## Resource Insight, Inc.



# The Cost of Clean Air

Effects of Air-Pollution Controls on Electric Rates in North Dakota and Minnesota

Paul Chernick

November 7, 2011

# Contents

CONTENTS .......................................................................................... I

SUMMARY...........................................................................................3

MILTON R. YOUNG PLANT BACKGROUND.................................5 Milton R. Young Plant..............................................................................5 Purchasers of Young Power......................................................................7



## MILTON R. YOUNG PLANT ANALYSIS ..........................................8

Cost of State-Plan Measures.....................................................................8 Capital Costs.......................................................................................8 State-Plan-Measure O&M ................................................................10 Carrying Charges..............................................................................10 Annual Costs .................................................................................... 11 Incremental Cost of Selective Catalytic Reduction................................ 11 Capital Costs.....................................................................................12 Operating Costs ................................................................................12 Annualized Capital Cost...................................................................12 Total Annualized Costs.....................................................................13
Rate Increases.........................................................................................13 Minnkota Member Co-ops ...............................................................13 Minnesota Power..............................................................................14

The Cost of Clean Air • Resource Insight, Inc. iContents

The Cost of Clean Air • Resource Insight, Inc. ii 

## LELAND OLDS PLAN T BACKGROUND.......................................16

Leland Olds Plant ...................................................................................16 Ownership...............................................................................................17



## LELAND OLDS PLANT ANALYSIS................................................21 Cost of the State Implementation Plan ...................................................21 Cost of Selective Catalytic Reduc tion for Leland Olds Unit 2 ..............21 Capital Costs.....................................................................................22 Annualized Capital Cost...................................................................22 Operating Costs ................................................................................22 Total Annualized Costs.....................................................................22 Cost per MWh of Basin Sales to Members ............................................23 Costs of State-Plan Measures ...........................................................23
Net SCR Costs..................................................................................23
Rate Increase for North Dakot a and Minnesota Co-ops.........................23 Co-op Power Supply.........................................................................23 Line Losses.......................................................................................25 Co-op Average Rates ........................................................................26
Rate Increases...................................................................................28



## WORKS CITED..................................................................................29

ABBREVIATIONS AND ACRONYMS ............................................33

# Summary

Pollution-control equipment proposed by the Environmental Protection Agency to reduce harmful pollutants from two li gnite-fired power plants will have varying effects on electric rates in pa rts of Minnesota and North Dakota. The size of the rate increase depends on the degree to which customers depend on power from the affected power plants.
Consensus

State Plan Proposed EPA Total Proposed as Share of Total Basin Electric Co-ops 3.1% 0.7% 3.8% less than one fifth Minnkota Co-ops 16.2% 10.3% 26.5% less than two fifths Minnesota Electric 1.2% 0.6% 2.0% about a third


### The rate increase associated with pollution-control equipment proposed by the
EPA 

### is smaller than that of the meas ures proposed by plant operators and required by North Dakota in it s State Implementation Plan. Other equipment proposed by the EPA 

### would not add to rates until it enters service in 2017, but the rate increases fr om the state-plan measures will be charged to customers by the end of 2012. Some state-plan measures are already installed and being charged to customers today. The rate effect for Basin Electric of pollu tion control at the Leland Olds plant is diluted by purchases from many other sources. By contrast, Minnkota’s member co-ops rely on the Milton R. Young plan t for most of their supply. Minnesota Electric purchases only a small portion of Young’s output and mixes it with power from other sources.
Types of Controls The controls required in the consensus state plan are as follows:

The Cost of Clean Air • Resource Insight, Inc. 3Summary Milton R. Young Plant

The Cost of Clean Air • Resource Insight, Inc. 4 

### • New scrubbers for Olds Units 1 and 2 and Young Unit 1. Formally known

as wet-flue-gas desulfurization, this technology washes sulfur dioxide and other acid gases from power-plant exhaust.

• An upgraded scrubber for Young Unit 2, to incr ease the percentage of sulfur dioxide removed.

• Separated Overfire Air for both Olds units and both Young units. This method directs some of the flue gases back into the combustion process so as to reduce oxygen and suppress the production of oxides of nitrogen.

• Selective Non-Catalytic Reduction for both Olds units and both Young units. This technology mixes ammonia in to the plant exha ust to convert about 30% of the flue-gas oxides of nitrogen into harmless nitrogen gas and
water.
The EPA 

### proposes to require Selective Catalytic Reduction for Olds Unit 2 andYoung Units 1 and 2 in place of North Dakota’s proposal for Selective NonCatalytic Reduction. This technology directs the ammonia-exhaust mixture through a catalyst (similar to the catalytic converters on cars) to eliminate about 90% of the oxides of nitrogen from the flue gas. Once out of the power-plant smokestac k, both sulfur dioxi de and nitrogen oxides condense into fine part icles that penetrate deep into the lungs, cause respiratory diseases, aggravate cardiovascular disease, and form visible haze. When they wash out of the air, these pollutants form acids—sulfuric, nitric, and nitrous—that damage property and acidify lakes, rivers, streams, and soils. In addition, oxides of nitrogen react with other atmospheric pollutants to form smog and ground-level ozone, which have multiple effects on health and visibility.
Scope of Research This report summarizes the capital and operating costs of each of the clean-air measures, computes the annual cost for each plant, determines the portion of those costs paid by the North Dakota and Minnesota electric co-operatives and Minnesota Power, and computes the percentage rate effects. 1 

### The analyses areconducted separately for Olds and Young, and within each plant, for the staterequired measures and those proposed by the EPA



### .

1 

### Because of the differences between Minnkota (which ser ves 11 co-ops, all in Minnesota and North Dakota) and Basin (which directly or indirectly serves some po rtion of the generation requirement for 135 co-ops in nine states), some steps in the analysis differ between the two co-ops.

# Milton R. Young Plant Background

Milton R. Young Plant
Milton R. Young consists of two lignite-f ired units located in Center, North Dakota. Both units are powered by cycl one boilers burning crushed coal. The operating capacities are 277 MW for Unit 1 and 517 MW for Unit 2. (76 FR 58596). Cyclone boilers produce much grea ter amount of oxide s of nitrogen (NO x 

### ) than do other designs. Young Unit 1 is 100% owned by Minnkota Power Co-operative, Inc. YoungUnit 2 is operated by Minnkota, but owned by Square Butte Electric Cooperative, which was formed to own th at unit and associated transmission. Both units have electrostatic precipitators that remove more than 99% of particulate matter from the flue gas. Un it 2 has a wet flue-gas desulfurization system (or “scrubber”) for control of sulfur dioxide (SO 2 

### ), while Unit 1 has no SO 2 

### controls. Neither unit has any post- combustion controls for oxides of nitrogen (NO x 

### ). (Minnkota 2006, 2, ES-2.) In October 2006 (with a supplementary filing in August 2007), Minnkota proposed the following steps to co mply with Regional Haze rules:

• using the existing electrostatic precip itators to reduce particulate-matter emissions for both units,

• upgrading the existing scr ubber on Unit 2 (including installation of a new larger stack) and installing a wet scrubber on Unit 1 to reduce sulfur emissions,

The Cost of Clean Air • Resource Insight, Inc. 5Milton R. Young Plant Backgr ound Milton R. Young Plant



### • retrofitting the combustion area of each unit with Advanced Separated Overfire Air ( ASOFA 

### ) to reduce NO x 

### formation and adding selective noncatalytic reduction ( SNCR 

### ) to the flue-gas system to break down some of the NO x 

### emissions.
The scrubber addition and upgrade and the reduction of NO x 

### by at least 40% are required by an April 200 6 settlement with the EPA 

### , regarding violation of newsource-review requirements ( EPA 

### 2006). The ASOFA 

### systems were installed at Unit 1 in 2009 and Unit 2 in 2007, and SNCR 

### was installed at Unit 1 in 2010 and Unit 2 in early 2011. Unit 2’s scrubbe r was upgraded in 2010 and Unit-1’s was installed in April 2011. (Square Butt e 2011, 7–8; North Star 2010, 6; 76 FR 58589–58590.) In February 2010, the North Dakota Depa rtment of Health accepted Basin’s proposed technologies as part of its St ate Implementation Plan, while requiring lower emission rates from the scrubbers. The Department found that a higher level of NO x 

### control was technically feasible using selective catalytic reduction ( SCR 

### ), but that the incremental emission reduction was not cost-effective. In September 2011, the U.S. EPA 

### accepted the Department’s determinations for SO 2 

### and particulates on bo th units, but found that SCR 

### would be cost-effective in controlling NO x 

### emissions and thus proposed to require SCR



### . The measures to bring Milton R. Y oung into compliance with the Regional Haze Rule thus fall into the following two groups:
1. the following costs of the consensus state-plan measures, agreed to by Minnkota and essentially all completed:

• the new Unit-1 scrubber,

• the upgrades to the Unit-2 scrubber,

• the ASOFA 

### and SNCR 

### at both units;
2. the incremental cost of the SCR



### . 2

2 

### Addition of SCR 

### would eliminate the need to operate the SNCR 

### system.

The Cost of Clean Air • Resource Insight, Inc. 6Milton R. Young Plant Background Purchasers of Young Power

The Cost of Clean Air • Resource Insight, Inc. 7 

# Purchasers of Young Power
Minnkota Power and Square Butte are ge neration-and-transmission (G&T) cooperatives, owned by 11 member distribution co-ops in North Dakota and Minnesota. Those co-ops are listed in Table 1

. Table 1: Minnkota Power Member Co-ops Beltrami Electric Co-operative PKM Electric Co-operative Cass County Electric Co-operative Red Lake Electric Co-operative Cavalier Rural Electric Co-operative Red River Valley Co-operative Power Clearwater-Polk Electric Co-operative Roseau Electric Co-operative Nodak Electric Co-operative Wild Rice Electric Co-operative North Star Electric Co-operative 

### Minnkota provides generation-and-transmissi on services to its members, at a uniform contract rate for all its Class A members of $52.99/MWh in 2010 (Minnkota 2011, 11). Under a long-term contract, 50% of the output of Young 2 issold to Minnkota and 50% to Minnesota Power, an investorowned utility headquartered in Duluth, Minnesota. Square Butte has recently sold to Minnesota Power the transmission line from Young to Duluth to allow Minnesota Power to import additional wind energy. As part of that transa ction, Minnesota Power’s share of the output from Young 2 will gradually be transferred to Minnkota, ove r the period 2013–2026, in the pattern shown in Table 2



### . Minnkota (2011a, 3) expects “a positive financial impact” from the acquisition of additional Young-2 capacity. Table 2: Transfer of Minnesota Power’s Share of Young 2 to Minnkota Incremental percent Cumulative percent 2013 17% 17% 2014 5% 23% 2015 5% 28% 2016 28% 2017 28% 2018 28% 2019 28% 2020 28% 2021 28% 2022 4% 32% 2023 4% 37% 2024 4% 41% 2025 4% 46% 2026 4% 50% Source: Tschepen 2010, 21

# Milton R. Young Plant Analysis

Cost of State-Plan Measures

The environmental retrofits to which Minnkota has already agreed, and which are to be completed by 2012, include the installation of the Unit 1 scrubber, the upgrade of the Unit 2 scrubber, and ASOFA 

### and SNCR 

### to control NO x 

### on both units. Minnkota’s (2006) estimate of the costs of these is reproduced in Table 3



### . The installed cost of these meas ures is approximately $177 million. Capital Costs

Recent estimates of environmental costs at Young have been considerably higher than those of Minnkota (2006). For example, the manager of the Red LakeElectric Co-operative, Roger Johanneck (2010, 2), describing “the investments in pollution c ontrol equipment,” writes of “the $360 million that Minnkota is investing in its Young 1 and Young 2 generating plants.”
Of the scrubber and NO x 

### -control measures Minnkota (2011, 2) reports, “In total, for Young 1 and Young 2, in excess of $425 million will be spent on this emission control equipment by the e nd of 2011.” Square Butte (2011, 7) further breaks down the capital costs to $260 million for the scrubbers and $30 million for NO x 

### controls. The reported NO x 

### costs are simila r to the sum of those estimated by Minnkota (2006) (which add to about $27 million in insta llation-year dollars), but th e scrubber costs reported by Square Butte (2011) are some $110 m illion more than those, adjusted for inflation. Table 3: Cost of Controls from Minnkota (2006) (Millions of Dollars) Capital

Measure 2006 Dollars Year installed Install-Yr Dollars Unit 1

Wet FGD $111.8 2011 $123.4 ASOFA $4.3 2009 $4.5 SNCR $3.8 2010 $4.2 Total $132.1 Unit 2

Wet FGD $25.0 2010 $27.0 ASOFA $10.0 2007 $10.2 SNCR $7.1 2011 $7.9 Total $45.1 Total Plant $177.2 Costs inflated from 2006 at 2%. Sources: Burns & McDonnell 2006a, 3-22; 2006b, 3-22; Minnkota 2007, 3-7, 3-20

The Cost of Clean Air • Resource Insight, Inc. 8Milton R. Young Plant Analysis Cost of State-Plan Measures



### The $425-million total cost estimate includes $130 million of “electrical improvements” including “new auxili ary transformers...ne w breakers, wiring and switchgear” (North Star 2010, 6). Square Butte (2010, 7) elaborates: Additional infrastructure to support th e emission control equipment required a major electrical system overhaul. New auxiliary transformers were installed, as well as new breakers, wiring and switchgear on Young 2 during the [2010] outage. 

### It is not clear whether these improvement s were required solely for the environmental improvements. The sum of $260 million for the scrubbers, $30 million for NO x 

### , and $130 million for electrical upgrades is $420 million. The nature of the other $5 million in costs is not specified in any of the sources we have seen. For the purpose of this analysis, wedistribute the $110 million in undesignated scrubber costs proportionately over the cost estimates from Minnkota (2006), resulting in scrubber costs of $213 million for Unit 1and $47 million for Unit 2. We similarly increase Minnkota’s estimates for NO x 

### controls by about 10% to total $30 million, about $10 million for Unit 1 and $20 million for Unit 2. We allocate the $130 million of electrical improvements, and the $5 million in unspecified costs between the two units in proportion to the scrubber and NO x 

### costs. See Table 4

. Table 4: Capital Costs of the State Implementation Plan (Millions of Dollars)

Measure Estimate a from a Minnkota a (2006) a Normalized b to Reported b Total b Control b Capital b Allocation c of c Electrical c Upgrades c Total d Allocated d Cost d Unit 1

FGD $123.4 a $213.3 b $99.3 c $312.5 d ASOFA $4.5 a $5.1 b $2.4 c $7.5 d SNCR $4.2 a $4.7 b $2.2 c $6.8 d Total $132.1 a $223.0 b $103.8 c $326.8 d Unit 2 B

FGD $27.0 a $46.7 b $21.8 c $68.5 d ASOFA $10.2 a $11.4 b $5.3 c $16.8 d SNCR $7.9 a $8.8 b $4.1 c $12.9 d Total $45.1 a $67.0 b $31.2 c $98.2 d Young Plant Total

FGD $150.5 a $260.0 b $121.0 c $381.0 d ASOFA + SNCR $26.8 a $30.0 b $14.0 c $44.0 d

Total $177.2 a $290.0 b $135.0 c $425.0 d

a Table 3
, above
b For flue-gas desulfurization (FGD), t he estimate from Minnkota (2006) is

normalized by multiplying it by the capital costs for the scrubbers ($260 million, per Square Butte 2011, 7) an d dividing that by the Minnkota’s estimate of the same costs ($150.5 million). Minnkota’s ASOFA and SNCR costs are normalized by multiplying them by our revised estimate from Minnkota ($30 million) divided by Minnkota’s original estimate ($26.8 million)

c The $153 million in electrical-upgrade costs are allocated by multiplying

them by the total for each type of control (i.e., FGD, ASOFA + SNCR) and dividing that by the total for all controls ($290 million).
d Sum of normalized capital costs plus electrical upgrades

The Cost of Clean Air • Resource Insight, Inc. 9Milton R. Young Plant Analysis Cost of State-Plan Measures



### In additional to capital costs, the stat e-plan measures will increase operation and maintenance (O&M) costs at Young. Minnkota provides estimates of the O&M costs for the wet scrubbers, ASOFA 

### and SNCR 

### ( Burns & McDonnell 2006a 3-23, 2006b 3-23). 3 

### The Young O&M data for 2010, from various sources, are provided in Table 5

.State-PlanMeasure O&M

Table 5: O&M Costs of Measures Agreed To Under the State Implementation Plan (Millions of Dollars) Measure O&M Total O&M Measure 2006$ a 2012$ b 2010 c Est 2012 d State-Plan O&M e as % total e Young Unit 1 FGD $10.3 a $11.6 b ASOFA $1.7 a $1.9 b SNCR $3.7 a $4.2 b Total $15.7 a $17.7 b $14.0 c $30.4 d 58% e Young Unit 2 FGD $5.0 a $5.6 b ASOFA $2.8 a $3.2 b SNCR $5.1 a $5.8 b Total $12.9 a $14.6 b $37.8 c $50.7 d 29% e

a Burns & McDonnell 2006a 3-23, 2006b 3-23; Minnkota 2007, 3-12, 3-21
b 2006 dollars × 1.026.

c Computed from Minnkota 2011, 1
d 2010 O&M × 1.022 + 2012-dollar O&M for FGD and SNCR. (ASOFA was included in 2010 O&M.)

e 2012-dollar O&M ÷ total O&M estimated for 2012.


### Minnkota’s embedded cost of debt is a bout 2.6% ($11 million in interest payments on $420 million in long-term debt, per Minnkota 2011, 18–19). In 2010, “Minnkota borrowed $126.4 million from [the Rural Utility Service] at longterm rates between 3.3 percent and 4.4 percent” (Minnkota 2011, 11). Burns & McDonnell (2006a, 3-24, C1-1; 2006b, 3-24, C1-1) assumes 20-year lives for the SCR 

### systems, and the EPA 

### (76 FR 58589) assumes rema ining lives of at least 20 years for Young 1 and 2. Rouseau Electri c (2011, 1) projects, “The upgrades will allow the Young Station to be our primary source of generation, likely until at least 2042;” and Square Butte’s Si gurdson & Loer say they “are confident that [Young Unit 2] is now well positioned for the generation of electric energy for its customers well into the future, perhaps as long as the year 2042,” implying a life of about 30 years. Carrying Charges

3 

### These estimates of O&M cost are stated in levelized no minal dollars over the life of the equipment, and thus include a multiplier for inflation in the O&M costs. Our analysis is specific to 2012 rate effects, and thus does not require a levelization adjustment.

The Cost of Clean Air • Resource Insight, Inc. 10Milton R. Young Plant Analysis Incremental Cost of Selective Catalytic Reduction



### With a 4% cost of capital (toward th e high end of the recent range) and a 20- year cost-recovery period (at the low end on the possible useful lives), the annual cost-recovery factor would be 7.36% of the initial investment, and the incremental annual capital recovery for th e state-plan measures would be $425 × 7.36%, which equals $31.3 million. The annual costs by unit for 2012 are the sum of 2012 O&M and the levelized capital recovery. See Table 6

. Annual Costs

Of these 2012 costs the Unit-1 costs and half the Unit-2 costs, about $52.6 million, would be paid byMinnkota. This value is considerably greater than predicted by Minnkota (2011b, 8): Table 6: Annual Costs for State-Plan Measures

Measure Total a Allocated a Cost a Annual b Capital b Cost b Recovery b 2012 c O&M c Annual d Costs d Unit 1 FGD $312.5 a $23.0 b $11.6 c $34.6 d ASOFA $7.5 a $0.5 b $1.9 c $2.5 d SNCR $6.8 a $0.5 b $4.2 c $4.7 d Total $326.8 a $24.0 b $17.7 c $41.7 d Unit 2 FGD $68.5 a $5.0 b $5.6 c $10.7 d ASOFA $16.8 a $1.2 b $3.2 c $4.4 d SNCR $12.9 a $1.0 b $5.8 c $6.7 d Total $98.2 a $7.2 b $14.6 c $21.8 d

a From Table 4
, above

. b Total allocated costs × 7.36% annual cost-recovery factor

c From Table 5
, above

. b Sum of annual capital costs and O&M costs 

### In the near term, capital investments and operating and maintenance cost increases haveadded significant upward pressure to Minnkota’s wholesale rate. The annual cost of the environmental control additions will b e abou t $35 million. 1 

### The remaining $10.9 million would be paid by Minnesota Power.



# Incremental Cost of Selective Catalytic Reduction

The EPA 

### rejected two of the Department’s conclusions regarding the application of SCR 

### on Young, finding instead (1) that that Young was large enough to be covered by federal requirements to use be st-available reduction technology and (2) that the NDDH 

### ’s analysis (2010a) (based on Minnkota 2006) had overestimated the cost of SCR 

### . Since both the Department and the EPA 

### consider SCR 

### to be technically feasible for the Young units, and since the EPA 

### found the cost of SCR 

### to be reasonable, EPA 

### proposed to require the plant to install SCR 

### within five years of EPA 

### ’s final rulemaking on the State’s proposed plan, which is by 2017.

The Cost of Clean Air • Resource Insight, Inc. 11Milton R. Young Plant Analysis Incremental Cost of Selective Catalytic Reduction



### The EPA 

### ’s analysis (Fox 2011, 25; 76 FR 58601) found that the capital cost of
SCR 

### would be about $120.6 million for Un it 1 and $216.9 million for Unit 2 (in 2009 dollars). Those are overnig ht costs, expressed as if all the work could be completed in a short period within 2009. Assuming 2% inflation, the comparable overnight cost for comple tion in 2017 would be about $141 million and $254 million, respectively. In addition, the EPA 

### costing methodology does not include interest costs during constr uction, between the time that contractors and suppliers are paid and the time that the project is finished. Minnkota might actually accrue interest on this balance, or it might recover those costs through current rates in 2012–2016. Capital Costs

For the purpose of this analysis, we a ssume that Minnkota w ill capitalize the interest, paying about 4% annual interest on the outstanding balance or about 2% more than the inflation that is al ready included in the overnight costs for 2017. Since the actual period for SCR 

### construction tends to be short, relatively little interest accrues during constructi on. For example, the engineering firm Sargent & Lundy (2010, 3) included in the cost of SCR 

### Allowance for Funds Used During Construction ( AFUDC 

### ) at 6% of the [construction] costs. The AFUDC 

### is based on a two-year engineering and construction cycle. 

### That 6% value may be appropriate for inve stor-owned utilities, but is too high for a co-op like Minnkota, with its low cost of capital. Accruing interest at 2% real interest for two y ears would add about 4% to the cost of the Young SCR



### . This additional item would bring the total capital cost of the SCR 

### systems that would be reflected in 2017 rates to about $147 million and $264 million.
The EPA 

### estimates that average annual O&M for the SCR 

### system in 2009 dollars would be about $11.3 million and $17.8 million for Units 1 and 2, respectively, or about $13 million and $21 million respectively in 2017 dollars (76 FR 58608, 58612) Operating Costs

Installation of the SCR 

### system would avoid th e need to operate the SNCR 

### system; escalating Minnkota’s estimates of that cost to 2017 gives costs for the SNCR 

### of $4.6 million and $6.4 million in 2017. The net O&M for SCR 

### , over what is already in rates, is thus $8.6 million for Unit 1 and $14.5 million for Unit 2. As discussed above, Minnkota’s annual co st-recovery factor for environmental upgrades would be 7.36% of the initial investment, and the incremental annual capital recovery would be $147 milli on × 7.36% = $23.7 million for Unit 1 and $264 million × 7.36% = $41.2 million for Unit 2. Annualized Capital Cost

The Cost of Clean Air • Resource Insight, Inc. 12Milton R. Young Plant Analysis Rate Increases



### The total annualized net SCR 

### costs for 2017, adding the net O&M to the annualized capital cost, would be $3 4.5 million for Unit 1 and $60.6 million for Unit 2. This computation is summarized in Table 7

. Total Annualized Costs Table 7: Calculation of Annual 2017 Cost of Selective Catalytic Reduction Millions of Dollars

SCR 2009 a SCR 2017 SNCR O&M Capital

Costs O&M Costs Capital b Costs b Cap.+ c AFDC c Annual d Capital d O&M e Costs e 2006 f Dollars f 2017 g Dollars g Net h SCR h O&M h 2017 h Dollars h Total i 2017 i Cost i Unit 1 $120.6 $11.3 $141.3 b $147.0 c $10.8 d $13.2 e $3.7 f $4.6 g $8.6 h $19.4 i Unit 2 $216.9 $17.8 $254.1 b $264.3 c $19.4 d $20.9 e $5.1 f $6.4 g $14.5 h $33.9 i

a 76 FR 58601
b 2009 Capital costs × 1.02 8 (8 years of 2% inflation)

c 2017 Capital Costs × 1.04
d “Cap + AFDC” × 7.36%

e 2009 SCR O&M × 1.02 8 (8 years of 2% inflation) f From Table 5 (2006-dollar SCR O&M
g 2017 O&M costs× 1. 02 8 (8 years of 2% inflation)
h 2006-dollar SNCR O&M

− 2017-dollar SNCR O&M
i Sum of 2017 SCR Annual Capital + net SCR O&M



### In 2017, Minnkota will purchase 78% of Y oung-2 output (50% of its long-term entitlement, plus 28% transferred from Minnesota Power) and pay 100% of the costs of Young 1, resulting in the split shown in Table 8 below

. Table 8: Minnkota and Minnesota Power 2017 Net Costs of Selective Catalytic Reduction Cost (Millions) Minnkota

Share Total Minnkota Minn. Power Unit 1 100% $19.4 $19.4 Unit 2 78% $33.9 $26.5 $7.5 Total $53.3 $45.9 $7.5



# Rate Increases
The percentage effect on the electric rates charged by North Dakota and Minnesota distribution co-ops of an increase in Minnkota’ s Class-A revenues depends on the distribution co-ops’ total revenues. Minnkota Member Co-ops Minnkota (2011, 28–29) provides the 2010 revenues of each of its eleven member co-ops; those revenues total $272,074,867 on sales of 3,268 GWh. Minnkota’s rates have increased stea dily from 2002 through 2011, with a $16/MWh increase in 2011. See Table 9



### .

The Cost of Clean Air • Resource Insight, Inc. 13Milton R. Young Plant Analysis Rate Increases



### Minnkota continues to face upward cost pressure from the $300-million, 345-kV transmission line from Center to Grand Forks, the 68-mile Bemidji to Grand Rapids 230-kV line, and distribution substation addition and replacement (Minnkota 2011a, 8–9, 24).

The Joint System Power Requirements Study completed in 2009 projects that energy sales by Minnkota and NMPA 

### will increase at approximately 1.9 percent during the next 25 years. These projections are used to plan future en ergy and capacity resource additions. 

### Minnkota (2011a, 12) also states,

Since Minnkota’s 2010 sales to its Class-A members

were 3,419 GWh, we estimate those sales to be 3,484 GWh in 2011, 3,550 GWh in 2012, and 3,900 GWh in 2017. Table 9: Minnkota Rate to Member Co-ops Annual Increase Dollars per MWh Current Year Average from 2002 2002 a 30.2 2003 a 32.0 6.0% 6.0% 2004 a 34.6 8.1% 7.0% 2005 a 35.8 3.5% 5.8% 2006 b 35.8 0.0% 4.3% 2007 b 38.1 6.3% 4.7% 2008 b 39.8 4.5% 4.7% 2009 b 44.9 12.8% 5.8% 2010 b 53.0 18.0% 7.3% 2011 a 69.0 30.2% 9.6%

a Minnkota 2011b, 3. b Minnkota 2011a, 11



### Increasing each year’s revenue by 1.9% for sales growth, plus $56.8 million in 2011 to reflect Minnkota’s $16/MWh increase and 3% annual increases in rates from 2012 through 2017 (representing a co ntinuation of Minnkota’s historical 5% increases, without any provision for ra te increases to cover the distribution co-ops’ costs), the resulting revenue s are $350.6 million in 2012 and $446.6 million in 2017, without the SCR 

### costs. For 2012, we estimate that retail rates w ould include $52.6 million of state-plan costs in $350.6 million of revenues, or 16.2% of the total. For the proposed SCR 

### in 2017, the additional environmental co sts would be about $45.9 million of
SCR 

### costs in $528.4 million of total revenues, or about 10.3% of the total. Thus, the incremental rate effect of the SCR 

### would be about two-th irds that of stateplan measures. 4 

### Minnesota Power’s share of the annual environmental costs would be $10.9 million in 2012 and $7.5 million from the SCR 

### in 2017. Minnesota Power had regulated utility sales of about $83 4 million in 2010 and was allowed rate increases for 2011 of $54 in Minnesota and $2 million in Wisconsin (Allete 2011, 6, 12, 14), in addition to some auto matic cost flow-through mechanisms. Hence, Minnesota Power’s 2011 revenues would appear to be on the order of Minnesota Power

4 

### Much of these costs are already in rates. Minnkota repo rts that its rates have risen $14 million since 2009 to pay for the costs of running new emissions controls and $17 for debt payments, part of which are also due to the emission controls. For comparison, Minnkota’s rates to its members have increased by $46 million due to lower profits on its market power sales (Minnkota 2011c, 2).

The Cost of Clean Air • Resource Insight, Inc. 14Milton R. Young Plant Analysis Rate Increases

The Cost of Clean Air • Resource Insight, Inc. 15 

### $900 million. Assuming 5% annual increases in revenues (for load growth and rate increases), Minnesota Power’s re venues would be about $935 million in 2012 and $1,195 million in 2017. The rate increases from the environmental upgrades would thus be 1.17% for the 2012 state-plan measures and 0.63% for the 2017 SCR



### .

# Leland Olds Plant Background

Leland Olds Plant
Leland Olds consists of two lignite-f ired units located in Stanton, North Dakota. Unit 1 has a wall-fired, dry-botto m, pulverized-coal-fi red boiler and is rated at 216 MW ( NDDH 

### 2010b, 1). Unit 2 has a cycl one boiler burning crushed coal and is rated at 440 MW ( NDDH 

### 2010b, 2). Cyclone boilers produce more oxides of nitrogen (NO x 

### ) than other designs. Both units are 100% owned by Basin Electric Power Co-operative. Both units have electrostatic precipitators that remove more than 99% of particulate matter from the flue gas. Neither unit has any post-combustion controls for either sulfur dioxide (SO 2 

### ) or oxides of nitrogen (NO x 

### ).In 2006, Basin Electric proposed the following steps to comply with regionalhaze rules:

• use the existing electrostatic precipitators to reduce particulate-matter emissions,

• install a wet flue-gas desulfurization system ( FGD 

### , or “scrubber”) on Unit 2 and a wet scrubber or equivalent on Unit 1 to reduce sulfur emissions,

• retrofit the combustion area of each unit with Separated Overfire Air ( SOFA 

### ) to reduce NO x 

### formation and adding sele ctive non-catalytic reduction ( SNCR 

### ) to the flue-gas system to break down some of the NO x 

### emissions. The scrubber installations are underway, with completion scheduled for 2012. The SOFA 

### system for Unit 2 was installed in November 2009 (Fox 2011, 11).

The Cost of Clean Air • Resource Insight, Inc. 16Leland Olds Plant Background Ownership



### In February 2010, the North Dakota Depa rtment of Health accepted Basin’s proposed technologies as part of its St ate Implementation Plan, while requiring lower emission rates from the electrostatic precipitators, requiring the wet scrubber on Unit 1 (resulting in lowe r emission rates), and accepting the SOFA



### SNCR 

### combination for NO x 

### control. The Department ( NDDH 

### 2010a Appendix B6, 31) found that a higher level of NO x 

### control was technically feasible at Unit 2, using selective ca talytic reduction ( SCR 

### ), but that the incremental emission reduction was not cost-effective. In September 2011, the U.S. EPA 

### accepted the Department’s determinations for SO 2 

### and particulates on both units and NO x 

### on Unit 1, but found that SCR 

### would be cost-effective in controllin g emissions of oxide s of nitrogen (NO x 

### ) at Unit 2, with its higher emissions. The EPA 

### thus proposed to require SCR 

### on Unit 2 (76 FR 58618).


# Ownership
Basin Electric is a generation-and-tran smission (G&T) co-operative, owned by its members, 9 smaller G&T co-ops and 11 distribution co-ops that purchase directly from the Basin Electric genera tion system. Collectively, those members serve 2.8 million customers in 9 states, from Canada to Mexico. The direct purchasers are Class-A members, while the 124 distribution co -ops served by the 9 G&T co-ops are Class-B and -C me mbers. Two of the co-ops in Montana and Wyoming that purchase portions of th e outputs of specific Basin plants are Class-D customers. See Figure 1 . Basin serves 25 co- ops in North Dakota and Minnesota; see Table 10

.

The Cost of Clean Air • Resource Insight, Inc. 17Leland Olds Plant Background Ownership



### Figure 1: Membership Structure of Basin Electric


### Basin Electric Power Cooperative

9 G&T coops (Class A) 11 distribution coops (9 Class B, 2 Class D)

124 distribution coops (Classes B & C) 13 N.D., 12 Minn.

The Cost of Clean Air • Resource Insight, Inc. 18Leland Olds Plant Background Ownership



### Table 10: Basin Electric Member Co-ops in North Dakota and Minnesota, by G&T Co-op and Headquarter State State Distribution Co-operative Served Directly by Basin Electric a

Minn. Crow Wing Power Minn. Minnesota Valley Co-operative Light & Power Association Minn. Minnesota Valley Electric Co-operative Minn. Wright-Hennepin Co-operat ive Electric Association N.D. KEM Electric Co-operative N.D. Mor-Gran-Sou El ectric Co-operative Central Power Electric Co-operative

N.D. Capital Electric Co-operative N.D. Dakota Valley Electric Co-operative N.D. McLean Electric Co-operative N.D. North Central Electric Co-operative N.D. Northern Plains Electric Co-operative N.D. Verendrye Electric Co-operative East River Electric Power Co-operative b Minn. Agralite Electric Co-operative Minn. Lyon-Lincoln Electric Co-operative Minn. Meeker Co-operative Light & Power Association Minn. Redwood Electric Co-operative—Clemens, MN Minn. Renville-Sibley Co-opera tive Power Association Minn. South Central Electric Association Minn. Traverse Electric Co-operative L & O Power Co-operative c

Minn. Federated Rural Electric Association Upper Missouri Generation and. Transmission Electric Co-operative d

N.D. Burke-Divide Electric Co-operative N.D. McKenzie Electric Co-operative N.D. Mountrail-Williams Electric Co-operative N.D. Roughrider Electric Co-operative N.D. Slope Electric Co-operative Note: Basin Electric also serves the following four G&T co-ops that have no members headquartered in North Dakota or Minnesota: Rushmore Electric Power Co-ope rative (8 members in South Dakota), Northwest Power Co-operative (7 in Iowa), Corn Belt Power Co-oper ative (11 in Iowa), and Tri-State Generation and Transmission Association (40 in Colorado, Nebraska, and New Mexico). Finally, Basin has two Class-D members (project-specific purchases) in Montana and Wyoming. Source : Basin Electric 2010, 3

a Basin Electric also serves 3 additional co-ops directly in South Dakota and Wyoming. b The East River Electric Co-operative also serves 18 in South Dakota

c The L& & O Power Co-operative also se rves 3 in Iowa and South Dakota d The Upper Missouri Generation and Transmission Electric Co-operative also serves 5 in Montana 

### Basin Electric is governed by an 11-mem ber board elected by district by the 135 member co-ops. The co-op owns ei ght for-profit and non-profit energy, mining, and telecommunications subsid iaries and operates more than 3,700

The Cost of Clean Air • Resource Insight, Inc. 19Leland Olds Plant Background Ownership

The Cost of Clean Air • Resource Insight, Inc. 20 

### MW of generation with some 850 MW unde r construction. It owns more than 2,000 miles of high-voltage transmi ssion. (Basin Electric 2010 2–9, 20.) Basin Electric provides genera tion and transmission services to its members. In most cases, those are only part of th e generation and transmission resources used by the members. Some members (e specially the G&T co-ops) have additional generation resources, while all the G&T co-ops and the Class-B members own some transmission lines. Basin Electric reports only a single contract rate for all its Class-A members, so it appears that the costs of Leland Olds (and Basin’s other power plants) are spread over all the customers of Basin’s me mbers. It thus appears that the costs of installing environmental controls will be spread over all of Basin Electric’s Class-A members (and through them to the Class-B and -C members).

# Leland Olds Plant Analysis

Cost of the State Implementation Plan

The costs of the environmental retrofits reported by Basin Electric (2006) are summarized in Table 11 below , along with the annual cost of those measures in 2012. Table 11: Leland Olds Cost of State Implementation Plan Measures (Millions of Dollars) Costs in 2005 Dollars a Unit Measure Capital O&M Costs in 2012 ) b Dollars (Total) b Olds 2 Wet FGD $147.6 $14.2 $28.8 ) b SNCR & ASOFA $16.8 $6.6 $9.0 ) b ASOFA $10.1 $0.2 $1.1 ) b Olds 1 Wet FGD $107.2 $8.4 $18.7 ) b SNCR & SOFA $6.2 $1.7 $2.5 ) b SOFA $1.4 $0.03 $0.1 ) b

a Basin Electric 2006, 64, 66, 98, 99, 158,188 b These costs are calculated as follows:

(2005 Capital Costs × 1.02 7 × 7.36%) + (2005 O&M × 1.027). 1.02 7 is 7 years of 2% inflation. 7.36% is a cost-recovery factor based on Basin’s 4% cost of debt over a 20-year cost-recovery period, as discussed below on page 22

. 

# Cost of Selective Catalytic Reduction for Leland Olds Unit 2
The Department ( NHDD 

### 2010, 73) found that SCR 

### would be feasible for Olds Unit 2, but that it would be excessively expensive ( NDDH 

### 2010 Appendix B.1, 16), based on a supplementary analysis by Basin Electric (2007). The EPA 

### found that Basin had overestimated the cost of SCR 

### , and that SCR 

### was cost-effective

The Cost of Clean Air • Resource Insight, Inc. 21Leland Olds Plant Analysis Cost of Selectiv e Catalytic Reduction for Leland Olds Unit 2



### (76 FR 58619). The SCR 

### would be required within five years of the EPA 

### ’s final rulemaking on the State Implementation Plan (by 2017).
The EPA 

### (76 FR 58617) found that the capital cost of SCR 

### Olds Unit 2 would be approximately $154 million in 2009 dollars . This is about $180 million in 2017 dollars, assuming 2% inflation. This estim ate is close to the $159 million estimate (in 2009 dollars) prepared for Basin Electric by Sargent & Lundy (DePriest 2009, 10). Capital Costs

Installation of the SCR 

### system would avoi d the need for the SNCR 

### system, which Basin Electric (2006, 98) estimates would have a capital cost of $6.7 million in 2005 dollars, or about $8.5 million in 2017 dollars. The EPA 

### (76 FR 58614) assumes this would cost $7.8 million in 2009 dollars, which is about $9.1 million in 2017 dollars. The capital cost of the SCR 

### system, net of the EPA 

### ’s estimate of the SNCR 

### capital cost, would thus be about $171 million. 5 

### Basin Electric’s cost of debt ( 2010, 39) is about 4%. The utility, the Department, and the EPA 

### all assume 20-year lives for the SCR 

### system. With this cost of capital and cost-recovery period, the annual cost recovery factor would be 7.36% of the initial inve stment, and the incrementa l annual capital recovery would be $171 × 7.36%, which equals $12.6 million. 6 

### Annualized Capital Cost

The EPA 

### (76 FR 58618) estimates that average annual O&M for the SCR 

### system would be about $7.7 million in 2009 dolla rs, or $9.1 million in 2017 dollars. Operating Costs Basin Electric (2006, 99) estimates that SNCR 

### would have O&M of $6.4 million in 2005 dollars, or about $8.3 million in 2017 dollars. The EPA 

### (76 FR 58614) assumes this would cost $3 million in 2009 dollars, about $3.5 million in 2017 dollars. Using the EPA 

### ’s estimate, the net annual O&M cost of SCR 

### net of SNCR 

### would be $5.6 million in 2017 dollars.
The total annualized net costs for the SCR 

### system would thus be $12.6 + $5.6 = $18.2 million in 2017. This would be less than a third of the roughly $59 million that are expected by 2012 for the Olds environmental equipment required under the State Implementation Plan. Total Annualized Costs

5 

### While these capital-cost estimates are quite clo se to one another, Basin Electric’s estimate of SNCR 

### O&M is greater than the EPA 

### ’s. Thus, netting the EPA 

### estimate of SNCR 

### cost from the EPA 

### estimate of SCR 

### cost is internally consistent. It is also conservative, in that it results in a higher net cost of SCR 

### than using Basin Electric’s estimate.

6 

### Because this estimate is specific to 2012 rate effect s, it does not include a multiplier for inflation in the O&M costs. Basin Electric’s levelized cost estimate (2006, 99) adds an in flation multiplier because it is stated in levelized nominal dollars over the life of the equipment.

The Cost of Clean Air • Resource Insight, Inc. 22Leland Olds Plant Analysis Cost per MWh of Basin Sales to Members


# Cost per MWh of Basin Sales to Members
Basin Electric (2010, 7) reports that its 2010 sales to members totaled 16,500,000 MWh. 7 

### Basin Electric (2011) also repo rts that its 2011 load forecast projects an average annual growth ra te of 3% through 2025. Specific forecasts for individual years are not readily av ailable. However, if sales to Basin Electric rise at 3% annually fr om 2010 to 2012, they would be 17,500,000 MWh in 2012.Costs of StatePlan Measures

Dividing the $58.9 million in state-pl an costs in 2012 by 17.5 million MWh would indicate that the state measures will increase Basin’s wholesale rate by about $3.4/MWh. Continuing Basin Electric’s projected 3% load growth to 2017, when the SCR 

### would be expected to be on line, would result in sales to members of 20.3 million MWh. Dividing the $18.2 million in net SCR 

### costs by the Basin Electric sales produces a $0.9/MWh increase in the Basin Electric rate. This is about a quarter of the increase related to the State Implementation plan. Net SCR Costs



# Rate Increase for North Dakota and Minnesota Co-ops
The effect, as percent of rates, on each North Dakota and Minnesota distribution co-op of a dollars-per-MWh increase in Basin Electric’s Class-A rate depends on the following three factors:

• the percentage of the di stribution co-op’s genera tion supply that comes from Basin Electric;

• the percentage loss between the genera tion plants and the distribution coops’ customer meters, which determin es how many MWh of generation is required to deliver one MWh to customers; 8



### • The distribution co-op’s average rate.
The various distribution a nd G&T co-ops purchase power from sources other than Basin, in particular the We stern Area Power Administration ( WAPA 

### ), and Great River Energy (Great River 2008, Figure 1-2). See Table 12 . Small Co-op Power Supply

7 

### This total includes some sales to Class-D members, but th is appears to be a very small part of the total.
8 

### Losses are inherent in all electric systems due to the physical properties of matter. For instance, line losses are caused by electrical resistance in pow er lines, which transforms some electricity to heat. The heat radiates out of the system and its energy is lost.

The Cost of Clean Air • Resource Insight, Inc. 23Leland Olds Plant Analysis Rate Increase for North Dakota and Minnesota Co-ops



### amounts of internal generation are also reported by Agralite (<0.1% of supply) and Federated (1.3% of supply) ( EIA 

### 2009). These purchases further dilute the impact of pollution-control costs on electric
rates. Table 12: Co-ops Purchasing from WAPA and/or Great River Energy

Distribution Co-ops WAPA Great River 

### 3 Agralite 

### 3 Capital Electric Co-operative 

### 3 3 Crow Wing Power Federated Rural Electric Association 

### 3 3 KEM Electric Co-operative 

### 3 3 Meeker 

### 3 Minnesota Valley Co-operative Light & Power Assoc. 

### 3 3 Minnesota Valley Electric Co-operative Mor-Gran-Sou Electric Co-operative 

### 3 3 Redwood 

### 3
South Central 

### 3 3 Wright-Hennepin Co-operat ive Electric Assoc. 

### 3 Distribution Co-ops WAPA Great River Central Power Electric 

### 3 Upper Missouri G&T 

### 3 Upper Missouri G&T 

### 3
East River 

### 3
L&O Power 

### 3
Source: WAPA 2011; Great River Energy 2011.

### We have not found a source of comprehensive data on the amount of each cooperative’s supply that comes from Basin Electric. Table 13 lists available estimates of the fraction of energy supply from Basin for a number of Basin Electric members.

The Cost of Clean Air • Resource Insight, Inc. 24Leland Olds Plant Analysis Rate Increase for North Dakota and Minnesota Co-ops



### Table 13: Share of Co-op Load Provided by Basin Electric Co-op States Energy from Basin Sioux Valley Energy a SD, MN 65%
KEM b B ND 45%
Rushmore Electric c G&T SD 82% Northwest Iowa Power Co-operative d IA 79% Verendrye e ND 80% L&O G&T (serves Federated) f IA, MN, SD 66% Sheridan Electric Co-operative g MT 61% East River G&T (serves 7 Minn. co-ops) h SD, MN approx. 70%

a Souix Valley Energy 2011, bottom of page
b Emmons County Record 2009

c Rapid City Journal 2007
d NIPCO 2009, 2

e Carlson 2006 f Ocheyedan Press 2002

g Missoulian 2002
h Charles Mix Electric Association 2006

(which notes that 30% of power is federal, hence not from Basin).


### While there is considerable spread in these data, it seems reasonable to assume that the average Basin Electric distribu tion co-op member in North Dakota and Minnesota receives 70% of its energy from Basin Electric. The average Basin Electric member in North Dakota and Minnesota experienced energy losses on its system of about 4.2% in 2009; see Table 14 . Adding the losses on the systems of the intermediate G&T co-ops increased this average to 5.7% of sales. Thus, Basin must de liver an average of 1.057 MWh of energy for every MWh delivered to ultimate cu stomers. In addition, losses on Basin Electric’s transmission system amount to 3.2% of the energy delivered to its members, so each MWh of sales requir es a total of 1.091 MWh of generation. Line Losses

The Cost of Clean Air • Resource Insight, Inc. 25Leland Olds Plant Analysis Rate Increase for North Dakota and Minnesota Co-ops



### Table 14: Basin Co-op Loss Factors by Member Co-op Losses as Share of Input Energy Distribution Co-op Intermediate a G&T a Combined Losses as % Sales Agralite Electric Co-op 5.4% 2.1% a 8.0% Burke-Divide Electric Co-op Inc 10.5% 0.03% a 11.7% Capital Electric Co-op, Inc 2.6% 3.4% a 6.3% Crow Wing Co-operative Power & Light Comp 5.3% 0 a 5.5% Dakota Valley Electric Co-op Inc 1.6% 3.4% a 5.3% Federated Rural Electric Assn 3.3% 1.9% a 5.4% KEM Electric Co-op Inc 8.0% 0 a 8.7% Lyon-Lincoln Electric Co-op Inc 8.6% 2.1% a 11.8% McKenzie Electric Co-op Inc 3.4% 0.03% a 3.5% McLean Electric Co-op, Inc 9.8% 3.4% a 14.8% Meeker Co-op Light & Power Assn 5.1% 2.1% a 7.6% Minnesota Valley Co-op L&P Assn 5.8% 0 a 6.2% Minnesota Valley Electric Co-op 3.5% 0 a 3.6% Mor-Gran-Sou Electric Co-op Inc Mountrail-Williams Electric Co-op 5.6% 0.03% a 6.0% North Central Electric Co-op, Inc 1.4% 3.4% a 5.0% Northern Plains Electric Co-op 5.4% 3.4% a 9.4% Redwood Electric Co-op 5.5% 2.1% a 8.1% Renville-Sibley Co -op Power Assn 1.9% 2.1% a 4.1% Roughrider Electric Co-operative 6.0% 0.03% a 6.4% Slope Electric Co-op Inc 3.6% 0.03% a 3.7% South Central Electric Assn 3.4% 2.1% a 5.8% Traverse Electric Co-op, Inc 6.7% 2.1% a 9.5% Upper Missouri G&T El Co-op Inc A Verendrye Electric Co-op Inc 2.6% 3.4% a 6.3% Wright-Hennepin Co-op Electric Assn 3.2% 0 a 3.3% Sales-Weighted Average 4.2% A 5.7% Basin Electric Power Co-op 3.2% a 3.3% Combined Losses 9.1% Computed from EIA 2009 as Losses ÷ Total Sources.

a Based on the losses reported by the respective G&T co-op, as follows:

Central Power Electric Co-op, Inc

....... 3.4% East River Electric Power Co-op, Inc

... 2.1% L & O Power Co-operative

................. 1.9% Upper Missouri G&T El Co-op Inc

..... 0.03% Co-ops that do not belong to an intermediat e G&T co-op have zero intermediate G&T losses 

### We were able to find sales and the averag e retail rate for all of Basin’s 25 North Dakota and Minnesota distribution-co-op members for 2009, and for 20 of those co-ops for 2010; see Table 15 . For the co-ops for which 2010 data are available (representing 83% of total energy), the average rate per MWh increased 4.2% Co-op Average Rates

The Cost of Clean Air • Resource Insight, Inc. 26Leland Olds Plant Analysis Rate Increase for North Dakota and Minnesota Co-ops



### from 2009 to 2010. We estimated aver age 2010 rates by increasing the 2009 average by 4.2%. Table 15: Average Rates, Basin Electric’s Members in North Dakota and Minnesota

a 2009 a b 2010 b MWh Sales Revenue per MWh MWh Sales Revenue per MWh Wright-Hennepin Co-op Electric Assn 865,397 $86.90 882,882 $88.52 Dakota Valley Electric Co-op Inc 466,193 $58.40 506,976 $59.45 McKenzie Electric Co-op Inc 367,749 $61.80 425,428 $67.90 McLean Electric Co-op, Inc 95,631 $71.70 106,643 $75.45 Northern Plains Electric Co-op 363,284 $68.70 387,928 $70.85 North Central Electric Co-op, Inc 230,455 $72.20 222,955 $77.08 Verendrye Electric Co-op Inc 440,125 $64.60 459,885 $70.40 Mountrail-Williams Electric Co-op 420,949 $67.30 512,054 $75.54 Roughrider Electric Co-operative 473,801 $62.10 138,196 $62.51 Agralite c 210,506 $83.30 206,400 $83.82 Lyon-Lincoln 88,258 $84.90 87,800 $89.98 Meeker c 168,292 $103.80 168,700 $106.11 Redwood c 73,381 $95.20 90,100 $88.79 Renville-Sibley c 168,601 $58.50 179,000 $59.78 South Central c 183,728 $80.70 180,600 $83.06 Traverse c 44,178 $90.04 74,700 $91.03 Minnesota Valley Co-op. Light & Power Assoc. d 203,387 $72.60 197,755 $76.36 Crow Wing Power 556,899 $99.00 541,455 $100.84 KEM Electric Co-operative 72,558 $85.80 70,843 $96.10 Minnesota Valley Electric Co-operative 673,591 $90.20 700,535 $90.20 Subtotal 6,166,963 $76.99 6,140,835 $80.26 Federated Rural Electric Association 325,150 $67.50 Capital Electric Co-operative 279,144 $73.70 Burke-Divide Electric Co-operative 73,352 $88.80 Slope Electric Co-operative 421,282 $56.70 Mor-Gran-Sou Electric Co -operative 137,689 $105.50 Total 7,403,580 $75.94 $79.17

a EIA 2011b b EAI 2011a, except as noted c 2010 data from East River Electric Co-operative (2011, 8)
d 2010 values calculated from 2009 based on Minnesota Valley Electric Co-opera tive’s statement (2011, 4) that

it “recognized a four percent increase in energy sales” in 2010. 

### Basin Electric (2010, 11, 38) projects thatits average wholesale rate will increase by $5.50/MWh between 2010 and 2012. This increase would generally be passed on to retail rates, reduced by the percentage of energy the distribution co-op purchases from other sources and increased by the loss factor. In addition, WAPA 

### , the G&T co-ops, and the distribu tion co-ops have indicated that they will have continuing transmission and distribution investment (and in some cases, investment in wind generati on) for some time to come. Hence, we

The Cost of Clean Air • Resource Insight, Inc. 27Leland Olds Plant Analysis Rate Increase for North Dakota and Minnesota Co-ops

The Cost of Clean Air • Resource Insight, Inc. 28 

### assume that the average rate for th e ND and MN co-ops in 2012 will be $5.50/MWh more than the 2010 rate, or $84.67/MWh. After 2012, we assume that rate increases will fall to the rate of inflation, 2% annually, producing a 2017 av erage rate of $93.48/MWh. For the state-plan measures planned for 2012, we estimate an average retail rate increase of $3.4/MWh sold by Basin, tim es 70% of energy from Basin, times 1.091 for losses, divided by $84.67/MWh av erage distribution co-op rate: Rate Increases

$3.4/MWH × 70% × 1.091 ÷ $84.67/MWh = 3.1%
For the incremental cost of SCR 

### in 2017, we estimate an average retail rate increase of $0.9/MWh sold by Basin, tim es × 70% of energy from Basin, times 1.091 for losses, divided by ÷ $93.48/MWh average distribution co-op rate: $0.9/MWh × 70% × 1.091÷ $93.48/MWh = 0.7%

# Works Cited

Allete. 2011. 2010 Form 10k. Duluth, Minn.: Allete
Basin Electric. 2006. “ BART 

### Determination Study: for Leland Olds Station Unit 1 and 2.” Bismarck, N. D.: Basin Electric Power Co-operative ———. 2010. “2010 Annual Report: Strength in Unity.” Bismarck, N. D.: Basin Electric Power Co-operative.
———. 2011. “Load Forecast Shows Continue d System Growth,” Basin Today, July– August 2011, pp. 10–11. Bismarck, N. D. : Basin Electric Power Co-operative
Burns & McDonnell. 2006a. “NOx Best Ava ilable Control Technology Analysis Study for Milton R. Young Station Unit 1” Project No. 31777. Part of Appendix A to Minnkota Power (2006). Kansas City, Missouri: Burns & McDonnell Engineering Company, Inc.
———. 2006b. “NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 2” Project No. 31777. Part of Appendix A to Minnkota Power (2006). Kansas City, Missouri: Burns & McDonnell Engineering Company, Inc. Carlson, Bruce. 2006. “Facing Increasing Costs,” p. 3 of “2006 Verendrye Annual Report.” Velva, N. D.: Verendrye
Charles Mix Electric Association. 2006. “Eminent Service Award Recognizes Utilities for Storm Aid, Federal Administrator” South Dakota Co-operative Connections 58 (Oct 2008)10:11. Lake Andes, S.D.: Charles Mix Electric Association. DePriest, William. 2009. “ BART 

### Evaluation Update—Tail End SCR 

### ,” letter to Chris Miller of May 27, 2009. East River Electric Co-operative. 2011. “Investing Today for a Smarter Tomorrow: East River Electric Power Co-operative 2011 Annual Report.” Madison. S.D.: East River Electric Co-operative

The Cost of Clean Air • Resource Insight, Inc. 29Works Cited

EPA 

### . 2006. “North Dakota Region Citizens to Breathe Cleaner Air in $100 Million NSR 

### Power Plant Settlement.” <http:// yosemite.epa.gov/opa/admpress.nsf /a8f952395381d3968525701c 005e65b5/f4350627987d7a9d8525715a006ca3ba! OpenDocument> viewed 10/26/2011. Washington: Environmental Protection Agency.
For EPA 

### , see also FR (Federal Register)

EIA 

### . 2009. “Form EIA 

### -861 Data.” Washington: Energy Information Administration.

———. 2011a. “Form EIA 

### -826 Data.” Washington: Energy Information Administration ———. 2011b. “Class of Ownership, Number of Consumers, Sales, Revenue, and Average Retail Price by State and Utility: All Sectors, 2009” Table 10 of “Sales (consumption), revenue, prices & customer s.” Washington: Energy Information Administration Emmons County Record. 2009.”Berreth Tells of KEM 

### ’s Snow, Flood Challenges” Emmons County Record 7/02/09. Online news report accessed 10/23/2011. <www.centraldakotanews.com/?id=1200&ncid=8&nid=1314> Fox, Phillis. 2011. “Revised BART 

### Cost Effectiveness Analysis for Tail-End Selective Catalytic Reduction at the Basin Electric Power Co-operative Leland Olds Station Unit 2 Final Report” (RTI No. 0209897.004.095). Prepared for U.S. EPA 

### Region 8.
EPA 

### Region 8; Denver, Colo. FR (Federal Register). All references to the Federal Register in this report are to the
EPA 

### ’s proposed rule, 76 FR 58570–58648 (No. 183, September 12 2011). Great River Energy. 2008. “Resource Plan.” Maple Grove, Minn.: Great River Energy: ———. 2011. “Member Co-operatives” web page accessed 10/23/2011. <www.greatriverenergy.com/co-operativeway/memberco-operatives> Johanneck, Roger. 2010”Rate Increase” Volts and Jolts 45(7): 2 (May 2010). Red Lake Falls, Minn.: Red Lake El ectric Co-operative. Rouseau Electric Co-operative. 2011. “Cole Makes ‘Cents’: Lignite-Based Electricity Keeps Costs Low” Volts & Views 56(2):1 (February 2011). Rouseau, Minn.: Rouseau Electric Co-operativeMinnesota Valley Electric Co-operative. 2011. “Minnesota Valley Electric Cooperative Annual Report: Electric Eye special issue, June 2011. Jordan: Minn.: Minnesota Valley Electric Co-operative.
———. 2006. “ BART 

### Determination Study for Milton R. Young Station Unit 1 and 2.” Grand Forks, N. D.” Minnkota Power Co-operative
Minnkota Power. 2007. “ BART 

### Determination Study for Milton R. Young Station Unit 1 and 2” (revised). Grand Forks, N. D.” Minnkota Power Co-operative

The Cost of Clean Air • Resource Insight, Inc. 30Works Cited



### ———. 2011a. “2010 Annual Report.” Grand Forks, N. D.” Minnkota Power Cooperative ———. 2011b. “Energy for Today and Tomorrow” Minnkota Messenger (March/April 2011) 6–9. Grand Forks, N. D.” Minnkota Power Co-operative ———. 2011c. “Information on our Wholesale Rate Increase.” Grand Forks, N. D.” Minnkota Power Co-operative Missoulian. 2002. “Electric Co-ops Worry about Cost of Cap-and-Trade” Missoulian 6/1/2009. Online news report accessed 10/23/2011. <missoulian.com/news/stateand-regional/article_007b537e-7cbc- 51a6-8602-14daf9c46a11.html >

NDDH 

### (North Dakota Department of Health). 2010a. “North Dakota State Implementation Plan for Regional Haze: A Plan for Implementing the Regional Haze Program Requirements of Section 308 of 40 CFR Part 51, Subpart P—Protection of Visibility.” NDDH 

### : Bismarck, No. Dakota.
———. 2010b. “ BART 

### Determination for Leland Ol ds Station Units 1 and 2,” Appendix B.1 to “North Dakota State Implementation Plan for Regional Haze.”
NDDH 

### : Bismarck, No. Dakota. North Star. “Future in Focus” North Star Enlightener 55(11):6 (November 2010). Northwest Iowa Power Co-operative ( NIPC 

### o). 2009. “Challenge of the Future, Promise of the Past” 2009 Annual Report. NIPC 

### o” Le Mars, Iowa: NIPC 

### o. Ocheyedan Press. 2002. “L&O Power Co-operative celebrates 50th” Ocheyedan Press4/30/2002. Online news report accessed 10/23/2011. <www.thepressnews.com/site/index.cfm?newsid=3742 828&brd=2204&pag=461&dept_id=43137 3> Rapid City Journal. 2007 “Electrical Co-ops Raising Rates” Rapid City Journal 10/27/2007. Online news report accessed 10/ 23/2011. < http://rapidcityjournal .com/news/local/top-stories/electrical-co- ops-raising-rates/article_f6fb0f8f-0576- 5783-902e-44b53b1875f3.html> Sargent & Lundy. 2010. “ IPM 

### Model—Revisions to Cost and Performance for APC 

### Technologies: SCR 

### Cost Development Methodology” Project 12301-007 Final. Charlottesville, Va.: Perrin Quarles Associates Sigurdson, Paul, and David Loer. 2011. “R eport to the Members.” “Square Butte Electric Co-operative Annual Report” 2–3). Grand Forks, N.D.: Square Butte Electric Co-operative Square Butte. 2011 “Square Butte Electric Co-operative Annual Report.” Grand Forks, N.D.: Square Butte Electric Co-operative Souix Valley Energy. 2011. “About us” web page accessed 10/23/2011. <http://www.siouxvalleyenergy.com/aboutUs.php>

The Cost of Clean Air • Resource Insight, Inc. 31Works Cited

The Cost of Clean Air • Resource Insight, Inc. 32 

### Tschepen, Al. 2010. “Resource Plan” power-point presentation to REMA 

### Member Services Conference Jan. 7, 2010 in St. Cloud, Minn. Resource Planning G&T Panel. Maple Grove, Minn.: Rural Electric Management Association Western Area Power Administration ( WAPA 

### ). 2011. “Rural Electric Co-operatives” “Member Co-operatives” web page acc essed 10/23/2011. <www.wapa.gov/ugp/ Customers/RuralElectricCo-operatives.htm>

# Abbreviations and Acronyms

The following abbreviations and acronyms are used in this work, in cited works, or in the field generally.

AFUDC 

### ..............Allowance for Funds Used During Construction

ASOFA 

### ...............Advanced Separated Overfire Air

BART 

### .................Best Available Retrofit Technology

EIA 

### ....................U.S. Energy Information Administration

EPA 

### ...................U.S. Environmental Protection Agency

FGD 

### ...................Flue-gas desulfurization, also known as scrubbing FR ....................Federal Register
G&T.................Generation-and-transmission

IPM 

### ...................Integrated Planning Model
kV ....................kilovolts MW..................Megawatt, a unit of generating capacity MWh................Megawatt hour, a unit of electri city production or consumption

NDDH 

### ................North Dakota Department of Health

NIPC 

### o................Northwest Iowa Power Co-operative

NMPA 

### ................Northern Municipal Power Agency
NO x .................Oxides of nitrogen (nitrogen oxides)

NSR 

### ...................New Source Review provisions of the Clean Air Act O&M................Operation-and-maintenance
PM10 ...............Particulate matter with diameters less than 10 microns (micrometers)

The Cost of Clean Air • Resource Insight, Inc. 33Abbreviations and Acronyms

The Cost of Clean Air • Resource Insight, Inc. 34 REMA 

### ................Rural Electric Management Association

RUS 

### ...................U.S. Rural Utility Service, formerly the Rural Electrification Administration

SCR 

### ...................Selective catalytic reduction

SIP 

### ....................State Implementation Plan

SNCR 

### .................Selective Non-Catalytic Reduction
SO 2 

### ...................Sulfur dioxide

SOFA 

### .................Separated Overfire Air

WAPA 

### ................Western Area Power Administration