisfy the

requirements of Rule 403, the Commission nonetheless held: “The Commission will

review the reasonableness of the REF expenses in Case Nos. U-16434-R and U-17097

based on the facts presented in those cases.”

In its reply brief, DTE argues based on the June 28, 2013 order that further

arguments regarding the REF Project are foreclosed under the doctrine of collateral

estoppel, although DTE acknowledges that doctrine is not directly applicable in

administrative proceedings.73 MEC/NRDC argues in its reply brief that the record in this

case is far more substantial than was before the Commission in Case No. U-16892,

noting that the contracts and other agreements between DTE and its affiliates are part

of the record. MEC/NRDC also asserts that the REF-related arguments in its reply brief

will focus largely on issues that were not implicated by the record in Case No.

U-16892.74 The Attorney General also argues that more complete evidentiary records

have been developed in this case and in Case No. U-16434-R.

This PFD concludes that the Commission’s order denying MCAAA’s request for

rehearing made clear that the Commission expected the REF project to be reviewed in

this docket. In the discussion that follows, the structure of transactions between DTE

and its affiliates is reviewed in section C, the environmental benefits are discussed in

section D, certain costs associated with the burning of REF fuel are discussed in

sections E, F and G, the “REF Adder” DTE pays BRFC and SCFC for refined coal is

72 See August 29, 2013 order, Case No. U-16892, page 5. 73 See DTE reply brief, page 21, citing Attorney General v Mich Pub Serv Comm, 291 Mich App 106, 122; 804 NW2d 574 (2010). 74 See MEC/NRDC reply brief, page 13.

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discussed in section H, the Coal Fee Rate paid to DTE by MFC is discussed in section

I, the working capital benefit to ratepayers is discussed in section J, Act 304 standards

and requirements are discussed in section K, the arguments regarding whether the

transactions are “arm’s length” are addressed in section L, and arguments regarding the

Code of Conduct are discussed in section M.

C. Structure of the Transactions

Exhibit A-21 was presented to show an overview of the transactions. As

described in that exhibit, for St. Clair and Belle River, the fuel companies:

-Finance and construct the REF facilities at Belle River and St. Clair -Purchase and carry the coal inventories at these plans and MERC for the duration of the projects -May be entitled to Section 45 Refined Coal tax credits generated from the sale of REF. These credits will be allocated to the partners based on ownership percentage.

In exchange, DTE will pay an REF Adder that “will never exceed the benefits received

by DE and is capped at the revenue requirement of the Fuels Company (environmental

benefits in excess of the project revenue requirement are retained by DE)” and will

“[p]rovide coal purchasing & consulting, coal handling, and other services through

contracts with the project companies.”75

At Monroe, Exhibit A-21 indicates the structure is the same, except that DTE

“retains the value of reduced SO2 and Hg emissions” and DTE receives a Coal Fee

Rate “on a tiered basis for each ton of RE Fuel purchased.”

The record also contains 18 agreements DTE has entered with the three fuel

companies, Belle River Fuel Company (BRFC), St. Clair Fuel Company (SCFC) and 75 See Exhibit A-21, page 7.

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Monroe Fuel Company (MFC). Since MEC/NRDC and MCAAA have identified the

contracts contained in Exhibit A-30 and Exhibit A-30 (Supplemental) from Case No.

U-16434-R as critical to an understanding of the transactions, and not part of the

evidentiary record in Case No. U-16892, this section reviews some of the key provisions

of those agreements, beginning with St. Clair.

1. St. Clair

Exhibit A-21 describes the “project documents” applicable to BRFC and SCFC as

follows:

License and Services Agreement: for a fee, provides for St. Clair/Belle River site access and infrastructure services to SCFC/BRFC. Refined Coal Supply Agreement: provides for SCFC/BRFC to sell DE Refined Coal at its book cost plus a REF Adder. At Belle River, there is no Adder during the testing period. Coal Inventory Purchase Agreement: provides for DE to sell SCFC/BRFC its coal inventory at book cost from Coal Yard and MERC. Coal Handling and Consulting Agreement: provides for DE to be a coal consultant on behalf of SCFC/BRFC and provides services such as to purchase, transport and handle adequate supply of coal and to ensure that SCFC/BRFC uses coal that conforms to the DE coal specifications. Acceptance Period Coal Inventory Purchase Agreement: provides for SCFC/BRFC to purchase portions of DE’s coal inventory at book cost from Coal Yard and MERC. Environmental Indemnity Agreement: provides for bilateral indemnification related to violation of any environmental law by either party.76

While these general descriptions are accurate, the agreements as a whole are

significantly more complex as discussed below. The agreements themselves also

identify other “project documents” that are not included in this record, including for

76 See Exhibit A-21, page 9.

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SCFC the “St. Clair Supply Agreement”, which is defined as an agreement “to be

entered into on or about the Commercial Operations Date, by and between St. Clair

Fuels Company and BR Fuels.”77

a. Inventory agreements

The Acceptance Period Coal Inventory Purchase Agreement dated December

18, 2009 provides for the purchase of “Coal Inventory” defined as “[T]he 700,000 net

tons of PRB Coal owned by [DTE]78 that is stored in the Coal Yard.” The purchase was

to take place on the “Coal Inventory Closing Date”, which was left open-ended under

the agreement,79 but DTE witnesses have testified that this transaction took place in

December of 2009. The price for this coal is stated in section 2.3 of the agreement to

be DTE’s “book value on November 30, 2009.”

The Coal Inventory Purchase Agreement, also dated December 18, 2009, was

subsequently amended as of December 1, 2010. The amendment extended the “Coal

Inventory Closing Date” from December 31, 2010 to March 31, 2011, and modified the

definition of “Coal Inventory”. The recitals indicate that the purpose of the agreement is

to provide for DTE to sell the Coal Inventory to SCFC for the duration of the agreement,

and to purchase coal inventory at the termination of the agreement. The Coal Inventory

to be sold is described as:

[T]he PRB80 Coal stored in the Coal Yard and Coal in Transit on the Coal Inventory Closing Date attributable to the St. Clair Power Plant as determined by the Coal Consultant.81

77 See, e.g., Exhibit A-30 (Case No. U-16434-R), page 361. 78 DTE is “Seller” under this agreement. 79 Section 2.6 provides: “The purchase and sale of the Coal Inventory pursuant to Section 2.1 shall occur on the date chosen by Purchaser (the “Coal Inventory Closing Date”) provided, that such date is reasonably acceptable to Seller.” 80 “Power River Basin” 81 See Exhibit A-30 (Case No. U-16434-R), page 469.

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The “Coal Consultant” means DTE acting under the Coal Handling and Consulting

Agreement, discussed below. The purchase price is contained in section 2.3:

The purchase price for the Coal Inventory shall be equal to the book value of the number of Tons of coal in the Coal Inventory as of the Coal Inventory Closing Date as reflected in Seller’s inventory records and in a certificate executed by an authorized officer of Seller in the form of Schedule 2.3(a) and delivered to Purchaser on or prior to the Coal Inventory Closing Date (the “Inventory Coal Purchase Price”).82

Although the recitals indicate the “coal inventory” (not capitalized) will be purchased by

DTE at the termination of the agreement, the agreement itself does not provide for this

purchase. As discussed below, this purchase is addressed in the Refined Coal

Purchase Agreement.

b. Refined Coal Supply Agreement

The Refined Coal Supply Agreement was entered into as of December 18, 2009,

and subsequently amended.83 The recitals provide that SCFC “desires to provide

refined coal produced at the Facility for use in [DTE’s] St. Clair Power Plant”; and DTE

“desires to purchase all of the PRB Coal feedstock requirements for the St. Clair Power

Plant in the form of Refined Coal output of the Facility, and otherwise in the form of

Resold Coal,84 as provided herein”.85

Section 5.1 is the principal section indicating DTE’s obligation to purchase all its

coal requirements for the St. Clair plant from SCFC. Section 5.1(a) provides:

82 See Exhibit A-30 (Case No. U-16434-R), page 453. 83 The amendment dates are March 1, 2010, January 7, 2011, and September 30, 2011 84 Resold Coal” is defined as “Available Seller Coal sold hereunder to [DTE] or to third parties as directed by [DTE]. The provisions governing Available Seller Coal are discussed further below. 85 See Exhibit A-30 (Case No. U-16434-R), page 356.

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During each Contract Year, in accordance with the terms of, and except as otherwise provided in this Agreement, (i) [DTE]86 shall procure and purchase from [SCFC] all of its requirements for PRB Coal and PRB Coal-based fuel for the Applicable Units (other than any coal purchased by [DTE] under a Back-Up Coal Purchase Contract in accordance with Section 6.1(b)), including Refined Coal produced by [SCFC] up to the Annual Cap, and (ii) [SCFC] shall use commercially reasonable efforts, in accordance with the Operating Protocols, to produce and sell to [DTE] Refined Coal in annual volumes equal to the Annual Cap and to the extent of its requirements, [DTE] shall purchase all Refined Coal so produced, and (iii) to the extent that such requirements as described in clause (i) are not fully satisfied by such Refined Coal . . . [SCFC] shall sell to [DTE] (and [DTE] shall purchase) Available Seller Coal, in amounts necessary to satisfy such requirements, as Resold Coal. The “Annual Cap” shall mean 1,800,000 tons per year, as may be increased pursuant hereto. [DTE] shall use commercially reasonable efforts at no additional cost to [DTE] to burn more than 1,800,000 tons per year of Refined Coal in the Applicable Units and, if [DTE] is able to burn more than 1,800,000 tons per year of Refined Coal in the Applicable Units, then the Annual Cap, for purposes of this Section 5.1(a) shall be increased to such amount.87

Section 5.1(b) reduces DTE’s obligation to purchase Refined Coal as necessary to

avoid any damage to the plant, referring to this as a “Reduction Event.” Section 5.1(c)

provides for a “Follow-up Period” after an initial period of commercial operation (the

Initial Acceptance Period) of the REF facility:

During the Follow-up Period, unless and until otherwise agreed by the Parties, each Party’s obligations under Section 5.1(a) will be suspended to provide the Parties time to review and analyze operating data and other information relating to the use by [DTE] of Refined Coal as fuel at the St. Clair Power Plant during the Initial Acceptance Period. During the Follow-up Period, [DTE] shall have the right, but not the obligation, to purchase Available Seller Coal as Resold Coal from Seller as set forth in Section 5.1(a).88

86 In quoting these agreements, this PFD generally substitutes party names for generic references such as “Seller”, “Buyer” or “Company,” since those terms are not consistent from agreement to agreement. 87 See Exhibit A-30 (Case No. U-16434-R), pages 436-437. Note that as provided in the amendment adopting this Annual Cap, the agreement also states in section 5.1(j): “[N]othing in this Article V will prevent [DTE] from discontinuing or reducing operation of the St. Clair Power Plant or any Applicable Unit prior to the end of the Term.” Id. 88 The January 7, 2011 amendment terminated the Follow-up Period. See Exhibit A-30 (Case No. U-16434-R), page 439.

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Section 5.1(f) provides:

Following the Follow-up Period, and subject to resolution of any Reduction Event as may be in effect, [DTE and SCFC] will cooperate and work together in good faith to optimize and maximize as soon as practicable the use of Refined Coal as a fuel at the St. Clair Power Plant and, in connection therewith, to determine the feasibility of using Refined Coal to satisfy [DTE’s] requirements for PRB Coal and PRB Coal-based fuel in each of the other fossil fuel-fired steam electric generating units constituting part of the St. Clair Power Plant that are not then Applicable Units. For purposes of this Agreement, each such other generating unit shall become an Applicable Unit if and when [DTE and SCFC] reasonably determine and agree that the use of Refined Coal as a fuel in such generating unit will not likely result in a Reduction Event.89

The “Applicable Units” are “St. Clair Units Nos. 1, 2, 3, 4 and 6, and such other fossil

fuel-fired steam electric generating units constituting part of the St. Clair Power Plant as

agreed upon by the Parties from time to time in accordance with Section 5.1(f).”90

When SCFC sells coal to DTE, refined coal is delivered to “the point at which

Refined Coal is discharged from the feed conveyor extending from the discharge point

of the Facility onto product conveyor 3CV 113, designated as ‘Delivery Point for Refined

Coal’ on Exhibit B hereto.” The delivery point for resold coal is defined as follows:

(a) for Resold Coal that (i) [SCFC] determines is not necessary for the production of Refined Coal to be supplied to the Applicable Units, or (ii) is not necessary to satisfy [DTE’s] requirements for PRB Coal and BRB Coal-based fuel at and for the Applicable Units based upon the Buyer Annual Forecast, the point at which such coal is initially unloaded at the St. Clair Site or the Coal Yard; and (b) for all other Resold Coal, the point at which coal passes across the belt scales on produce conveyors 3CV 119 and 3CV 124, designated at “Delivery Point for Resold Coal” on Exhibit B hereto.91

89 See Exhibit A-30 (Case No. U-16434-R), page 367. 90 See Exhibit A-30 (Case No. U-16434-R), page 435. 91 See second amendment, Exhibit A-30 (Case No. U-16434-R), page 435.

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The Refined Coal Supply Agreement does not require SCFC to purchase coal

from DTE. SCFC may purchase its own coal (generally provided it meets the

specifications provided by DTE for use in its plants) as follows:

“Seller Coal” means coal purchased by [SCFC] pursuant to a Coal Purchase Contract.”

A Coal Purchase Contract is defined in this agreement in section 6.1(a):

It is contemplated that [SCFC], directly or through an Affiliate, will enter into the St. Clair Supply Agreement92 and potentially one or more contracts with third-party coal suppliers to purchase PRB Coal conforming to the Coal Specifications for use as Feedstock and for sale to [DTE], or others designed by [DTE], as provided herein (each such Contract and the St. Clair Supply Agreement, a “Coal Purchase Contract”).93

Section 5.5 provides:

Notwithstanding the means of sourcing fuel for the St. Clair Power Plant prior to the Commercial Operations Date, [DTE] covenants and agrees that it will not, and it will cause its Affiliates not to, make or give any filing, return, ruling request, representation, allegation, notice or report with any Governmental Body or court that contains, or otherwise present in accounting or financial records, reports or statements, or tax or information returns, characterizations of the transactions (or elements thereof) contemplated by the various Project Documents that are inconsistent with the terms of such Project Documents, such as (by way of example and not limitation) any characterization that Feedstock purchased by [SCFC] under applicable Coal Purchase Contracts was purchased by [DTE] or any other Person, or that Refined Coal sold to [DTE] hereunder was something other than Refined Coal.94

Section 6.1(b) contains a provision allowing DTE to enter into “Back-up Coal

Purchase Contracts” to purchase coal from the same third-party coal supplier on terms

substantially similar to the terms contained in the corresponding Coal Purchase

Contract, “except that [DTE’s] obligation to purchase a quantity of coal thereunder shall

92 This is an agreement between BRFC and SCFC that is identified as one of the “Project Documents” in the Refined Coal Purchase Agreement, but was not provided in the Exhibit A-30 and A-30 Supplemental discovery responses from Case No. U-16434-R. 93 See Exhibit A-30 (Case No. U-16434-R), page 368. 94 Id.

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be reduced by the quantity of coal purchased by [SCFC] under the corresponding Coal

Purchase Contract.” 95

In addition to DTE’s required purchases under section 5.1, quoted above, under

section 6.2 DTE may request to purchase SCFC coal not needed to produce Refined

Coal, and SCFC may require DTE to make additional purchases of coal:

(a) At any point in time, to the extent [SCFC] has Available Seller Coal, as to which [SCFC] has determined is not needed as Feedstock, [DTE] may request to purchase, and upon such request [SCFC] will sell to [DTE] or to others to the extent so directed by [DTE], all (or such portion requested by [DTE]) of such Available Seller Coal as Resold Coal at the applicable Resold Coal Price and otherwise as provided herein; provided, however, that as to any Available Seller Coal that is to be sold to others or shipped for use at a location or facility other than the St. Clair Power Plant, Seller’s obligation to sell such Available Seller Coal shall be subject to receiving [DTE’s] undertaking to replace or cause to be replaced by arranging for one or more Coal Purchase contracts for Conforming Coal, and providing for delivery in such a manner that [SCFC’s] Feedstock requirements for production of Refined Coal, and its Refined Coal production schedule, and its requirements for Conforming Coal to be sold hereunder as Resold Coal, in each case, will not be impaired. (b) At any point in time, to the extent that [SCFC] has Available Seller Coal, [SCFC] may request that [DTE] purchase all or a portion of such Available Seller Coal, and upon such request [DTE] will purchase and [SCFC] will sell to [DTE], or to others to the extent so directed by [DTE], such Available Seller Coal (or applicable portion thereof) as Resold Coal at the applicable Resold Coal Price and otherwise as provided herein, it being agreed, for the avoidance of doubt, that [SCFC’s] exercise of such right shall not cause to arise an obligation by [DTE] to replace Conforming Coal under Section 6.2(a).96

At contract termination, section 6.3 of the agreement provides for the sale of

SCFC’s coal whether already received or under contract:

At the end of the Term, [DTE] shall purchase, and [SCFC] shall sell to [DTE], all Conforming Coal on hand or under contract as Resold Coal. To the extent that there is any Coal Purchase Contract in place at the end of the Term which, by its terms, obligates [SCFC] to purchase Conforming

95 Mr. Sansoucy characterized this provision as highly unusual. See 2 Tr 392. 96 See Exhibit A-30 (Case No. U-16434-R), page 369.

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Coal for a period extending beyond the end of the Term, each Party agrees that [SCFC] will assign such Coal Purchase Contract to [DTE] and [DTE] will assume [SCFC’s] rights and obligations thereunder. To the extent any such Coal Purchase Contract is not able to be so assigned, following the end of the Term, [SCFC] shall sell and [DTE] shall purchase Conforming Coal as Resold Coal in accordance with the terms and conditions hereof until the applicable coal Purchase Contract expires or otherwise terminates.97

Article IX governs pricing of transactions under the agreement. The purchase

prices DTE must pay for coal as “Refined Coal” or “Resold Coal” from DTE’s Coal Yard

are based on the fuel company’s inventory price. For Refined Coal, DTE pays the

“Refined Coal Price” under section 9.1, defined as “the per Ton amount equal to the

sum of (i) the Coal Inventory Price multiplied by a fraction, the numerator of which is the

amount of Feedstock (by weight in Tons and as agreed to by the Parties) used to

produce one Ton of Refined Coal at the Facility, and the denominator of which is one

Ton, plus (ii) the Refined Coal Adder.” The Coal Inventory Price, or base price, is

defined as follows:

Coal Inventory Price means, for any given period, the per Ton amount derived by dividing (i) the sum of (A) the book value of the Seller Coal inventory at the beginning of the period, plus (B) the total quality adjusted cost of all Seller Coal purchased during such period (reflecting all quality and other allowances, adjustments and assessments under the applicable Coal Purchase Contract, all related Third Party Impositions that are imposed on Seller in this Agreement and transportation costs, and all other charges and costs relating to such period and charged to Seller Coal inventory in accordance with Seller’s customary inventory accounting procedures consistently applied), by (ii) the sum of (A) the volume in Tons of Seller Coal inventory on hand at the beginning of the period, plus (B) the volume in Tons of Seller Coal inventory purchased during such period.98

97 Id. 98 See Exhibit A-30 (Case No. U-16434-R), page 357 (emphasis added).

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“Third Party Impositions” are defined in section 9.8 as “all assessments, fees, costs,

expenses and taxes imposed by any Governmental Body or other third parties . . .

relating to Seller Coal that arise prior to any transfer of title . . . as Resold Coal or . . .

Refined Coal.” The Refined Coal Adder is defined in the agreement as the amount

calculated as set forth in Exhibit C to the agreement. This Exhibit contains the formulas

and definitions for determining the “Environmental Benefit” and other elements,

discussed in more detail below.

Under section 9.2, for “Resold Coal” DTE purchases from the “Feedstock

Inventory Store” (Coal Yard), DTE pays “the Coal Inventory Price applicable to such

Ton of Resold Coal”, while for “Resold Coal” purchased at “a site other than the St. Clair

site”, DTE pays the contract price applicable to that shipment, plus any applicable

transportation charges and transloading costs.

The agreement also has numerous provisions governing breach of the

agreement. Notably, Section 6.1(c) provides:

Notwithstanding anything to the contrary herein but subject to the provisions of Sections 5.1(e), 8.2(c) and 9.4, [DTE’s] sole remedy for [SCFC’s] failure to produce and sell Refined Coal hereunder shall be to: (i) purchase Resold Coal pursuant to Section 5.1 and to purchase coal under the Back-Up Coal Purchase contracts; and (ii) terminate this Agreement in accordance with Section 11.1(f).99

The 10-year term of the agreement is contained in section 3.1, which also provides for a

five-year extension. Article XI provides for early termination.

99 See Exhibit A-30 (Case No. U-16434-R), page 369.

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c. Coal Handling and Consulting Agreement

The Coal Handling and Consulting Agreement, also entered on December 18,

2009 and subsequently amended,100 recites that: “[SCFC] desires to retain Coal

Consultant to perform the Services, in order to transport and handle an adequate supply

of coal and to ensure that the [SCFC] uses coal that conforms to the coal specifications,

so as to allow [SCFC] to satisfy its obligations under the Refined Coal Supply

Agreement.” Under this agreement, Coal Purchase Contracts are defined as “[T]he St.

Clair Supply Agreement and any other Contract as may be entered into by the

Company from time to time for the purchase of PRB Coal necessary to fulfill its

obligations under the Refined Coal Supply Agreement. “

DTE is appointed Coal Consultant “to act as an independent contractor to

provide the Services to [SCFC].” Section 5.1 further provides: “Coal Consultant will

represent the Company as its exclusive coal consultant for the Services during the Term

of this Agreement.” The “Services” to be provided are set forth in Article VI of the

agreement, and include assisting SCFC to meet the requirements of the Refined Coal

Supply Agreement, consultation on coal performance, inventory levels, shipment

schedules and coal purchasing and transportation strategies under section 6.2, and coal

inventory management, preparation and handling services with respect to coal at the

plant site under section 6.3. Section 6.2 (d) addresses DTE’s coal procurement

obligations:

To the extent the Annual Forecast is increased during the Contract Year, Coal Consultant will procure and submit like proposed Coal Purchase Contracts sufficient to satisfy such increase; and, further, to the extent that the Coal Specifications are changed such that one or more of the Coal Purchase Contracts then in place will not satisfy such Coal Specifications,

100 The two amendments are dated March 1, 2010 and January 7, 2011.

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Coal Consultant will procure and submit like proposed Coal Purchase Contracts necessary to satisfy the Annual Forecast and meeting such new Coal Specifications. Except for the St. Clair Supply Agreement or as expressly approved by the [SCFC], the Coal Purchase Contracts procured by Coal Consultant pursuant hereto shall not have as a counterparty Coal Consultant or any Affiliate of Coal Consultant, and Coal Consultant will not intentionally arrange, directly or indirectly, for the purchase by [SCFC] of coal that is then presently or was previously owned by Coal Consultant or an Affiliate of Coal Consultant. Notwithstanding the foregoing, Coal Purchase Contracts procured for the Company pursuant hereto may be in the form of a Contract or Contracts to which Coal Consultant or an Affiliate is or was a party which is to be assigned to [SCFC] by Coal Consultant or such Affiliate.101

The Coal Handling and Consulting Agreement does not require DTE to procure coal

contracts other than as set forth in this section. Section 6.2 (i) provides that “[u]nless

otherwise agreed to by the Parties, each Coal Purchase Contract shall specify that the

coal . . . shall be purchased at the applicable mine.”102

The Coal Consultant is also required to arrange for transportation for all coal

purchased by SCFC under section 6.2(e), and assist in administering the contracts

under section 6.2(f) and (h). To assist the Coal Consultant in performing its obligations,

SCFC is required under section 6.2(g) to provide DTE with a list of all SCFC’s contracts

for the purchase of coal. Under section 6.3, DTE’s obligations include inventory

management, preparation and handling services to provide sufficient feedstock coal to

operate the REF facility.

Section 7.1 provides for SCFC to pay DTE a “Coal Fee” for services provided

under the agreement, and section 7.2 provides for SCFC to make additional payments

for “such additional fees in amounts and at such times as may be agreed upon by

[SCFC] and Coal Consultant, if any”, for transportation services provided under the

101 See Exhibit A-30 (Case No. U-16434-R), page 565. 102 See Exhibit A-30 (Case No. U-16434-R), page 566.

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agreement, and for “Increased Frequency Services” including “costs and expenses,

including overhead, incurred by Coal Consultant for additional material handling and

inventory management in the Coal Yard” as provided for in section 6.3(a) and (b).

Exhibit AG-2 indicates that the Coal Fee for SCFC is $9.5 million.

A miscellaneous “Agreement” is included in Exhibit A-30 (Case No. U-16434-R)

between DTE and DTE Energy Services, Inc. (DTEES) as “managing member” of

SCFC, which references the Coal Handling and Consulting Agreement. It provides in

key part:

Whereas, DTEES has agreed to make payments to [DTE] in addition to the amounts paid . . . by SCFC under the Coal Handling Agreement to reimburse [DTE] for certain cost incurred by [DTE] in connection [sic] providing the coal handling services . . . [Therefore,] In addition to the amounts paid to [DTE] by SCFC under the Coal Handling Agreement, commencing in January 2011 and continuing for the term of this Agreement, DTEES shall pay to [DTE] [REDACTED]103 per month to reimburse [DTE] for the incremental cost incurred in connection with supplying 1,800,000 tons of coal per calendar year to the Facility.104

d. Other agreements

Other agreements between DTE and SCFC include the License and Services

Agreement and the Environmental Indemnity Agreement. The Licenses and Services

Agreement, dated September 22, 2009, provides that for a $60,000 annual fee, DTE

agrees to provide site licenses and access to certain services on DTE’s property. The

licenses granted under the agreement include, under the label of an Operating License

in section 2.1, a Facility License, an Access License, a Utilities and Services License, a

Material Storage and Handling License, and a Refined Coal Storage and Handling

103 Mr. Lapplander identified the redacted amount as a $10,000 per month payment to cover incremental coal handling costs identified by plant personnel. See Exhibit A-35, page 99. 104 See Exhibit A-30 (Case No. U-16434-R), page 595.

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License, and under section 2.2, a Construction License. This agreement also provides

that DTE may purchase the facilities at the termination of the agreement, at a price

mutually agreed on, or SCFC will remove the facilities. The agreement provides for the

payment of certain taxes and utilities by SCFC. Section 13.1 requires that each party

maintain insurance as provided in Schedule 13.1, including Worker’s Compensation

Insurance as required by law, General Liability insurances with combined limits of no

less than $10 million per occurrence, and Automobile Liability insurance with a $1

million minimum limit per occurrence.

The Licenses and Services Agreement also contains an indemnification

provision, under which each party agrees to indemnify the other for Claims arising from

their acts or omissions, except for claims relating to Environmental Laws or Hazardous

Materials, which are governed by the Environmental Indemnity Agreement.

The Environmental Indemnity Agreement provides indemnifications for claims

relating to the alleged violation of environmental laws.105 DTE as “Host” provides

indemnifications to SCFC under section 4.1 for all claims arising out of an alleged

violation of any Environmental Law (as defined in the agreement) or the presence or

release of Hazardous Materials (as defined in the agreement), except for claims

attributable to SCFC’s acts or omissions. SCFC provides indemnifications to DTE

under section 4.2 for all claims arising out of an alleged violation of Environmental Law,

to the extent attributable to SCFC’s acts or omissions. The agreement also provides

notification and dispute resolution procedures. No requirements for insurance, bond, or

other financial assurances are included.

105 This agreement is contained in Exhibit A-0 Supplemental (Case No. U-16434-R). It was amended twice.

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2. Belle River

As quoted above, DTE identifies the same project documents for Belle River as

for St. Clair. The agreements themselves also include as project documents the MPPA

Coal Inventory Purchase Agreement (“to be entered into on or about the Commercial

Operations Date” between BRFC and MPPA), the Memorandum of Understanding with

respect to the Participation Agreement (also “to be entered into on or about the

Commercial Operations Date” between MPPA and DTE), the St. Clair Supply

Agreement noted in subsection 1 above, and “the other documents, agreements,

certificates and instruments executed or entered into by and between (i) BR Fuels and

MPPA and Detroit Edison, (ii) BR Fuels and Detroit Edison, and (iii) BR Fuels and

MPPA in connection with the transactions contemplated thereby”.106 These documents

are not included in Exhibit A-30 or A-30 (Supplemental) from Case No. U-16434-R. For

those documents identified by DTE in Exhibit A-21, however, a review of those

agreements shows that they are substantially the same as the agreements between

DTE and SCFC, with some differences reflecting MPPA’s ownership interest.

a. Inventory purchase agreements

The Acceptance Period Coal Inventory Purchase Agreement dated December 4,

2009, provides for the purchase of “Coal Inventory” defined as “[T]he 1,000,000 net tons

of coal owned by [DTE]107 that is stored in the Coal Yard.” The purchase was to take

place on the “Coal Inventory Closing Date”, which was left open-ended under the

106 See Exhibit A-30 (Case No. U-16434-R) page 11. 107 DTE is “Seller” under this agreement.

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agreement,108 but DTE witnesses have testified that this transaction took place in

December of 2009. The price for this coal is stated in section 2.3 of the agreement to

be DTE’s “book value on November 30, 2009.” Subsequent letter agreements provided

for the purchase of additional “Installments” of “Coal Inventory” as provided in those

letter agreements. The purchase prices under these subsequent letter agreements

were DTE’s “book value” as of either a date certain or the last day of the calendar

month preceding the month in which the Installment purchase occurred. The total

quantity of coal transferred under these supplemental letters, from both the Coal Yard

and from MERC, is approximately 8.5 million tons.

The Inventory Purchase Agreement, although extended once by amendment,

appears to have expired. The December 4, 2009 Coal Inventory Purchase Agreement

provided in section 2.1(b): “In the event that the Coal Inventory Closing Date has not

occurred on or before December 31, 2010, this Agreement shall be null and void and

the Parties shall have no further obligations or liabilities to each other hereunder.”109

The December 1, 2010 amendment extended that date to December 31, 2011. Instead,

as Mr. Krishnamurthy testified, the Acceptance Period Coal Inventory Purchase

Agreement has been relied on while testing is ongoing.110

108 Section 2.6 provides: “The purchase and sale of the Coal Inventory pursuant to Section 2.1 shall occur on the date chosen by Purchaser (the “Coal Inventory Closing Date”)’ provided, that such date is reasonably acceptable to Seller.” 109 See Exhibit A-30 (Case No. U-16434-R), page 94. 110 See 3 Tr 623.

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b. Refined Coal Supply Agreement

The Refined Coal Supply Agreement dated December 4, 2009, was amended

March 1, 2010, with a subsequent letter agreement dated February 15, 2011.111 Like the

St. Clair Coal Supply Agreement discussed above, the Refined Coal Supply Agreement

between BRFC and DTE contemplated that DTE would purchase all its requirements for

coal at the Belle River plant from BRFC, including Refined Coal and unrefined coal.112

A February 15, 2011 letter agreement temporarily suspends this requirement:

The Parties agree that notwithstanding anything to the contrary in the [Refined Coal Supply] Agreement, that any time prior to BR Fuels purchase of the Coal Inventory pursuant to the Coal Inventory Purchase Agreement that BR Fuels is not producing Refined Coal from the Facility that BR Fuels shall not be required to provide Detroit Edison Resold Coal and Detroit Edison shall be permitted to procure coal from sources other than BR Fuels to fuel the Belle River Power Plant. Either Party may terminate this letter agreement upon written notice to the other Party. Except as expressly set forth in this letter agreement, the terms of the [Refined Coal Supply] Agreement shall remain in full force and effect without modification.113

According to the Refined Coal Supply Agreement, BRFC can also purchase its

own coal (generally provided it meets the specifications provided by DTE for use in its

plants) as follows:

“Seller Coal” means coal purchased by [BRFC] pursuant to a Coal Purchase Contract.”114

A Coal Purchase Contract is defined in this agreement in section 6.1(a): 111 The Refined Coal Supply Agreement contemplates that DTE will purchase all of its coal requirements for the Belle River plant from BFC, as set forth in section 5.1 of the agreement, but the February 15, 2011 letter agreement allows DTE to purchase coal from other suppliers prior to BFC’s purchase under the Coal Inventory Purchase Agreement and while BFC is not producing Refined Coal. This agreement may be terminated by either party on written notice to the other. 112 See section 5.1, Exhibit A-30 (Case No. U-16434-R), page 15. 113 See Exhibit A-30 (Case No. U-16434-R), page 83. 114 See Exhibit A-30 (Case No. U-16434-R), page 12.

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It is contemplated that [BRFC], directly or through an Affiliate, will enter into one or more contracts with third-party coal suppliers to purchase coal conforming to the Coal Specifications for use as Feedstock and for sale as Resold Coal to [DTE], or others designed by [DTE], as provided herein (each, a “Coal Purchase Contract.”)115

Section 6.1(b) provides:

It is further contemplated that included among the Coal Purchase Contracts will be purchase contracts that [DTE] has in place with coal suppliers on the Commercial Operations Date and that are to be assigned in whole or in part to Seller pursuant to the Coal Inventory Purchase Agreement.116

And section 5.5 has the same prohibition as the St. Clair Refined Coal Supply

Agreement, precluding DTE from “any characterization that Feedstock purchased by

[BRFC] under applicable Coal Purchase Contracts was purchased by [DTE] or any

other person.”117

Section 6.1(c) contains a provision allowing DTE to enter into “Back-up Coal

Purchase Contracts” to purchase coal from the same third-party coal supplier on terms

substantially similar to the terms contained in the corresponding Coal Purchase

Contract, “except that [DTE’s] obligation to purchase a quantity of coal thereunder shall

be reduced by the quantity of coal purchased by [BRFC] under the corresponding Coal

Purchase Contract.”

As with the St. Clair agreement, the purchase prices DTE must pay for coal as

“Refined Coal” or “Resold Coal” from DTE’s Coal Yard are based on the fuel company’s

inventory price, but the Refined Coal Adder is modified to account for MPPA’s

ownership in the plant. For Refined Coal, DTE pays the “Refined Coal Price” defined as

“the per Ton amount equal to the sum of (i) the Coal Inventory Price, plus (ii) the Detroit

115 See Exhibit A-30 (Case No. U-16434-R), pages 17 and 75. 116 See Exhibit A-30 (Case No. U-16434-R), pages 17-18. 117 See Exhibit A-30 (Case No. U-16434-R), page 17.

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Edison Refined Coal Adder, plus (iii) the MPPA Refined Coal Adder.” The Coal

Inventory Price, or base price, has the same definition as for SCFC:

Coal Inventory Price means, for any given period, the per Ton amount derived by dividing (i) the sum of (A) the book value of the Seller Coal inventory at the beginning of the period (less the “Inventory Coal Purchase Price,” as defined in the MPPA Coal Inventory Purchase Agreement), plus (B) the total quality adjusted cost of all Seller Coal purchased during such period (reflecting all quality and other allowances, adjustments and assessments under the applicable Coal Purchase Contract, all related Third Party Impositions that are imposed on [BRFC] in this Agreement and transportation costs, and all other charges and costs relating to such period and charged to Seller Coal inventory in accordance with [BRFC’s] customary inventory accounting procedures consistently applied), by (ii) the sum of (A) the volume in Tons of Seller Coal inventory on hand at the beginning of the period, plus (B) the volume in Tons of Seller Coal inventory purchased during such period.118

The Refined Coal Adder is presented in Exhibit C to the agreement, and is discussed in

more detail below.

Under section 9.2, for “Resold Coal” DTE purchases from the “Feedstock

Inventory Store” (Coal Yard), DTE pays “the Coal Inventory Price applicable to such

Ton of Resold Coal”. Only if DTE purchases “Resold Coal” from BRFC at a site other

than the Belle River Site does DTE pay the contract price under the applicable Coal

Purchase Contract. The delivery points for Resold Coal are defined as follows:

(a) for Resold Coal that is in transit or that has been identified for delivery under a Coal Purchase contract but is not yet in transit, the Point of Origin; and (b) for all other Resold Coal, the point at transfer gate no. 03zm053 on feed conveyor CV 23 and at transfer gate no. 03zm054 on feed conveyor CV 24, designated as “Delivery Point for Resold Coal” on Exhibit B hereto.119

Also, at termination, DTE is obligated under section 6.3 to purchase all refined

coal and also all “Conforming Coal” on hand or under contract, with the additional

118 See Exhibit A-30 (Case No. U-16434-R), page 6. 119 See Exhibit A-30 (Case No. U-16434-R), page 7.

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proviso that DTE will assume BRFC’s rights under contracts extending beyond the term

of the agreement “to the extent not assigned to St. Clair Fuels under the St. Clair Supply

Agreement.”

c. Coal Handling and Consulting Agreement

The Coal Handling and Consulting Agreement dated December 4, 2009,

designated DTE as its “exclusive” coal consultant, as an independent contractor. This

agreement expressly provides that “Coal Consultant and its Authorized Representative

shall have no authority and shall not represent that they have the authority to execute

documents on behalf of [BRFC] or otherwise to assume or incur any obligation in the

name of [BRFC].”120 This agreement further references the St. Clair Supply Agreement

between BRFC and SCFC in outlining DTE’s responsibilities in section 6.1:

For and in consideration of the Coal Fee, each Contract Year, Coal Consultant shall (a) provide to [BRFC] information regarding sources of coal and transportation thereof that will enable [BRFC] to obtain coal meeting the Coal Specifications for use as Feedstock in the Facility and for sale as Resold Coal, in each case as necessary to allow [BRFC] to meet its obligations under the Refined Coal Supply Agreement, and for the sale of coal to St. Clair Fuels as necessary to allow [BRFC] to meet its obligations under the St. Clair Supply Agreement and (b) assist [BRFC] in meeting its obligations under the Refined Coal Supply Agreement and under the St. Clair Supply Agreement by providing certain certifications as described below.121

DTE’s obligations under the Coal Handling and Consulting Agreement are similar but

not identical to its obligations under the consulting agreement with St. Clair discussed

above. DTE’s coal procurement responsibilities are identified in section 6.2(e) as

follows:

120 See section 4.1, Exhibit A-30 (Case No. U-16434-R), page 205. 121 See Exhibit A-30 (Case No. U-16434-R), page 206.

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Coal Consultant shall procure and obtain for [BRFC’s] review and consideration proposed Coal Purchase Contracts for coal meeting the Coal Specifications and in connection with which Coal Consultant has made the certification provided for in Section 6.3 for an aggregate amount of coal sufficient to meet the Annual Forecast. To the extent that the Annual Forecast is increased during the Contract Year, Coal Consultant will procure and submit like proposed Coal Purchase contracts sufficient to satisfy such increase; and, further, to the extent that the Coal Specifications are changed such that one or more of the Coal Purchase Contracts then in place will not satisfy such Coal Specifications, Coal Consultant will procure and submit like proposed Coal Purchase Contracts necessary to satisfy the Annual Forecast and meting such new coal specifications. Except as expressly approved by [BRFC], the Coal Purchase Contracts procured by Coal Consultant pursuant hereto shall not have as a counterparty Coal Consultant or any Affiliate of Coal Consultant, and Coal Consultant will not intentionally arrange, directly or indirectly, for the purchase by [BRFC] of coal that is then presently or was previously owned by Coal Consultant or an Affiliate of Coal Consultant. Notwithstanding the foregoing, Coal Purchase contracts procured for [BRFC] pursuant hereto may be in the form of a Contract or Contracts to which Coal Consultant or an Affiliate is or was a party which is to be assigned to [BRFC] by Coal Consultant or such Affiliate.122

Under section 6.3:

As to coal to be used to satisfy [BRFC’s] obligations under the Refined Coal Supply Agreement and [BRFC’s] obligations under the St. Clair Supply agreement, Coal Consultant shall provide [BRFC] with Coal Purchase Contracts that meet the following standards: (i) the use of such coal is consistent with the Coal Specifications and [BRFC’s] obligations under the Refined Coal Supply Agreement and [BRFC’s] obligations under the St. Clair Supply Agreement . . . so long as [BRFC] executes any Coal Purchase Contract provided by Coal Consultant under this Section 6.3 without modification, or utilizes a coal transportation agreement to which Coal Consultant or its Affiliate is a party, Coal Consultant’s Authorized Representative shall certify in writing at the time of execution of such contract that such contracts satisfy the requirements of this Section 6.3.123

As with the St. Clair agreement, the Coal Fee is redacted in Exhibit A-30, but it is

contained in section 7.1, but Exhibit AG-2 establishes that Coal Fee for BRFC is $5.2

million. Section 7.2 provides for BRFC to reimburse DTE for “such additional fees in 122 See Exhibit A-30 (Case No. U-16434-R), page 207. 123 See Exhibit A-30 (Case No. U016434-R), page 208.

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amounts and at such times as may be agreed upon”, and also reimburse DTE for

transportation costs, and “costs and expenses, including overhead, incurred by Coal

Consultant for additional material handling and inventory management in the Coal Yard

resulting from Increased Frequency Services.”

d. Other agreements

The other agreements in Exhibit A-30 and A-30 Supplemental include the

Licenses and Services Agreement, which provides BRFC site licenses and access to

certain services on DTE’s property as described for SCFC above, and the

Environmental Indemnity Agreement, which contains essentially the same terms as for

SCFC as discussed above.

3. Monroe

As Mr. Krishnamurthy testified, the Monroe agreements have a somewhat

different structure. The project documents include the Pre-Closing Inventory Purchase

Agreement and Coal Feedstock Purchase Agreement in lieu of the Acceptance Period

Coal Inventory Purchase Agreement and Coal Inventory Purchase Agreement

discussed above, as well as the Refined Coal Supply Agreement, the Coal Consulting

and Handling Agreement, the Licensing Agreement and the Environmental

Indemnification Agreement. The key structural differences are that there is no “Refined

Coal Adder” or any other charge for REF coal above the “Resold Coal” price, and that

the Coal Handling and Consulting Agreement includes a “Coal Fee Rate” or discount

given by MFC to DTE, which is not subsequently reimbursed by DTE.

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a. Inventory purchase agreements

The Pre-Closing Coal Inventory Purchase Agreement and Coal Feedstock

Purchase Agreement are dated August 21, 2011. The Pre-closing Coal Inventory

Purchase Agreement provides for MFC to purchase 75,000 net tons of eastern coal and

175,000 tons of Power River Basin coal owned by DTE and stored in the Monroe Coal

Yard. The purchase price under section 2.3 of the agreement is DTE’s book value “as

of the close of business on the last day of the calendar month immediately preceding

the Coal Inventory Closing Date”, which is to be mutually agreed upon under section

2.6.

The Coal Feedstock Purchase Agreement was originally written to provide that

MFC would purchase from DTE all coal required to meet its obligations under the

Refined Coal Supply Agreement, discussed below.124 Section 6.1 of the agreement

was amended effective November 16, 2011, to provide:

During each Contract Year, in accordance with the terms of this Agreement, [DTE] will sell to [MFC], and [MFC] will purchase from [DTE], that quantity of Conforming Coal as reasonably requested by [MFC] from time to time to facilitate the operation of the Facility and the production of Refined Coal by [MFC]. The Parties hereby acknowledge and agree that (i) [MFC] does not have any minimum purchase requirement hereunder, and (ii) the quantity of Conforming Coal to be sold to [MFC] hereunder will not exceed Detroit Edison’s demand for use of Refined Coal at the Monroe Power Plant.125

b. Refined Coal Supply Agreement

The Refined Coal Supply Agreement, dated August 21, 2011, was amended

effective November 16, 2011. Similar to the other fuel company agreements, DTE

agrees to purchase from MFC all of its requirements for refined coal for the Monroe 124 See Exhibit A-30 (Case No. U-16434-R), page 791. 125 See Exhibit A-30 (Case No. U-16434-R), page 804.

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plant, to purchase “Resold Coal” from MFC to the extent it needs additional coal, and to

“use commercially reasonable efforts consistent with Prudent Operating and

Maintenance Standards to maximize the amount of such Refined Coal used at

[Monroe]”.126

Also, while section 6.1(a) provides that DTE may request to purchase for itself or

others “Available Seller Coal” from MFC, subject to replacing it with Conforming Coal as

needed for Feedstock, section 6.1(b) limits DTE’s ongoing obligation, at MFC’s request,

to purchase Available Seller Coal as Resold Coal, so that DTE is only obligated to

purchase amounts in the Coal Yard “in excess of 250,000 tons”. As in the other

agreements, DTE retains the obligation to purchase all refined coal and all other coal

owned by MFC at the termination of the agreement.127 Similar to the other

agreements, “Available Seller Coal” means “Conforming Coal that is in the Feedstock

Inventory Store or in transit (or has been identified for delivery under the Coal

Feedstock Purchase Agreement but is not yet in transit”; “Conforming Coal” means

Seller Coal that meets the Coal Specifications in effect at the time purchased by Seller,

and shall include, without limitation, Seller Coal presumed to be conforming Coal

pursuant to Section 8.5 hereof”; and “Seller Coal” means “coal purchased by [MFC],

including, without limitation, coal purchased pursuant to the Coal Feedstock Purchase

Agreement or the Pre-closing Coal Inventory Purchase Agreement.”128

126 Note that a portion of the language addressing limits on DTE’s obligation to purchase Refined Coal is redacted in Exhibit A-30 (Case No. U-16434-R), page 609. 127 See sections 5.5 and 6.2, Exhibit A-30 (Case No. U-16434-R), pages 611 and 612. 128 See Exhibit A-30 (Case No. U-16434-R), pages 601 and 602, and pages 642 and 643.

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Aside from a reduction to reflect that it takes less than one ton of unrefined coal

to produce a ton of refined coal, the price charged for refined coal under the agreement

is the same as the price charged for unrefined “Resold Coal” purchased at Monroe:

[DTE] shall pay (or cause to be paid) to Seller for each Ton of Resold Coal purchased and sold hereunder the Resold Coal Price. The “Resold Coal Price” for Resold Coal purchased at a site other than the Monroe Site shall be the same quality adjusted price per Ton incurred or to be incurred directly by MFC under the Coal Feedstock Purchase Agreement, plus any applicable transportation charges or other rail, vessel and transloading costs incurred by [MFC]. The “Resold Coal Price” for Resold Coal sold from the Feedstock Inventory Store shall be the Coal Inventory Price applicable to such Ton of Resold Coal.129

The Inventory Price is defined slightly differently under this agreement than in the

agreements with BRFC and SCFC, making clear that the “Coal Fee Rate” paid to DTE

under the Coal Handling and Consulting Agreement cannot be recovered through the

inventory price, 130 and making clear that all coal contracts entered into by MFC are

included in the inventory price:

“Coal Inventory Price” means, for any given period, the per Ton amount derived by dividing (i) the sum of (A) the book value of the Seller Coal inventory at beginning of the period, plus (B) the total quality adjusted cost of all Seller Coal purchased during such period (reflecting all quality and other allowances, adjustments and assessments under the Coal Feedstock Purchase Agreement, all related Third Party Impositions that are imposed on [MFC] in this Agreement and transportation costs, and all other charges and costs relating to such period and charged to Seller Coal Inventory in accordance with [MFC’s] customer inventory accounting procedures consistently applied), by (ii) the sum of (A) the volume in Tons of Seller Coal inventory on hand at the beginning of the period, plus (B) the volume in Tons of Seller Coal inventory purchased during such period.131

129 See Exhibit A-30 (Case No. U-16434-R), page 618. 130 Amendments dated November 16, 2011 to the Refined Coal Purchase Agreement delete DTE’s obligation to reimburse MFC for the “Coal Fee” under original section 9.3 of this agreement. 131 See Exhibit A-30 (Case No. U-16434-R), page 601.

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For the avoidance of doubt, the Coal Fee paid by Monroe Fuels Company to Detroit Edison pursuant to the Coal Handling and Consulting agreement shall not be included in the Coal Inventory Price.132 [P]rovided, however, if Seller Coal includes coal not purchased under the Coal Feedstock Purchase Agreement, then for purposes of determining the Coal Inventory Price, the book value of such coal shall be calculated as if such coal had been purchased under the Coal Feedstock Purchase Agreement.133

Under section 9.4, MFC has potential obligations to compensate DTE for any

capital costs attributable to DTE’s use of Refined Coal, providing the parties agree, and

for additional costs associated with gypsum and fly ash contracts attributable to the use

of Refined Coal, under certain circumstances. 134

c. Coal Handling and Consulting Agreement

Similar to the other consulting agreements, the Coal Handling and Consulting

Agreement between DTE and MFC requires DTE as Coal Consultant to provide a broad

range of services, set forth in Article VI of the agreement. The agreement makes clear;

however, that DTE does not have authority to execute agreements on behalf of MFC.

The “Coal Fee Rate” compensation to DTE is the result of an amendment to the

initial agreement. In the contracts with MFC as originally entered, a “Fuel Discount” was

included in the August 21, 2011 Refined Coal Supply Agreement between DTE and

MFC. This fuel discount was stated as an amount related to the volume of refined coal

purchased by DTE. The Coal Handling and Consulting Agreement dated August 21,

2011, contained a “Coal Fee” in section 7.1, which MFC was to pay to DTE for each ton

of coal delivered by DTE in its capacity as coal consultant. Subsequently, by

132 See Exhibit A-30 (Case No. U-16434-R), page 642. 133 Id. 134 See Exhibit A-30 Supplemental (Case No. U-16434-R), pages 618 and 619.

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amendments dated November 16, 2011, the “Fuel Discount” was removed from the

Refined Coal Supply Agreement, and the “Coal Fee” in section 7.1 of the Coal Handling

and Consulting Agreement was replaced with a “Coal Fee Rate”, which now varies by

the amount of refined coal purchased by DTE.135 Although the figures are redacted in

Exhibit A-30 (Case No. U-16434-R), DTE witnesses have testified that the Coal Fee

Rate is $1.03 for the first 7 million tons of refined coal purchased by DTE, and $1.50 for

each additional ton after that.

The only other payments made to DTE under the Coal Handling and Consulting

Agreement are stated in section 7.2, which provides for reimbursement of “direct costs

and expenses incurred by Coal Consulting in providing coal transportation services

under this Agreement.”

d. Other agreements

The License and Services Agreement appears to grant essentially the same

licenses and access in exchange for the same annual fee as the agreements with

BRFC and SCFC. The indemnification, dispute resolution procedures, and insurance

requirements also appear to be the same. Likewise, the Environmental Indemnity

Agreement dated June 13, 2011, appears to be essentially the same as the parallel

agreements with the other fuel companies.

D. Environmental Benefits

DTE contends that REF reduces the cost of compliance with SO2 and NOx

emission regulations, and will reduce the cost of compliance with mercury emission

135 Witnesses for DTE testified that when 99% of the ownership of MFC was sold to outside investors, those investors wanted certain changes in the agreements.

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limits beginning in 2015. Mr. Rogers explained how burning REF fuel reduces

environmental compliance costs at Belle River and St. Clair. As discussed above, the

company has determined that ACI and DSI systems are economically feasible and

reasonable technologies for meeting emission standards at Belle River and St. Clair.

Mr. Rogers testified specifically regarding REF: “[T]he Company has also determined

that using REF improves the performance of both FGD and ACI in meeting the required

mercury reductions in the most cost effective manner.”136

MEC/NRDC and MCAAA argue that the environmental benefits are overstated,

emphasizing that the company has acknowledged that the refined coal is not necessary

to meet environmental standards currently or in 2015 because alternative technologies

are available, that the agreements and tax-benefits terminate in 10 years, leaving only a

six-year period to obtain the benefits after the more stringent regulations take effect in

2015.

1. Mercury

Because the Belle River and St. Clair plants will use an ACI system while the

Monroe plant will use a wet FGD system for controlling mercury emissions, it is

appropriate to review the mercury emission compliance cost savings attributable to the

REF project separately for these systems.

a. Belle River and St. Clair

Mr. Rogers explained:

Mercury is found naturally in coal and is vaporized during the combustion process. This vapor-phase mercury in the flue gas can take the form of either elemental mercury or oxidized mercury. Since oxidized mercury

136 See 2 Tr 123.

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can be effectively removed, while elemental mercury is very difficult to remove, the form that vapor phase mercury takes is significant.137

For the ACI systems, he further explained:

ACI is an engineered system where powdered activated carbon (PAC) is injected into the flue gas ductwork of the power plant. PAC absorbs the vaporized mercury from the flue gas before being removed along with the fly ash by the particulate control equipment. Oxidized vapor phase mercury can be effectively removed by standard PACs, while elemental vapor phase mercury requires larger quantities of more expensive chemically treated PACs.138

Mr. Rogers then explained the savings obtained from using REF with the ACI systems

at Belle River and St. Clair:

Because those plants burn predominantly subbituminous coal, those ACI systems require a more expensive chemically treated powered activated carbon (BrPAC) to achieve the required mercury removal. The required injection rates for ACI have been projected based on several ACI tests conducted at St. Clair Power Plant Units 1 and 3. Detroit Edison has conducted additional tests on those units in 2010 and 2011 demonstrating that while consuming REF, compliance-level mercury removal can be achieved using the lower cost standard PAC instead of the chemically treated BRPAC, and at much lower injection rates. This is to be expected since one of the components of REF is an effective agent for oxidizing vapor phase mercury.139

Acknowledging that exact savings cannot be determined until permanent ACI

systems are installed, Mr. Rogers presented savings estimates of $5.6 to $5.9 million

from the use of REF at Belle River and St. Clair beginning in 2015 in Exhibit A-2.

MEC/NRDC argues that these estimates are unreliable based on Mr. Rogers’

acknowledgement that the company cannot generate a reliable estimate until it

determines the optimal amounts of REF and ACI additives.140

137 See 2 Tr 124. 138 See 2 Tr 125. 139 See 2 Tr 127. 140 See MEC/NRDC brief, pages 57-58, also citing 2 Tr 139.

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DTE argues in response that MEC/NRDC relies only on DTE’s testimony, and

“speculates about how the Commission could ignore and misconstrue that evidence (as

well as Edison’s additional evidence) to somehow reach a different conclusion that

would violate the fundamental requirement that [a] final order of the PSC must ‘be

supported by ‘competent, material and substantial evidence on the whole record.’”141

b. Monroe

DTE witnesses also argued to some extent that savings related to mercury

emission control would also be obtained at the Monroe plant, which uses Wet Flue Gas

Desulphurization (FGD), very effective at reducing mercury. Mr. Rogers testified that

because one of the additives in REF is an effective agent for oxidizing vapor phase

mercury, using REF causes the vapor phase mercury entering the FGD to be highly

oxidized, promoting very effective mercury removal with the Wet FGD. Mr. Rogers thus

testified:

If REF were not used at Monroe Power Plant, then a separate system would be required to inject this additive onto the coal or into the flue gas to promote compliance-level mercury removal by the Wet FGD to consistently meet the MATS mercury standards. REF removes the need for additional costly additives necessary to achieve full compliance with the MATS mercury standard.142

MEC/NRDC argues that there is no evidence to establish that Monroe requires

either the use of REF or an alternate chemical injection system to comply with MATS or

the Michigan Mercury Rule. Regarding Mr. Rogers’ opinion, quoted above, MEC/NRDC

argues that Mr. Rogers’ testimony was equivocal on cross examination, and that DTE

failed to quantify any savings. Recognizing that REF may become unavailable at some

141 See DTE reply brief, page 50. 142 See 2 Tr 127.

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point, MEC/NRDC argues that any capital costs to comply with MATS and the Michigan

Mercury Rule at Monroe must be incurred anyway.143

Mr. Rogers acknowledged that he had not estimated the savings associated with

using REF at Monroe.144 On cross-examination, he testified to his opinion that in the

absence of REF, the company would need to use additives “to consistently 100% of the

time meet those limits,” and that he was “certain” that with REF, the additive system

would not be needed. 145 Subsequently he acknowledged that a back-up system would

be installed to allow the use of these additives even with REF, contending that DTE

would still save the cost of the additives, and that the injection system would be smaller

than if needed to be used 100% of the time.146 Mr. Rogers then acknowledged that

even without REF, treatment of the coal would not be required 100% of the time.147

2. SO2

DTE projects a small reduction in its need for SO2 emission allowances

attributable to burning REF coal. The number of emission allowances projected to be

saved and the associated dollar value of the savings are shown in Exhibit A-19. As

noted above, Ms. Wojtowicz testified that the company does not expect to purchase

emission allowances for the plan year. While the company could sell the number of

allowances projected to be avoided by burning REF fuel, she also testified the current

market price for SO2 allowances is close to zero, and that the market prices are so low

143 See MEC/NRDC brief at pages 59-62. 144 See 2 Tr 140. 145 See 2 Tr 138. 146 See 2 Tr 220 147 See 2 Tr 221, 232.

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that a sale might not be feasible.148 Exhibit A-19 nonetheless calculates the market

value of the avoided emission allowances, approximately $4,390 at Monroe and $1,907

for St. Clair for the 2013 plan year.149

For Belle River and St. Clair, emission allowance savings are projected from

2014 to 2017 as shown. For Monroe, DTE acknowledges that once the emission

control equipment planned for the plant is fully installed on all units by 2015, no further

SO2 savings will be realized by burning REF, although nominal savings of $263 are

included in Exhibit A-19.150

MEC/NRDC argues that this benefit is not only “de minimis” as stated, it is

essentially a cost to PSCR customers since the loss in value over time of the

allowances held by DTE in inventory is recognized at the time of the sale.151 That is,

consistent with Exhibit A-19, the inventory value of 8396 allowances ($133,000) will be

charged as a cost to the PSCR customers, offset by projected revenue of $6,217 from

the sale of those allowances in 2013. MEC/NRDC also cites Mr. Lapplander’s

testimony from Case No. U-16434-R, included in Exhibit MEC-25, 119-120,

acknowledging that 2012 projected SO2 cost savings were $544, but actual savings

were zero.

DTE responds to MEC/NRDC’s argument by citing Ms. Wojtowicz’s explanation

that since there would ultimately be a loss on the allowance inventory that cannot be

used in any event, it would be better to obtain some offsetting revenue.152

148 See 3 Tr 595. 149 Also see Mr. Krishnamurthy’s testimony at 3 Tr 626-627. 150 See Palmer, 3 Tr 531. 151 See MEC/NRDC brief, pages 52-57; reply brief, pages 18-19. 152 See DTE reply brief, page 50, citing 3 Tr 597.

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3. NOx

In order to get the tax benefits under section 45, DTE argues that the fuel

companies must be able to show a reduction in NOx emissions from use of the fuel.

This showing may be made by laboratory tests. DTE further asserts that the reason

NOx emission reductions were not included in the REF Adder is the difficulty of

measuring those benefits, which vary significantly with the coal burned.153 Nonetheless,

DTE argues that the potential savings in NOx emission allowances is a benefit to the

PSCR customers from using REF.

MEC/NRDC argues that DTE’s failure to provide even an estimate of this benefit

is striking considering the numerous witnesses asserting that the benefit exists, arguing

that DTE repeatedly relies on an alleged NOx emission allowance savings as a core

justification for the REF project, and has acknowledged that the tax credit requires a

showing of a 20% reduction in NOx emissions.154

DTE, in its reply brief, treats MEC/NRDC’s reference to the statutory prerequisite

to tax recovery as an acknowledgement that NOx emission allowance savings must be

at least 20%,155 although DTE does not then explain its own failure to include any

savings in the PSCR plan cost projections.

E. Fly Ash Disposal

DTE also acknowledges that an additional cost of burning REF coal includes

increased fly ash generation and thus increased fly ash disposal costs. DTE estimates

153 See 2 Tr 141. 154 See MEC/NRDC brief, pages 48-51; reply brief, pages 17-18. 155 See DTE reply brief, page 50, also citing 3 Tr 391-392.

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these costs at approximately $26,000 per year for St. Clair, and approximately $45,000

per year for Belle River, beginning in 2014.156 Mr. Krishnamurthy testified that DTE had

originally thought DTE would benefit from selling the additional fly ash at Belle River and

St. Clair, but it turns out that such sales are not possible. In his testimony in an earlier

case, Mr. Lapplander also explained that the use of PAC at Belle River and St. Clair

precludes the sale of fly ash.157

For Monroe, Mr. Krishnamurthy was not sure whether DTE would have increased

fly ash sales in addition to increased fly ash disposal costs:

Q. But my question is: Does burning REF at Monroe result in increased fly ash disposal costs versus burning regular untreated coal at Monroe? A: Part of it, at Monroe we sell fly ash. I would say portions of it we are getting the benefit and keep it it for ourselves. The other portion is included in, to the extent that it is land-filled on the web scrubbers, wet fly ash, I would say that is covered by the O&M, that O&M mechanism, the 2.76 million. So that is within, probably within that mechanics. It was negotiated into it. But generally we sell fly ash, I believe, at Monroe to some extent, a partial amount. I’m not conversant with that. . . . Somebody from the plant would be able to better answer that.158

F. DSI Sorbent Costs

Mr. Rogers testified to the company’s plans to comply with acid gas or HCl

emission limits using Dry Sorbent Injection (DSI):

A sorbent is injected into the hot flue gas leaving a coal-fired boiler. The sorbent reacts quickly with acid gases to form particles that can then be removed by the particulate control device, or electrostatic precipitator (ESP). A variety of alkaline reagent (or sorbents) are available based on the specific application, including existing air quality control equipment and pollutants to be controlled. Trona and sodium bicarbonate (SBC) were demonstrated through the Company’s test program to be cost-effective sorbents to use for the MATS requirements. The Company will use the

156 See Exhibit MEC-60. 157 See Exhibit MEC-34, pages 181-182. 158 See 3 Tr 699.

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most cost-effective sorbent depending on the cost of these sorbents at the time of application. Currently, the Company forecasts that it will use trona to control acid gases and [Particulate Matter]. See 2 Tr 128-129.

Burning REF coal also appears to increase the quantity of sorbent required to meet acid

gas emission limits.

Exhibit MEC-45, a discovery response regarding this issue, indicates that DTE is

hoping that a new version of S-Sorb (one of the REF components) will reduce the

additional trona needed. Exhibit MEC-45 estimates increased trona costs for the

current S-Sorb to be $6.9 million and for the new S-Sorb to be $1.4 million,

acknowledging that the new S-Sorb has not been tested yet:

Testing demonstrated that with the existing S-Sorb supply, the required sorbent injection rate while burning 100% LSW increased from 2 lb/MWh without REF to 7 lb/MWh with REF. While burning 85 LSW/15 bituminous blend, the required sorbent injection rate increased from 15 lb/MWh without REF to 19 lb/MWh with REF. An alternative S-Sorb supply is under review that would reduce this increase of DSI sorbents required while consuming REF. It is estimated that with this new source of S-Sorb, the required sorbent injection rate while burning 100% LSW increased from 2 lb/MWh without REF to 3 lb/MWh with REF. While burning 85 LSW/15 bituminous blend, the required sorbent injection rate increased from 15 lb/MWh without REF to 16 lb/MWh with REF.

But it is unclear whether the $1.4 to $6.9 million estimate includes additional units

because the mercury savings presented in Exhibit MEC-45 are on the order of $9

million, and DTE did not amend its mercury cost savings estimates in Exhibit A-2.

Exhibit A-2 presents DTE’s estimates of its DSI sorbent costs without regard to

REF-related increases, on the premise that DTE will recover increased costs from the

fuel companies as additional operations and maintenance expenses caused by burning

REF under section 9.4 of the BRFC and SCFC Refined Coal Supply Agreements.159

159 See Exhibit MEC-59.

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MEC/NRDC disputes that DTE’s contracts permit it to recover these costs, as discussed

below.

G. 1989 PA 2 Costs

Ms. Wojtowicz explained the impact using REF will have at the Belle River plant:

Since the fuel expense at Belle River Power Plant is used in determining the following year’s purchase power prices for the P.A. 2 contracts, the increase in fuel expense due to the use of REF will result in a higher purchase power price. The REF price will be adjusted to ensure that this increased expense does not result in increased PSCR expense, all other factors remaining constant. See 3 Tr 564.

These costs have not been projected on this record. Total costs for all PURPA

and PA 2 contracts are estimated at $29.6 million for 2013 in Exhibit A-16. Note that

Mr. O’Neill, in his rebuttal testimony, cited this impact in explaining why the REF costs

should be considered a PSCR expense.160

H. Refined Coal Adder

In addition to the cost of coal, DTE pays the BRFC and SCFC a “Refined Coal

Adder” for each ton of refined coal consumed at each plant. Mr. Krishnamurthy

testified:

[A]t Detroit Edison’s Belle River and St. Clair Power Plants, the additional PSCR cost for Refined Coal is limited to the lower of the PSCR benefit of reduced SO2 emissions and the reduced cost of mercury emissions compliance associated with the consumption of the Refined Coal, or the revenue requirement associated with the REF Project production facility. Thus, the cost of the Refined Coal Adder at Belle River and St. Clair Power Plants will be zero until such time as the plants experience an actual and measurable reduction in SO2 emissions or the reduced cost of mercury emissions compliance. Once the plants experience measurable reduced emissions, the cost of the Refined Coal Adder will be capped at the revenue requirement associated with the REF Project facility. Once the calculated cost of the Refined Coal Adder reaches this cap, any

160 See 2 Tr 257.

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additional benefits of reduced emission allowances will flow directly through to the PSCR customers. See Krishnamurthy at 3 Tr 616.

The formula for the Refined Coal Adder is contained in the Refined Coal Supply

Agreements for Belle River and St. Clair and is illustrated for SCFC in Mr.

Krishnamurthy’s Exhibit A-22. The Refined Coal Adder is essentially the same for both

BRFC and SCFC, except that the Belle River agreements include a recognition of the

Michigan Public Power Agency’s (MPPA’s) 18% ownership interest in the Belle River

plant. Exhibit A-20 includes the projected cost of the Refined Coal Adder as an element

of PSCR costs for the five-year plan period.

A review of the formula shows that it has multiple elements. Mr. Krishnamurthy

testified:

The REF Adder will consist of several components: (1) an adjustment amount related to fly ash disposal costs designed to keep Detroit Edison whole for any incremental fly ash disposal costs (beginning in January 2011); (2) an adjustment amount if any related to fly ash revenue (beginning in January 2015); (3) an adjustment amount based upon and no greater than Detroit Edison’s reduction in actual SO2 emission allowance expense (beginning in January 2011); and (4) an adjustment amount based upon Detroit Edison’s reduction in actual mercury compliance expense (beginning in January 2015). The latter two adjustments combined are capped at the Fuel Companies’ revenue requirements.161

MEC/NRDC argues that the limited emission-related benefits discussed above

suggest that the Refined Coal Adder will never exceed the fuel companies’ revenue

requirements, and thus no environmental benefits will be realized by PSCR customers.

See MEC/NRDC brief, page 58. DTE witnesses acknowledged that they are not

projecting the environmental benefits calculated under the agreements will exceed the

revenue requirement cap under the agreements.

161 See 3 Tr 625.

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Reviewing Exhibit C to the SCFC agreement in Exhibit A-30 from Case No.

U-16434-R, the first element is the minimum of the “DECo Environmental Benefit” and

the Revenue Requirement. The “Environmental Benefit” includes an SO2 component, a

mercury component, and a fly ash disposal component.162

The SO2 benefit component compares actual SO2 emissions per unit to a

benchmark calculation to reflect the status quo emission level. The difference between

the actual emissions and the benchmark determine the number of SO2 allowances not

consumed due to REF. The value of those allowances not consumed is measured

either by the actual sale price, or an index value if they are not sold. Recall that Ms.

Wojtowicz testified that the company might not actually be able to sell the emission

allowances. Thus, it is possible that DTE may still pay BRFC or SCFC a small amount

attributable to SO2 emission allowances savings when DTE was not able to sell those

emission allowances.

For mercury, as noted above, the savings DTE projects will not occur until the

MATS requirements take effect in 2015, and the mercury benefit component of the

Refined Coal Adder is zero until that date. Mr. Rogers estimated reduced savings on

PAC and BrPAC costs to reduce mercury emissions beginning in 2015, as shown in

exhibit A-2. The mercury benefit calculation under Exhibit C is highly complex. As

shown on pages 46-47 of Exhibit A-30 (Case No. U-16434-R) for Belle River and pages

423-425 of this exhibit for St. Clair, the Adder contains components for the “DECo

Mercury Benefit” that reflect more than the sorbent cost savings explained by Mr.

Rogers. The “DECo Mercury Benefit” is equal to the “Avoided Mercury Compliance

Cost.” Assuming MATS compliance is required in 2015, DTE may be required to pay 162 See Exhibit A-30 (Case No. U-16434-R), page 420.

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BRFC or SCFC the difference between the O & M expenses for mercury control at

DTE’s plants that do not use REF and the O & M expenses at Belle River or St. Clair.

Again assuming MATS compliance is required in 2015, DTE may also be required to

pay BRFC or SCFC 15% of the difference between the capital costs incurred to control

mercury for DTE’s generating fleet and the capital costs incurred to control mercury at

Belle River or St. Clair. These payments, as part of the Environmental Benefit

component of the Adder, would be capped at the fuel companies’ revenue requirement.

In addition to the mercury benefit that is capped by the fuel companies’ revenue

requirement, the compensation formula also has an additional element related to

mercury capital cost savings, labeled “DECo Avoided Hg Capital Amortization

Calculation”.163 A review of this formula indicates that it will be zero unless the

“Environmental Benefit” piece of the REF Adder is greater than the SCFC revenue

requirement as calculated in the exhibit.

Note that DTE has not claimed any actual capital savings associated with using

REF fuel to control mercury emission costs, and these potential payments have not

been shown to capture real benefits to PSCR customers.

The Adder also contains a formula to address both fly ash disposal and the

potential sale of fly ash. Because the fly ash disposal costs are base rate O & M costs

and not PSCR costs, DTE retains the reimbursement relating to fly ash disposal, and

does not credit it to PSCR costs. Thus, the Adder amounts projected in Exhibit A-20 do

not include these offsetting reimbursements.

The revenue requirement calculation provided for in Exhibit C to the Refined Coal

Supply Agreements acts as a cap on the “environmental benefits” as discussed above, 163 See Exhibit A-30 (Case No. U-16434-R), page 51 for Belle River, and pages 429-430 for St. Clair.

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and is designed to replicate a revenue requirement for DTE, i.e. using expenses, a “rate

base’ concept, and DTE’s cost of capital. It does include the fuel company’s coal

inventory as a capital item, as shown in Exhibit A-22.

Consistent with Mr. Krishnamurthy’s testimony, the Adder also does not include

any element for NOx control cost savings, which as noted above, have not been

quantified.

The Refined Coal Adder in the Belle River agreements also contains a formula to

reimburse DTE for any additional costs incurred in contracts under 1989 PA 2. Note

that the formula in the agreement does not directly calculate the cost increase to DTE

under the PA 2 agreements, but the formula returns a fraction of the SO2 benefit and

the “Avoided Hg Capital Amortization”, based on the PA 2 contract MWh as a

percentage of the total Belle River and PA 2 contract MWh.164

The Adder does not contain an element to address increased alkaline sorbent

costs for the DSI system. As Mr. Krishnamurthy testified, DTE believes that these costs

are reimbursable under section 9.4 of the Refined Coal Supply Agreements, which

provides for additional payments for “increased operations and maintenance expense”

from burning refined coal. Noting that DTE frequently draws a distinction between

“PSCR costs” and “operations and maintenance” costs, MEC/NRDC and MCAAA

question whether this language is sufficient to protect the PSCR customers from these

increased costs. Operations and maintenance costs are not defined in the agreements.

As discussed above, DTE also argues that it is seeking a solution through the fuel

companies to use an alternative sorbent in their process that would reduce the

additional alkaline sorbent costs. 164 See Exhibit A-30 (Case No. U-16434-R), page 53.

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I. Coal Fee Rate

The Coal Fee Rate or discount DTE receives when it purchases refined coal for

the Monroe plant is approximately $1.03 per ton for the first 7 million tons, and $1.50 for

additional tons. Mr. Krishnamurthy testified that the total benefit for 2012 was

$7,920,268, or an average of $1.07 per ton.165 Exhibit MEC-32, a discovery response

from Case No. U-16892, estimated the net present value of the coal fee rate payment to

be $63 million over the life of the Monroe project, not including incremental expenses of

$22.4 million also identified on that exhibit.

DTE divides the amount it receives under this provision to an Operations and

Maintenance Expense portion to be retained by the company and an amount offsetting

the PSCR cost of REF coal. Mr. Krishnamurthy testified that the O & M compensation

to DTE is approximately $2.76 million, while the PSCR costs are credited with

approximately $.65 per ton for the first 7 million tons, and $1.50 for each ton after that.

On this basis, Exhibit A-20 shows DTE’s projected benefit to PSCR customers from

their share of the Coal Fee Rate equal to approximate $4.6 to $4.8 million per year for

the years 2013 to 2017. As Mr. Sansoucy testified166 and MEC/NRDC and MCAAA

argue, DTE has not provided a cost-based analysis supporting this division, or

established that these payments are sufficient to cover its incremental costs in providing

the coal consulting and handling services provided for under the agreement.

Exhibit MEC-32 does contain a projection of the incremental operations and

maintenance expenses under the agreement, projecting increases from $2.76 million in

2012 to $3.6 million in 2021.

165 See 3 Tr 650. 166 See 2 Tr 399.

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As discussed below, DTE argues that the Coal Fee Rate is justified with

reference to available information regarding the terms of similar transactions, including

an offer made to DTE by another potential supplier of REF coal.

J. Working capital benefit

DTE argues ratepayers have already benefited from the REF transactions

through a reduction in the working capital allowance included in base rates due to

DTE’s transfer of a portion of its coal inventory to the fuel companies in 2009.167 Mr.

Krishnamurthy testified that the $38.6 million in inventory transferred to BRFC and

SCFC in 2009 resulted in a $4.1 million reduction in base rates compared to the rates

that would have been established absent the transfer.168 His rebuttal testimony

presented Exhibit A-38 to illustrate his calculation of this effect. DTE further argues that

ratepayers will obtain a greater benefit when rates are reset to reflect additional

transfers since 2009. Mr. O’Neill also testified that the 2009 fuel inventory level used in

setting current rates was at a historically low level, and DTE’s own fuel inventory is

currently $70 million higher.169

MEC/NRDC argues that the working capital benefits are overstated, asserting

that at most, only a small amount is currently included in rates, and DTE does not plan

to file another rate case until 2015, at which point the contracts will be more than half

completed. Mr. Sansoucy referenced Mr. Lapplander’s estimate of a working capital

benefit of $140 million over the life of the REF project and Exhibit MEC-32, and testified:

The total rate reduction attributed to the working capital benefit from removing the coal inventory goes up each year with the price and, in some

167 See DTE brief, page 18, citing 2 Tr 247-248, 265. 168 See 3 Tr 623, 650. 169 See 2 Tr 265.

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instances, the tonnage of the coal sold to the Fuels Companies. However, as Mr. Lapplander explained in his direct testimony in Case U-16892 at 2 Tr 63-64, the reduction in inventory used to set DTE Electric’s current working capital component in rate base was set in 2009. It has not been adjusted since then, so DTE Electric customers are not receiving the larger working capital benefits reflected in the table from 2010 to the present. Mr. Lapplander stated in his rebuttal testimony in Case U-16892 at 2 Tr 84 that the customers will ultimately receive a larger working capital benefit when base rates are re-set, but they are not receiving the larger benefits identified each year in his tables in the meantime. They are receiving the 2009 level of benefit. Moreover, in Case No. U-17068, DTE Electric applied for approval to amortize $127 million in revenue decoupling refunds it no longer is required to distribute to its ratepayers as a result of the Michigan Court of Appeals having reversed the Commission’s approval of revenue decoupling. DTE Electric stated in its application that it would most likely defer a new rate case until 2015 if the Commission granted the amortization request, which the Commission did in an order dated September 25, 2012. Therefore, DTE Electric customers are likely to receive the 2009 level of working capital benefit until at least 2015, and not the levels identified in the tables prepared by Mr. Lapplander. 170

MEC/NRDC also argues that any future rate impact is speculative, since DTE has

acknowledged that its overall fuel inventory could rise at the same time that any working

capital reduction occurs. 171

MCAAA also argues that DTE has not established that inventory values used in

the rate case reflected these sales, and further contends that DTE may well be double-

recovering these costs:

DECo in these REF cases has also made unfounded claims that customer benefits of the REF program include a reduction in Detroit Edison’s working capital expense by not carrying coal inventory, or reductions in emission allowances expense, or a cap on never paying more than the value of environmental benefits not received. However, these assertions are highly questionable. The “Fuel Companies” are going to charge Edison for their capital costs, including a return on their investment in fuel inventory (fuel inventory which otherwise would have been on the books of Detroit Edison). The result is a zero net savings for working capital.

170 See 2 Tr 388. 171 See MEC/NRDC brief, page 71-72, citing O’Neill at 2 Tr 287.

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Rather than a savings, the aspect of the “Fuel Companies” owning fuel inventories may well result in a double recovery of capital costs related to these fuel inventory. [sic] A review of the commission’s October 26, 2011 Order in Case No. U-16472 (DECo’s most recent general electric rate case) establishes that there is no reference to a reduction of DECo’s working capital ratebase specifically for fuel transferred to REF projects. DECo’s projected test year in its rate case, U-16472, did not include a downward adjustment to working capital to account for the REF transactions. DECo’s working capital costs for coal inventory are thus still being recovered in DECo’s base rates, or are covered by charges of the fuel companies to DECo under the REF arrangements. Therefore, DECo customers are being charged for all DECo fuel inventory, including any transfers to REF projects.172

In its reply brief, DTE cites Mr. Lapplander’s testimony from Case No. U-16047-

R, which it argues Mr. Lapplander affirmed in Case No. U-16892, citing Exhibit MEC-25,

page 11:

[T]here was no specific reference in Case No. U-16472 to the reduction of Detroit Edison’s working capital for the coal transferred to the REF projects. However, there was a sale of coal inventory that occurred in December 2009. The month-over-month change in fuel inventory from November 2009 to December 2009 was a $63.4 million reduction. Included in the $63.4 million reduction was the sale of 1.7 million tons of coal for $38.6 million to the Belle River and St. Clair Fuels Companies. In Detroit Edison’s rate case, Case No. U-16472, the 12-month ending historical period was the 12-months ending December 2009. To project the working capital component of rate base for the forecast period, the starting point was the December 31, 2009 balance sheet values. The resulting rate base therefore reflects the coal sale to the Fuels Companies in December 2009. Thus, Mr. Peloquin is incorrect in his assertion that Detroit Edison customers are being charged for all Detroit Edison fuel inventory, including any transfers to REF projects. Customers are experiencing lower base rates due to the sale of coal inventory in December 2009.173

DTE does not respond to MCAAA’s argument regarding a double recovery of working

capital costs from ratepayers.174

172 See MCAAA brief, page 39. 173 See DTE reply brief, pages48-49. 174 Id.

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DTE’s quotation of Mr. Lapplander’s testimony from Case No. U-16047-R

implicitly acknowledges one of the concerns raised by MCAAA, whether the working

capital allowance used in DTE’s last rate case rate case reflects $38.6 million in coal

inventory transfers from DTE to the fuel companies. Mr. Lapplander’s testimony as

quoted by DTE acknowledges that DTE used a projected working capital balance, and

does not indicate on what basis that projection was made. Thus, while DTE’s Exhibit

A-38 reasonably estimates the impact on rates from a straight-forward $38.6 million

reduction in working capital, to evaluate the claim that the working capital allowance

was lower than it would otherwise have been in the absence of the December 2009

transfer to the fuel companies requires a more extensive analysis of how the December

2009 inventory value was used in the projected working capital allowance. Exhibit

MEC-32 contains this analysis. In responding to a discovery question in Case No.

U-16892, Mr. Lapplander explained:

Exhibit A-2 Schedule B3.2 [from Case No. U-16472] page 1 of 2, line 25 shows Inventory-Fuel of $106,653,000 which is carried forward to the projected test year. Line 49 of Exhibit A-9, Schedule B4 [from Case No. U-16472] shows a Working Capital value of $592,444,000. This working capital value is referenced on page 26 in the October 20, 2011 Commission Order in Case No U-16472. The final Working Capital value included in Rate Base shown on page 92 of the Case No. U-16472 Commission Order dated October 20, 2011 was adjusted downward ($505 million) but not due to fuel inventories. Therefore the Rate Base shown on page 92 of that Commission Order and the Revenue Deficiency calculation reflect the sale of coal inventory to the Fuel Companies in December 2009 as explained in my testimony.

No party disputed this explanation that the December 2009 fuel inventory was the

forecast value used in the projected test year working capital requirement, thus is it

reasonable to accept DTE’s claim that the current base rates reflect a $4 million

reduction due to the inventory transfer.

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More significantly, DTE has failed to address MCAAA’s claim that working capital

costs traditionally recovered by DTE through base rates have been shifted to PSCR

costs, because the fuel companies may charge DTE for essentially the same costs, the

carrying costs of inventory. The underlying cost of coal under these agreements,

quoted more fully in section C above, is the fuel companies’ inventory price. There is no

explicit control on charges the fuel companies may make to inventory, except in the

Monroe agreement which precludes recovery of the Coal Fee Rate through the

inventory charge. Note that the express inclusion in inventory of “all other charges and

costs relating to such period and charged to Seller coal inventory in accord with Seller’s

customary inventory accounting procedures consistently applied” is not a meaningful

constraint because the fuel companies were created only to enter into these

transactions with DTE.175 DTE witnesses have acknowledged that the fuel companies

do not have the same accounting as DTE.176 Mr. Krishnamurthy acknowledged that he

did not know whether the fuel companies recovered their working capital costs through

their inventory charges:

Q: (By Mr. Keskey): Now, with respect to working capital, when Edison buys back the coal from the fuel companies, is the cost of that coal inclusive of a working capital component? A: Subsection (e) that I mentioned, line item 8, is to explain reduction in Detroit Edison’s working capital expense by having sold inventory to the fuels company. I realize that’s not the question you asked. I’m not aware that buying back the coal includes certain working capital component, I’m not aware.

175 See e.g. Krishnamurthy, 3 Tr 636 (“The Fuels companies were created to comply with Internal Revenue Code §45(e)(8) . . . which requires an entity unrelated to the purchaser of REF to produce and sell REF to the purchaser.”) 176 See, e.g. Lapplander, Exhibit MEC-34, pages 125-126; Exhibit MEC-35, page 66.

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Q: Well, if the Detroit Edison is buying the coal back from the fuel companies at a fully allocated cost, would that not include working capital related to that coal? A: Only to the extent it goes back into inventory. Like I told you before, when we buy back the coal, it is refined coal, it is being consumed. Q: O.K. So when the coal is burned, which is very close to when Edison buys back the coal time wise - - A: On a conveyor belt? Q: - - wouldn’t that cost include all of the fuel companies’ costs, including the working capital component? A: No, it’s got all the fully allocated costs. Q: Well, the working - - I mean the fuel companies wouldn’t fail to recognize the working capital component for or related to that coal, would it? A: Like I said before, we sell them coal at cost, we buy it back at cost, the refined coal, and the inclusion or exclusion of this working capital component at the buy-back structure, I don’t think it’s included. I mean I don’t know. Q: Well, if you don’t know, you don’t know. A: I don’t know.177

That inventory costs may contain financing charges is not surprising; Mr. Wines

explained that if DTE did not own nuclear fuel, interest expense would be a component

of the expense:

In-core interest expense represents the periodic in-core interest payments made on the unamortized value of the in-core fuel. Currently, Detroit Edison owns the nuclear fuel so no interest expense is being charged to PSCR expense. However, Detroit Edison does incur expenses related to the cost of money needed to own the fuel and these are currently included in base rates.178

177 See 4 Tr 804-805. 178 See 2 Tr 31.

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Exhibit MEC-32, discussed above, contains DTE’s estimate of the working capital

benefit to ratepayers if the full magnitude of the transfer of DTE inventory to the fuel

companies were entirely reflected in rates. This exhibit simultaneously shows the

magnitude of the potential transfer of inventory financing costs to PSCR costs if the fuel

companies recover their financing costs through the inventory price. Based only on the

inventory holdings of the fuel companies, Exhibit MEC-32 calculates a net present value

of the cost of holding inventory totaling approximately $72 million: $29 million for Belle

River, $24 million for St. Clair, and $19 million for Monroe. For 2013 alone, the estimate

in $7.4 million, which exceeds the magnitude of the working capital benefit reflected in

rates. Since this analysis is based on DTE’s cost of capital, the net present value of the

cost to PSCR customers from paying financing costs to the fuel companies could be

even higher if the financing costs for the unregulated fuel companies are greater than

DTE’s capital costs as set in its last rate case.

Mr. O’Neill’s rebuttal testimony that DTE’s current working capital requirements

are higher than the working capital requirements used in setting current rates does not

establish that DTE’s rates are currently too low, and is not relevant to the evaluation of

the REF project.

For these reasons, this PFD concludes that DTE has not established a working

capital benefit.

K. Act 304 (reasonableness and prudence standard) MCL 460.6j(6) governs this proceeding and directs:

In its final order in a power supply and cost review, the commission shall evaluate the reasonableness and prudence of the decisions underlying the power supply cost recovery plan filed by the utility pursuant to subsection

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(3), and shall approve, disapprove, or amend the power supply cost recovery plan accordingly. In evaluating the decisions underlying the power supply cost recovery plan, the commission shall consider the cost and availability of the electrical generation available to the utility; the cost of short-term firm purchases available to the utility; the availability of interruptible service; the ability of the utility to reduce or to eliminate any firm sales to out-of-state customers if the utility is not a multi-state utility whose firm sales are subject to other regulatory authority; whether the utility has taken all appropriate actions to minimize the cost of fuel; and other relevant factors. . . .

Section 6j(6) also directs: “The factors shall not reflect items the commission could

reasonably anticipate would be disallowed under subsection (13).” MCL 460.6j(6).

MEC/NRDC and MCAAA argue that DTE has not taken all appropriate actions to

minimize the cost of fuel.179 MEC/NRDC also argues that the company is proposing to

recover costs that should be disallowed under subsection (13)(e), which directs the

Commission to:

Disallow the cost of fuel purchased from an affiliated company to the extent that such fuel is more costly than fuel of requisite quality available at or about the same time from other suppliers with whom it would be comparably cost beneficial to deal.180

Mr. Crandall testified to some potential concerns from sales to the fuel

companies at below-market prices:

Mr. Krishnamurthy’s argument that the price at which DECO sells coal to the Fuels Companies doesn’t matter fails to consider the impact of sales of REF to non-affiliated entities. If a Fuels Company sells cleaned coal to a party other than DECo, they may generate a profit on the sale which will be retained by the Fuels Company (and DTE) rather than returned to the ratepayers.

* * * Finally, there is also a possibility that the Fuels Company could buy the coal at below market prices and sell it at below market prices, effectively artificially becoming a more competitive supplier rather than keeping all the profits. This would enhance their sales volumes, but the lower cost

179 See, e.g. MCAAA brief, page 55; reply brief, pages 3-4. 180 MCL 460.6j(13)(e). See MEC/NRDC brief, page 86-87; reply brief, page 22-23.

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would in effect be made possible only because of the existence of and past investment by ratepayers.181

In its initial brief, addressing Mr. Crandall’s testimony, DTE cites Mr.

Krishnamurthy’s rebuttal testimony as follows:

With respect to fully allocated cost, the price at which Detroit Edison is selling the coal is equal to Detroit Edison’s fully allocated cost, or book cost. The Fuels Companies will simply use the coal to produce REF and sell the REF back to Detroit Edison for consumption at the BRPP, SCPP and MPP and any adjustments to the sale price to reflect any higher market pricing would only serve to increase the resale price to Detroit Edison. Since the asymmetrical pricing provision of the Code of Conduct is intended to prevent Detroit Edison from subsidizing its unregulated affiliates, it is clear that this transaction is consistent with that intent and effectuates the proper outcome.182

In his rebuttal testimony, Mr. Krishnamurthy also testified that is was only speculative

that DTE or its affiliates would profit from sales to third parties:

Witness Crandall admits (refer to page 7, lines 16-22 and page 8, lines 1-4) and recognizes the statements made by Company Witness Lapplander in his rebuttal testimony in Case No. U-16434-R that the Detroit Edison’s REF Project agreements limit the ability of the Fuels Companies to resell to third parties and that they would need Detroit Edison’s consent to resell to third parties. For Detroit Edison to provide consent to sell REF coal to a third party by the Fuels Company, Detroit Edison would require that the original sale of Feedstock coal meet the asymmetrical pricing guideline included in the Code of Conduct and any discussions of a profit motive is simply meritless. Witness Crandall does not dispute Witness Lapplander’s assertions, but speculates that Detroit Edison would readily provide consent at the direction of its controlling parent company DTE Energy. Mr. Crandall in making this comment (page 8, lines 3-4) is speculating that Detroit Edison would provide consent without regard to protecting the interests of its customers. Mr. Crandall in making this assertion fails to recognize that the checks and balances within Act 304 preclude such wanton, irresponsible and deliberative act by Detroit Edison that is detrimental to its customers. Detroit Edison purchases coal equivalent to the consumption at its plants and that premise has not changed in its responsibilities as Consultant in the respective Fuels Companies Coal

181 See 2 Tr 333. 182 See 3 Tr 619, DTE brief, pages 23-24.

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Handling and Consulting Agreements. Alternatively, Witness Crandall suggests as a solution that Detroit Edison should profit from the sales to the Fuels Companies (page 8, lines 9-14), but he fails to recognize as he did earlier (page 6, lines 19-23) that the sale back would result in no net cost to the ratepayers.183

A review of the transactions in Exhibit A-30 from Case No. U-16434-R does not

support DTE’s characterization of the REF project. DTE argues that it sells coal to the

fuel companies and purchases it from the fuel companies at the same price—subject to

the Refined Coal Adder or Coal Fee Rate (discount) for refined coal purchased. DTE’s

witnesses who testified on this topic each apparently believe that this is the case. Mr.

Krishnamurthy presented Exhibit A-23 to demonstrate compliance with the Code of

Conduct. Page 4 of this exhibit depicts the sale of coal from DTE to BRFC and SCFC

and back again to DTE with the note: “No impact on PSCR – coal returns to DetEd at

same cost sold to FuelCo.” At page 8, the exhibit asserts: “Detroit Edison sells coal to

the Fuels Companies upstream of the plant site at its cost. As discussed below, the

fuels Companies sell the same coal back to Detroit Edison at the same cost that Edison

originally charged for the coal. There is no net impact to Edison’s PSCR charges as a

result of the coal component of the overall transaction.”184

As discussed in sections C and J above, the contracts do not require that the fuel

companies resell coal to DTE at the same price they paid DTE for the coal, with an

additional adjustment for treatment of the coal. Instead, for purchases of Refined Coal

or purchases of untreated coal from the Coal Yard, the price DTE pays is based on the

inventory cost on the fuel company’s books, which need not match the price at which

183 See 3 Tr 643. 184 And see Krishnamurthy, 3 Tr 625, 684, and Mr. Lapplander’s testimony from prior cases, Exhibit MEC-25, pages 26, 28, 88, 146-147, Exhibit MEC-34,pages 16, 97, 108, Exhibit MEC-35, pages 77-78, 161.

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DTE sold the coal initially. First, the contractual inventory price may include other costs

incurred by the fuel companies, including reimbursement to DTE for coal consulting and

handling services at Belle River and St. Clair,185 and inventory financing costs.

Transportation costs are also expressly mentioned in the inventory price provisions of

the contract, even though these costs are also directly reimbursed to DTE in its role as

Coal Consultant.

Second, the fuel companies may contractually purchase coal from third parties,

as long as the coal conforms to DTE specifications. Although both Mr. Krishnamurthy

and Mr. Lapplander believed that DTE had sole responsibility for coal procurement and

purchasing under the coal handling and consulting agreements, a review of the

contracts shows that DTE’s authority is more limited. DTE is the “exclusive” coal

consultant under each coal consulting and handling agreement, but this “exclusivity” is

not defined in the agreements. Instead, DTE has limited powers of procurement and

purchasing spelled out in Article VI of each agreement.

And the Refined Coal Supply Agreements further clarify the fuel companies’

independence in coal procurement. Note, too, that one of the “project documents” not

included in this record is the St. Clair Agreement between BFC and SCFC. Mr.

Lapplander acknowledged that this arrangement is “confusing”, but nowhere has DTE

made an effort to show that it is reasonable and prudent for the ratepayers.

For MFC, section 6.1 of the Coal Feedstock Purchase Agreement is also explicit

that MFC is not required to purchase from DTE all the coal it needs to meet its

185 While Mr. Krishnamurthy and Mr. Lapplander both testified that the coal handling and consulting fees are “netted” or zeroed out by the corporate accounting program, which would be consistent with section 9.3 of the Refined Coal Supply Agreement, Mr. Krishnamurthy also testified that the coal handling and consulting fee is charged back to DTE as REF is purchased, which instead is consistent with inventory pricing.

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requirements under the Refined Coal Supply Agreement. Section 6.1 of the Coal

Feedstock Purchase Agreement as originally entered did require MFC to purchase from

DTE all coal required to meet its obligations under the Refined Coal Supply Agreement,

but this section was also amended to eliminate this obligation.186

Third, while the fuel companies’ ability to sell refined coal under the agreement

requires DTE’s consent, DTE has the ability to direct the sale of unrefined coal from a

fuel company to others, if the fuel company determines it has coal available, subject to

DTE’s undertaking to replace the coal with conforming coal.

That the parties would be concerned about the potential for PSCR customers to

pay higher costs under these contracts than if DTE were simply purchasing all the coal

for its power plants is not unreasonable given that DTE purchases as much as 70% of

its total coal through these affiliate transactions.187 Contrary to Mr. Krishnamurthy’s

rebuttal testimony, pointing out the potential for excessive or duplicative costs to be

passed onto ratepayers is consistent with the checks and balances in Act 304. It does

not constitute a condemnation of DTE’s motives or competence, and is no different from

any proposed disallowance or challenge to the utility’s decision-making under Act 304.

Neither Mr. Krishnamurthy nor Mr. Lapplander testified regarding the actual

invoiced transactions. Neither of them are attorneys. Mr. Lapplander testified that he

negotiated “the commercial provisions” but did not do the “wordsmithing”.188 He was not

aware that DTE has the ability to audit the fuel companies’ books and records under the

agreements,189 and he had not reviewed any invoices from the fuel companies.190 Mr.

186 See Exhibit A-30 (Case No. U-16434-R), pages 791 and 804. 187 See Lapplander, Exhibit MEC-34, pages 104-105. 188 See Lapplander, Exhibit MEC-35, page 94. 189 See Exhibit MEC-25, page 72; section 9.7 of each Refined Coal Supply Agreement grants audit rights.

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Krishnamurthy was not directly involved in negotiating the agreements, although he

supported Mr. Lapplander in the negotiation of the agreements with MFC, and he

testified that he was not comfortable with accounting questions.191 Therefore, the

assurances of these witnesses that there is no cause for concern with the affiliate

transactions must themselves be considered speculative.

Based on the foregoing discussion, this PFD concludes that DTE has failed to

take all reasonable and prudent actions to minimize the cost of fuel, as required by Act

304, because it has failed to ensure that the inventory price of coal it pays its affiliates is

reasonable and prudent. It may be that DTE purchases all coal acquired by the fuel

companies, and that the inventory price DTE pays for that coal will match the price at

which it sold the coal, but it has not assured contractually that this is the case.

MCAAA’s argument that the REF project agreements complicate audit of DTE’s

coal purchases is on point. Based on the series of agreements DTE has entered into,

to determine whether PSCR customers are paying rates that reflect the best contracts

DTE could negotiate, a complex series of transactions need to be audited.

Traditionally, the following transactions could be audited:

Suppliers # 1 to 11 3 Tr 613

→ DTE → PSCR

To ensure no abuse is taking place and PSCR costs are appropriately minimized,

Staff’s audit would include significantly more transactions. In the following diagrams,

each arrow represents a different set of transactions (invoices or charges) to be audited.

190 See Exhibit MEC-34, page 109. 191 See 3 Tr 679.

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For Belle River, because DTE purchases from BRFC are not necessarily purchased

from DTE at the same price DTE charged BRFC, and because BRFC can purchase

coal from other suppliers, BRFC purchases making up its inventory will need to be

reviewed, as well as potential sales to third parties:

DTE Inventory →

DTE Suppliers # 1 to 11 3 Tr 613 →

Belle River Fuels Company

→ →

DTE → Other Purchasers

PSCR

Other Suppliers →

The MFC transactions would follow the same pattern. The transactions for

SCFC are potentially more complicated, because SCFC also purchases coal from

BRFC, under an agreement that is not in this record:

DTE Inventory →

DTE Suppliers #1 to 11 3 Tr 613

→

St. Clair Fuels Company

→ →

DTE → Other

PSCR

Belle River Fuels Company

→

Purchasers

Other Suppliers →

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A review of the benefits of the agreements as established on this record also

does not show that the benefits justify the complexity of these agreements. As

explained in section D above, for Belle River and St. Clair, the SO2 emission allowance

and mercury emission control savings are subsumed by the Refined Coal Adder, up to

the fuel companies’ revenue requirements as contractually defined, and the complex

Adder calculation may overstate these benefits at greater cost to the PSCR customers.

NOx benefits, which would not be subject to the adder, have not been estimated or

quantified. And the working capital benefit, with a quantified $4 million captured in

current base rates, may be eviscerated by the potential financing costs included in the

inventory price DTE pays for coal. Additional costs of the REF project, including

increased DSI-sorbent requirements and other incremental costs may not be fully

recovered under the Adder calculation or other provisions of the agreements.

For Monroe, SO2 and mercury benefits are minimal, with SO2 benefits estimated

at less than $300 by 2015,192 and mercury benefits unquantified. NOx benefits likewise

have not been quantified, and working capital benefits which are not yet reflected in

rates may be working capital costs if MFC’s inventory price includes financing costs

associated with carrying the inventory. The most tangible benefit is the Coal Fee Rate

received under the Monroe Coal Handling and Consulting Agreement, since DTE

proposes to credit approximately $4 million of this fee to offset PSCR costs, while the

remainder offsets incremental operations and maintenance expense. But because DTE

has not provided a study of its costs, or incremental costs, in operating under that

agreement, it has not established that it is reasonable to credit any of the Coal Fee Rate

to the PSCR costs. Asked about the costs included in the $2.76 million estimate of 192 See Exhibit A-19.

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incremental O & M at Monroe, both Mr. Krishnamurthy and Mr. Lapplander cited only

“plant personnel”. 193

For these reasons, DTE has failed to establish that PSCR customers benefit from

any of these agreements.

L. Arm’s-length transactions

The parties also dispute whether the agreements should be considered arm’s-

length agreements. DTE argues that they should, citing Mr. Krishnamurthy’s testimony

and rebuttal exhibits, and the Commission’s decision in Case No. U-16892.194

MEC/NRDC and MCAAA disagree. MCAAA cites Mr. Crandall’s testimony.

MEC/NRDC argues that the benchmarks provided by DTE do not justify the agreements

and further contends that DTE did not expend any effort investigating alternatives prior

to entering into the agreements.195

Part of this dispute is merely over terminology. When DTE negotiates with its

affiliates, the resulting transactions do not meet the common understanding of “arm’s

length,” regardless of the motivation of the negotiators. For example, Black’s Law

Dictionary defines the term as follows:

Said of a transaction negotiated by unrelated parties, each acting in his or her own self interest; the basis for a fair market value determination. Commonly applied in areas of taxation when there are dealings between related corporations, e.g. parent and subsidiary. . . . The standard under which unrelated parties, each acting in his or her own best interest, would carry out a particular transaction. For example, if a corporation sells property to its sole shareholder for $10,000, in testing whether $10,000 is an “arm’s length” price it must be ascertained for how much the

193 See Lapplander, Exhibit MEC-34, page 113; Krishnamurthy, 3 Tr 699, 4 Tr 785-787. Also see Exhibit AG-2. 194 See DTE reply brief, pages 44-50. 195 See MEC/NRDC brief, pages 75-83.

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corporation could have sold the property to a disinterested third party in a bargained transaction.196

Thus, DTE’s argument is properly evaluated as a claim that the REF transactions mirror

an arm’s-length agreement. Mr. Lapplander’s belief that he negotiated in the best

interest of DTE does not change the fundamental characterization of the transactions as

not in fact arm’s length. Moreover, whether a transaction can be characterized as arm’s

length does not itself establish reasonableness and prudence under Act 304.

Nonetheless, to evaluate DTE’s claim that the REF project agreements mirror

arm’s length transactions, there are two time periods to evaluate. Looking at the 2009

agreements, DTE relies on the agreements reached between MPPA and BRFC to

support its claim that the BRFC and SCFC transactions match a disinterested third-

party transaction. As to that claim, this record contains no useful information

establishing that MPPA reached an independent agreement with BRFC.197

Mr. Krishnamurthy speculates that because the MPPA agreement with BRFC is

identified as a “project document” in the BRFC/DTE agreements in Exhibit A-30 from

Case No. U-16434-R, it must have been reached before the BRFC/DTE agreements. A

review of the Refined Coal Supply Agreement, for example, shows that the “MPPA Coal

Inventory Purchase Agreement” identified as one of the “project documents” is defined

as: “The Coal Inventory Purchase Agreement, to be entered into on or about the

Commercial Operations Date, by and between BR Fuels and MPPA.”198 Also

referenced as a project document is a “Memorandum of Understanding with respect to

the Participation Agreement, to be entered into on or about the Commercial Operations

196 See Black’s Law Dictionary (5th Ed. 1979), p 100 (citation omitted). 197 See e.g. Krishnamurthy, 4 Tr 800-804; Lapplander, Exhibit MEC-34, pages 148-157; Exhibit MEC-35, pages 129-131, 183-186. 198 See Exhibit A-30 (Case No. U-16434-R), page 10 (emphasis added).

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Date, by and between MPPA and Detroit Edison.” Neither of these agreements is in the

record. But the existence of these agreements does not establish that MPPA reached

an independent agreement with DTEES, or address to what extent MPPA could have

negotiated alternative arrangements.

Turning to the later agreements between DTE and MFC, Mr. Krishnamurthy

provided rebuttal testimony and exhibits to establish what market alternatives were

available to this transaction. Some of this information was presented in his Exhibit

A-33, which was subsequently withdrawn by agreement of the parties.199 Mr.

Krishnamurthy testified that none of the utilities he identifies as using refined coal own

the REF facility or receive the tax credits.200 Exhibit A-34 contains an REF project

description from Arthur J. Gallagher & Co, indicating reliance on “investment partners”

other than the host utility.201 Mr. Krishnamurthy also presented in Exhibit A-37, an

unsolicited offer he testified came from A J Gallagher Coal, Inc., which outlines the

general terms of an agreement for Canadys Refined Coal LLC to provide refined coal at

DTE’s River Rouge plant, including a $0.25 per ton site lease payment and a $0.25 per

ton discount on the refined coal. From his review of the documents in Exhibits A-33 (not

admitted), A-34 and A-37, Mr. Krishnamurthy concluded that Duke Energy Indiana, Inc.

would have received a $0.42 discount for each ton of refined coal; Arthur J. Gallager &

Co. identified an average $0.75 per ton discount; and the offer from A J Gallagher Coal,

Inc, involving Canadys Refined Coal LLC, indicated a $0.50 per ton discount:

In comparison, Detroit Edison’s Monroe Power Plant receives from the Fuels companies a discount (Coal fee Rate) of $1.0375 per ton for the first seven million tons received annually and $1.50 per ton for each ton

199 See 4 Tr 817-818. 200 See 3 Tr 639. 201 See 3 Tr 638.

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received above the seven million ton level. From review of the public documents I described above, I conclude that Detroit Edison negotiated a favorable discount with the Fuels Companies compared to the other utilities mentioned above with their refined coal suppliers.202

After reviewing the record, this PFD finds that it is not possible to compare those

terms to DTE’s REF project. Because those companies are not affiliated with DTE, it is

speculative to consider how the terms of any offers available from those companies

would have compared to the transactions between DTE and the affiliated fuel

companies reviewed in this PFD, which as discussed above do not contractually match

the terms of the agreements as described by DTE. Thus, this PFD concludes that DTE

has not established that its transactions mirror other REF transactions negotiated by or

available to other utilities.

M. Code of Conduct

MCAAA and MEC/NRDC also challenge these transactions under the Code of

Conduct, focusing principally on the fuel transactions and the coal handling and

consulting agreement. The Code of Conduct adopted by the Commission’s October 29,

2001 order in Case No. U-12134 provides in section II.B that “[an] electric utility’s or

alternative electric supplier’s regulated services shall not subsidize in any manner,

directly or indirectly, the business of its affiliates or other separate entities.” It also

provides in section III.C:

If an electric utility or alternative electric supplier offering regulated service in Michigan provides services, products, or property to any affiliate or other entity within the existing corporate structure, compensation shall be based upon the higher of fully allocated embedded cost or market price. If an affiliate or other entity within the existing corporate structure provides services, products, or property to an electric utility or alternative electric

202 See 3 Tr 647.

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supplier offering regulated service in Michigan, compensation shall be at the lower of market price of 10% over fully allocated embedded cost and transfers of assets shall be based upon the lower of fully allocated embedded cost or market price.

MEC/NRDC cites these provisions in its brief at page 84. MEC/NRDC also cites the

following portion of the Affiliate Transaction Guidelines adopted by DTE in Case No.

U-13502:

Asset transfers from regulated to non-regulated shall be at the higher of cost or fair market value and nonregulated to regulated shall be at the lower of cost or fair market value. All services and suppliers provided by nonregulated enterprises shall be at market price or 10% over fully allocated cost, whichever is less.

Noting the time lags DTE identified between the time of its sale to the fuel

companies and its purchase of refined or unrefined coal, MEC/NRDC argues that DTE’s

sale of feedstock coal to the affiliates without regard to the market price at the time of

the sale, as well as the purchase of REF and resold coal from DTE without regard to the

market price at the time of the purchase, violate the Code of Conduct and affiliate

transaction guidelines.203 MCAAA also argues that a significant time difference

precludes the simultaneous estimate of market prices in determining compliance with

the Code of Conduct:

The record strongly suggests that the market price for coal at St. Clair, Michigan, is or should be regarded as being higher that DECo’s costs and thus the sale of DECo coal inventories to the fuel company affiliates at DECo’s costs underprices the revenues DECo should receive for these sales. The problem is compounded by the fact that the Fuel Companies will sell the coal back to DECo at a profit (while important tax credit benefits are captured by the fuel companies or their third party investors and not DECo).204

203 See MEC/NRDC brief, ages 88-90. 204 See MCAAA brief, page 60.

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DTE argues that Mr. Krishnamurthy’s Exhibit A-23 establishes that the REF

project complies with the Code of Conduct, arguing there is structural separation

between DTE and the fuels companies; there is no preferential treatment or

subsidization. Mr. Krishnamurthy testified:

Shipments of coal for consumption at BRPP and SCPP will be sold at Detroit Edison’s MERC transshipment facility. All rail shipments of coal for consumption at MPP will be sold FOB mine and all vessel delivered western coal for consumption at MPP will be sold FOB vessel at Detroit Edison’s MERC facility. Notwithstanding these sales, the coal always remains under the supervision and control of Detroit Edison and MERC . . . and Detroit Edison’s and MERC’s books and records are maintained separately from the Fuels Companies. Most importantly, Section III.C of the Code of Conduct, as approved in the Commission’s October 29, 2001 Order on Rehearing in Case No. U-12134, provides for sales to affiliates at the higher of fully allocated cost or market price. With respect to fully allocated cost, the price at which Detroit Edison is selling the coal is equal to Detroit Edison’s fully allocated cost, or booked cost. The Fuels Companies will simply use the coal to produce REF and sell the REF back to Detroit Edison for consumption at the BRPP, SCPP and MPP and any adjustments to the sale price to reflect any higher market pricing would only serve to increase the resale price to Detroit Edison. Since the asymmetrical pricing provision of the Code of Conduct is intended to prevent Detroit Edison from subsidizing its unregulated affiliates, it is clear this transaction is consistent with that intent and effectuates the proper outcome. 205

DTE further argues in its reply brief that the Commission found compliance with

the Code of Conduct in Case No. U-16892, and neither MEC/NRDC nor MCAAA has

presented any new material evidence that was not previously presented in that case.

DTE asserts that the Code of Conduct is not intended to apply to the sale of identical

assets, and the Commission has already accepted its argument that the Code of

Conduct is complied with because the transactions take place at the identical price.

DTE quotes the Commission’s decision, including the following language:

205 See 3 Tr 618-619.

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Based on the evidence presented in Exhibits A-21 and A-23, the Commission finds that the REF project complies with the Code of Conduct. There is structural separation between the company and its affiliated fuels companies; they do not engage in joint advertising, marketing, or other promotional activities related to the provision of the fuels processing service; and there is no preferential treatment for or subsidization of the affiliated fuels companies by Detroit Edison. The Commission finds that Detroit Edison has complied with Section III.C of the Code of Conduct. As discussed previously, the record supports that Detroit Edison purchases coal from a third party at market price, then sells the coal at the same market price to its affiliated fuels companies. The cost of the coal for the affiliated fuels companies is Detroit Edison’s booked cost, or its fully allocated embedded cost. Therefore, both the market cost and the fully allocated embedded cost are the same in this case. Because neither the market price nor the fully allocated embedded cost is higher than the other, the compensation to Detroit Edison by the affiliated fuels companies complies with section III.C of the Code of Conduct. When the affiliates resell the treated coal to Detroit Edison, it is for the same market price the affiliated fuels companies paid to the company (or in this case, the fully allocated embedded cost), plus the cost of the REF added. The price of the treated coal is offset by the corresponding savings in PSCR emissions allowance expense, resulting in zero cost for the treated coal. Under section III.C of the code of Conduct, compensation to the affiliated companies by Detroit Edison for the treated coal must be the lower of market price of 10% over fully allocated embedded cost. Because market price and the fully allocated embedded cost are the same in this case, the Commission finds that market price is lower than 10% over the fully allocated embedded cost. By paying the affiliated fuels companies market price for the treated coal, Detroit Edison has complied with section III.C of the Code of Conduct.206

In finding compliance with the code of Conduct, the Commission relied on DTE’s

characterization of the transactions, including its assertion that it sells coal to the fuel

companies and repurchases coal from the fuel companies at the same price. But as

discussed above, the fuel companies are not contractually required to simply buy and

206 See June 28, 2013 order, Case No. U-16892, pages 32-33, cited in DTE’s reply brief, pages 39-40 (emphasis omitted).

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sell coal at the same price, subject only to the Refined Coal Adder or the Coal Fee

Rate. Thus, DTE’s premise for ignoring the code of conduct is faulty.

Reviewing the issue in light of the contracts DTE negotiated, DTE has not

established that these transactions comply with the code of conduct. Although the

transactions are complex, in part because they were structured to assist the fuel

companies in taking advantage of the tax credits, the essence of the transactions can

be distilled to DTE’s purchase of a coal refining service from the affiliated fuel

companies. As such, the Code of Conduct requires that DTE pay its affiliates the lesser

of market price of 10% above fully allocated cost. Assuming DTE is correct that it could

not have obtained a greater discount from any other company than the discount it

receives from MFC, making this a “market” price, there is no evidence on this record

regarding the fully allocated cost to the fuel companies of providing the service.

Likewise, regarding the coal handling and consulting agreements, no study was

presented to establish that the services DTE was providing matched its fees. As

MEC/NRDC argues:

[T]he Fuels Companies pay DTE Electric to perform all of the activities that it “has always performed” related to acquiring and storing the coal consumed by DTE electric power plants. As Mr. Krishnamurthy stated in his direct testimony, all of these services are provided by DTE Electric to the Fuels Companies “at cost.” Section III(c) of the Code of Conduct, however, requires regulated Michigan utilities to sell such services (at least when the buyer is an unregulated affiliate like the Fuels Companies) at the higher of the seller’s “fully allocated embedded cost” or “market price.” Because there is no evidence in the record that DTE Electric has performed any study or analysis to identify the market price of its coal handling and consulting services, it is impossible to know whether this transaction actually complies with the Code of Conduct.”207

207 See MEC/NRDC brief, page 86.

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For Belle River and St. Clair, because the coal handling and consulting fees are

not PSCR costs, other than assuring that these costs are not included in the inventory

prices of the fuel companies, it is not necessary to determine whether DTE’s failure to

establish any basis for its cost estimates violates the Code of Conduct. Nonetheless,

because these transactions are squarely before the Commission in this case, and

because they have a potential impact on the price DTE pays for coal, it is appropriate to

consider them in this case. Mr. Krishnamurthy testified:

The Coal Handling and Consulting Agreements provide that Detroit Edison will, in exchange for a fee, perform all functions related to the delivery of coal to the BRPP and SCPP. These functions, which Detroit Edison has always performed, cover all fuel procurement, fuel processing and fuel handling activities including consumption forecasting, specification of coal quality, coal purchasing, coal transportation, coal shipment scheduling, receiving and unloading of coal, coal sampling and analysis, coal stockpile management and maintenance, etc.

* * * Coal handling and consulting services are provided by Detroit Edison at cost to the Fuel Companies to support the processing and delivery of REF to the Belle River and St. Clair Power Plants. The rationale for providing these services at cost is that these services are only supporting the provision of REF feedstock coal to the Belle River and St. Clair Power Plants and these same costs eventually flow back to Detroit Edison. In other words, the costs of these services are a zero-sum proposition with costs charged to the Fuels Companies ultimately flowing back to Detroit Edison as REF is purchased.208

In the Monroe agreements as amended, there is no pretense that the coal

handling and consulting services are provided at cost. Mr. Krishnamurthy testified:

The coal handling and consulting services will be provided by Detroit Edison to the MFC to support the processing and delivery of REF to the Monroe Power Plant. These functions, which Detroit Edison has always performed, cover all fuel procurement, fuel processing and fuel handling activities including consumption forecasting, specification of coal quantity, coal purchasing, coal transportation, coal shipment scheduling, receiving

208 See 3 Tr 624.

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and unloading of coal, coal sampling and analysis, coal stockpile management and maintenance, etc. As stated previously, the MFC will pay a Coal Fee Rate for these coal handling and consulting services. The forecasted PSCR savings from the Coal Fee Rate is shown on line 5 of Exhibit A-20.209

After agreeing to include the “Coal Fee Rate” in the Coal Handling and Consulting

Agreement in lieu of the discount originally included in the Refined Coal Supply

Agreement, and eliminating the “Coal Fee” initially included in the Coal Handling and

Consulting Agreement, DTE allocates the “Coal Fee Rate” between PSCR and

incremental O & M expenses without regard to the Code of Conduct and without a

supporting study. Because the proper allocation of the Coal Fee Rate to incremental

O & M determines the amount credited to PSCR costs as a discount, it is clearly

germane to the PSCR proceeding to consider this.

This PFD finds that DTE has not established that its transactions comply with the

Code of Conduct, and recommends that the Commission establish an expectation that

utilities engaging in transactions with their unregulated affiliates will routinely perform

analyses of both the market price and fully allocated cost of the products or services

prior to entering into the transactions.

MEC/NRDC and MCAAA also challenge other aspects of the REF project,

including what Mr. Sansoucy refers to as the “incubation” of future fuels companies,210

but this PFD finds that these considerations are beyond the scope of this PSCR case.

209 See 3 Tr 630. 210 See 2 Tr 398.

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N. Summary Based on this analysis, this PFD recommends that the Commission find that DTE

has not established that the REF project is reasonable and prudent and consistent with

its obligations under Act 304 to minimize the cost of fuel. Because the agreements do

not limit the purchase prices DTE pays the fuel companies for coal to prices reflecting

the best contract and spot prices DTE could obtain, they are inconsistent with DTE’s

statutory obligations. Correspondingly, DTE has not established that benefits of the

agreement outweigh the potential costs, including the potential transfer of inventory

financing costs to PSCR rates, and the complexity of auditing the interrelated

transactions. Additionally, this PFD concludes that DTE has not established that the

REF project complies with the Code of Conduct, because the premise on which it

sought and obtained Commission approval in Case No. U-16892-- that DTE sold and

repurchased coal from the affiliated fuel companies at the same price, subject only to

the Refined Coal Adder or Coal Fee Rate for refined coal—is not consistent with the

contracts governing the transactions.

VI.

CONCLUSION

Based on the foregoing discussion, this PFD recommends that the Commission

adopt the findings, conclusions, and recommendations set forth above, including the

following findings and recommendations:

1. As explained in section III, DTE’s forecast of generation and purchased power

requirements should be accepted, but the Commission should caution DTE that it

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should support its PROMOD forecast in future plan cases with a more comprehensive

discussion of the inputs, as well as an evaluation of the reasonableness of the

projections.

2. As explained in section IV, DTE did not establish that its plan to install ACI

and DSI systems at River Rouge 2 and 3, St. Clair 7, and Trenton Channel 9 is

reasonable and prudent, given that in DTE’s 2012 PSCR plan case, the company was

contemplating retiring these units, and given the limitations of its analysis in Exhibit

MEC-10. The Commission should caution DTE that it should undertake a more

comprehensive analysis prior to finalizing a decision whether to make these

installations.

3. As explained in section V, a review of the transactions underlying DTE’s REF

project shows that it is not reasonable and prudent and should not be approved.

MICHIGAN ADMINISTRATIVE HEARING SERVICES For the Michigan Public Service Commission _____________________________________ Sharon L. Feldman Administrative Law Judge

Issued and Served: 11/08/2013 drr