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. i 
Contents 

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

LELAND OLDS PLANT BACKGROUND.......................................16

Leland Olds Plant ...................................................................................16 

Ownership...............................................................................................17 

LELAND OLDS PLANT ANALYSIS................................................21

Cost of the State Implementation Plan ...................................................21 

Cost of Selective Catalytic Reduction 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 Dakota 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 lignite-fired power plants will have 

varying effects on electric rates in parts 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 measures proposed by plant operators and 

required by North Dakota in its State Implementation Plan. 

Other equipment proposed by the EPA would not add to rates until it enters 

service in 2017, but the rate increases from 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 pollution control at the Leland Olds plant is 

diluted by purchasesfrom many othersources.By contrast, Minnkota’s member 

co-ops rely on the Milton R. Young plant 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. 3 
Summary 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 increase 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 into the plant exhaust 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 and 

Young 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 smokestack, both sulfur dioxide and nitrogen oxides condense into fine particles 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 are 

conducted separately for Olds and Young, and within each plant, for the staterequired measures and those proposed by the EPA. 

1Because of the differences between Minnkota (which serves 11 co-ops, all in Minnesota and North Dakota) 

and Basin (which directly or indirectly serves some portion 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-fired units located in Center, North 

Dakota. Both units are powered by cyclone 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 greater amount of oxides of nitrogen 

(NOx) than do other designs. 

Young Unit 1 is 100% owned by Minnkota Power Co-operative, Inc. Young 

Unit 2 is operated by Minnkota, but owned by Square Butte Electric Cooperative, which was formed to own that unit and associated transmission. 

Both units have electrostatic precipitators that remove more than 99% of 

particulate matter from the flue gas. Unit 2 has a wet flue-gas desulfurization 

system (or “scrubber”) for control of sulfur dioxide (SO2), while Unit 1 has no 

SO2 controls. Neither unit has any post-combustion controls for oxides of 

nitrogen (NOx). (Minnkota 2006, 2, ES-2.) 

In October 2006 (with a supplementary filing in August 2007), Minnkota 

proposed the following steps to comply with Regional Haze rules: 

• using the existing electrostatic precipitators to reduce particulate-matter 

emissions for both units, 

• upgrading the existing scrubber 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. 5 
Milton R. Young Plant Background Milton R. Young Plant 

• retrofitting the combustion area of each unit with Advanced Separated 

Overfire Air (ASOFA) to reduce NOx formation and adding selective noncatalytic reduction (SNCR) to the flue-gas system to break down some of the 

NOx emissions. 

The scrubber addition and upgrade and the reduction of NOx by at least 40% are 

required by an April 2006 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 scrubber was upgraded in 2010 and Unit-1’s was 

installed in April 2011. (Square Butte 2011, 7–8; North Star 2010, 6; 76 FR 

58589–58590.) 

In February 2010, the North Dakota Department of Health accepted Basin’s 

proposed technologies as part of its State Implementation Plan, while requiring 

lower emission rates from the scrubbers. The Department found that a higher 

level of NOx 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 

SO2 and particulates on both units, but found that SCR would be cost-effective 

in controlling NOx emissions and thus proposed to require SCR. 

The measures to bring Milton R. Young 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

 

2Addition of SCR would eliminate the need to operate the SNCR system. 

The Cost of Clean Air • Resource Insight, Inc. 6 
Milton 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 generation-and-transmission (G&T) cooperatives, owned by 11 member distribution co-opsin 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-transmission 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 is 

sold 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 transaction, Minnesota 

Power’s share of the output from Young 2 will gradually be 

transferred to Minnkota, over 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 NOx on both 

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

The installed cost of these measures 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 Lake 

Electric Co-operative, Roger Johanneck (2010, 2), describing “the investments in pollution control equipment,” writes of “the $360 million that Minnkota is investing in its Young 1 and Young 2 generating plants.” 

Of the scrubber and NOx-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 end of 2011.” Square Butte 

(2011, 7) further breaks down the capital costs to $260 

million for the scrubbers and $30 million for NOx controls. The reported NOx costs are similar to the sum of 

those estimated by Minnkota (2006) (which add to

about $27 million in installation-year dollars), but the scrubber costs reported 

by Square Butte (2011) are some $110 million 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. 8 
Milton R. Young Plant Analysis Cost of State-Plan Measures 

The $425-million total cost estimate includes $130 million of “electrical 

improvements” including “new auxiliary transformers...new breakers, wiring 

and switchgear” (North Star 2010, 6). Square Butte (2010, 7) elaborates: 

Additional infrastructure to support the 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 improvements were required solely for the environmental improvements. The sum of $260 million for the scrubbers, $30 million 

for NOx, 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, we 

distribute the $110 million in undesignated scrubber costs proportionately over the cost estimates from 

Minnkota (2006),resulting in scrubber costs of $213 million for Unit 1 

and $47 million for Unit 2. We similarly increase Minnkota’s estimates 

for NOx 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 NOx costs. See Table 

4. 

Table 4: Capital Costs of the State Implementation Plan

(Millions of Dollars)

Measure 

Estimatea

froma

Minnkotaa

(2006)a

Normalizedb

to Reportedb

Totalb

Controlb

Capitalb

Allocationc

ofc

Electricalc

Upgradesc

Totald

Allocatedd

Costd

Unit 1 

FGD $123.4a $213.3b $99.3c $312.5d

ASOFA $4.5a $5.1b $2.4c $7.5d

SNCR $4.2a $4.7b $2.2c $6.8d

Total $132.1a $223.0b $103.8c $326.8d

Unit 2 B

FGD $27.0a $46.7b $21.8c $68.5d

ASOFA $10.2a $11.4b $5.3c $16.8d

SNCR $7.9a $8.8b $4.1c $12.9d

Total $45.1a $67.0b $31.2c $98.2d

Young Plant Total 

FGD $150.5a $260.0b $121.0c $381.0d

ASOFA 

+ SNCR $26.8a $30.0b

$14.0c $44.0d

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

aTable 3, above 

bFor flue-gas desulfurization (FGD), the estimate from Minnkota (2006) is

normalized by multiplying it by the capital costs for the scrubbers ($260

million, per Square Butte 2011, 7) and 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) 

cThe $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). 

dSum of normalized capital costs plus electrical upgrades 

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

In additional to capital costs, the state-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 2010c Est 2012d

State-Plan O&Me

as % totale

Young Unit 1 

FGD $10.3a $11.6b

ASOFA $1.7a $1.9b

SNCR $3.7a $4.2b

Total $15.7a $17.7b $14.0c $30.4d 58%e

Young Unit 2 

FGD $5.0a $5.6b

ASOFA $2.8a $3.2b

SNCR $5.1a $5.8b

Total $12.9a $14.6b $37.8c $50.7d 29%e

aBurns & McDonnell 2006a 3-23, 2006b 3-23; Minnkota 2007, 3-12, 3-21 

b2006 dollars × 1.026. 

cComputed from Minnkota 2011, 1 

d2010 O&M × 1.022 + 2012-dollar O&M for FGD and SNCR. (ASOFA was included in 2010 O&M.) 

e2012-dollar O&M ÷ total O&M estimated for 2012. 

Minnkota’s embedded cost of debt is about 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 remaining lives of at least 

20 years for Young 1 and 2. Rouseau Electric (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 Sigurdson & 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 

 

3These estimates of O&M cost are stated in levelized nominal 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. 10 
Milton R. Young Plant Analysis Incremental Cost of Selective Catalytic Reduction 

With a 4% cost of capital (toward the 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 the 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 by 

Minnkota. This value is considerably greaterthan predicted by Minnkota (2011b, 8): 

Table 6: Annual Costs for State-Plan Measures 

Measure 

Totala

Allocateda

Costa

Annualb

Capitalb

Costb

Recoveryb

2012c

O&Mc AnnualdCostsd

Unit 1 

FGD $312.5a $23.0b $11.6c $34.6d

ASOFA $7.5a $0.5b $1.9c $2.5d

SNCR $6.8a $0.5b $4.2c $4.7d

Total $326.8a $24.0b $17.7c $41.7d

Unit 2 

FGD $68.5a $5.0b $5.6c $10.7d

ASOFA $16.8a $1.2b $3.2c $4.4d

SNCR $12.9a $1.0b $5.8c $6.7d

Total $98.2a $7.2b $14.6c $21.8d

aFrom Table 4, above. 

bTotal allocated costs × 7.36% annual cost-recovery factor 

cFrom Table 5, above. 

bSum of annual capital costs and O&M costs 

In the near term, capital investments and operating and maintenance cost increases have 

added significant upward pressure to Minnkota’s wholesale

rate. The annual cost of the environmental control additions 

will be about $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 best-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. 11 
Milton 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 Unit 1 and $216.9 million for Unit 2 (in 

2009 dollars). Those are overnight costs, expressed as if all the work could be 

completed in a short period within 2009. Assuming 2% inflation, the 

comparable overnight cost for completion in 2017 would be about $141 million 

and $254 million, respectively. In addition, the EPA costing methodology does 

not include interest costs during construction, 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 assume that Minnkota will capitalize the 

interest, paying about 4% annual interest on the outstanding balance or about 

2% more than the inflation that is already included in the overnight costs for 

2017. Since the actual period for SCR construction tends to be short, relatively 

little interest accrues during construction. 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 investor-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 years 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 the 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 cost-recovery factor for environmental 

upgrades would be 7.36% of the initial investment, and the incremental annual 

capital recovery would be $147 million × 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. 12 
Milton 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 $34.5 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 2009a SCR 2017 SNCR O&M 

Capital 

Costs 

O&M 

Costs 

Capitalb

Costsb Cap.+c

AFDCc AnnualdCapitald

O&Me

Costse 2006fDollarsf

2017g

Dollarsg

Neth

SCRh

O&Mh

2017h

Dollarsh

Totali

2017i

Costi

Unit 1 $120.6 $11.3 $141.3b $147.0c $10.8d $13.2e $3.7f $4.6g $8.6h $19.4i

Unit 2 $216.9 $17.8 $254.1b $264.3c $19.4d $20.9e $5.1f $6.4g $14.5h $33.9i

a76 FR 58601 

b2009 Capital costs × 1.028 (8 years of 2% inflation) 

c2017 Capital Costs × 1.04 

d“Cap + AFDC” × 7.36% 

e2009 SCR O&M × 1.028 (8 years of 2% inflation) 

fFrom Table 5 (2006-dollar SCR O&M 

g2017 O&M costs× 1. 028 (8 years of 2% inflation) 

h2006-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 Young-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 steadily from 2002 through 2011, with a 

$16/MWh increase in 2011. See Table 9. 

The Cost of Clean Air • Resource Insight, Inc. 13 
Milton 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 energy 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 salesto 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

2002a 30.2 

2003a 32.0 6.0% 6.0%

2004a 34.6 8.1% 7.0%

2005a 35.8 3.5% 5.8%

2006b 35.8 0.0% 4.3%

2007b 38.1 6.3% 4.7%

2008b 39.8 4.5% 4.7%

2009b 44.9 12.8% 5.8%

2010b 53.0 18.0% 7.3%

2011a 69.0 30.2% 9.6%

aMinnkota 2011b, 3. bMinnkota 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 continuation of Minnkota’s historical 

5% increases, without any provision for rate increases to cover the distribution 

co-ops’ costs), the resulting revenues are $350.6 million in 2012 and $446.6 

million in 2017, without the SCR costs. 

For 2012, we estimate that retail rates would 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 costs 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-thirds 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 $834 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 automatic cost flow-through mechanisms. 

Hence, Minnesota Power’s 2011 revenues would appear to be on the order of 

Minnesota 

Power 

 

4Much of these costs are already in rates. Minnkota reports 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. 14 
Milton 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 revenues 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-fired units located in Stanton, North 

Dakota. Unit 1 has a wall-fired, dry-bottom, pulverized-coal-fired boiler and is 

rated at 216 MW (NDDH 2010b, 1). Unit 2 has a cyclone boiler burning crushed 

coal and is rated at 440 MW (NDDH 2010b, 2). Cyclone boilers produce more 

oxides of nitrogen (NOx) 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 (SO2) or oxides of nitrogen (NOx). 

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 NOx formation and adding selective non-catalytic reduction 

(SNCR) to the flue-gas system to break down some of the NOx 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. 16 
Leland Olds Plant Background Ownership 

In February 2010, the North Dakota Department of Health accepted Basin’s 

proposed technologies as part of its State Implementation Plan, while requiring 

lower emission rates from the electrostatic precipitators, requiring the wet 

scrubber on Unit 1 (resulting in lower emission rates), and accepting the SOFASNCR combination for NOx control. The Department (NDDH 2010a Appendix B6, 31) found that a higher level of NOx control was technically feasible at Unit 

2, 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 

SO2 and particulates on both units and NOx on Unit 1, but found that SCR

would be cost-effective in controlling emissions of oxides of nitrogen (NOx) 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-transmission (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 generation 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 members. Two of the co-ops in Montana 

and Wyoming that purchase portions of the 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. 17 
Leland 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. 18 
Leland 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 Electrica

Minn. Crow Wing Power 

Minn. Minnesota Valley Co-operative Light & Power Association 

Minn. Minnesota Valley Electric Co-operative 

Minn. Wright-Hennepin Co-operative Electric Association 

N.D. KEM Electric Co-operative 

N.D. Mor-Gran-Sou Electric 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-operativeb

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-operative Power Association 

Minn. South Central Electric Association 

Minn. Traverse Electric Co-operative 

L & O Power Co-operativec

Minn. Federated Rural Electric Association 

Upper Missouri Generation and. Transmission Electric Co-operatived

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-operative (8 members in South Dakota), Northwest Power 

Co-operative (7 in Iowa), Corn Belt Power Co-operative (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 

aBasin 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 serves 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-member board elected by district by the 

135 member co-ops. The co-op owns eight for-profit and non-profit energy, 

mining, and telecommunications subsidiaries and operates more than 3,700 

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

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

MW of generation with some 850 MW under construction. It owns more than 

2,000 miles of high-voltage transmission. (Basin Electric 2010 2–9, 20.) 

Basin Electric provides generation and transmission services to its members. In 

most cases, those are only part of the generation and transmission resources 

used by the members. Some members (especially 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 members. 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 

Dollarsa

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

aBasin Electric 2006, 64, 66, 98, 99, 158,188 

bThese costs are calculated as follows: 

(2005 Capital Costs × 1.027 × 7.36%) + (2005 O&M × 1.027). 

1.027 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. 21 
Leland Olds Plant Analysis Cost of Selective 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 estimate 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 avoid 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 investment, and the incremental 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 dollars, 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 

 

5While these capital-cost estimates are quite close 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. 

6Because this estimate is specific to 2012 rate effects, it does not include a multiplier for inflation in the 

O&M costs. Basin Electric’s levelized cost estimate (2006, 99) adds an inflation multiplier because it is stated 

in levelized nominal dollars over the life of the equipment. 

The Cost of Clean Air • Resource Insight, Inc. 22 
Leland 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 reports that its 2011 load forecast 

projects an average annual growth rate of 3% through 2025. Specific forecasts 

for individual years are not readily available. However, if sales to Basin 

Electric rise at 3% annually from 2010 to 2012, they would be 17,500,000 

MWh in 2012. 

Costs of StatePlan Measures 

Dividing the $58.9 million in state-plan 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 distribution co-op’s generation supply that comes 

from Basin Electric; 

• the percentage loss between the generation plants and the distribution coops’ customer meters, which determines how many MWh of generation is 

required to deliver one MWh to customers;8

• The distribution co-op’s average rate. 

The various distribution and G&T co-ops purchase power from sources other 

than Basin, in particular the Western Area Power Administration (WAPA), and 

Great River Energy (Great River 2008, Figure 1-2). See Table 12. Small 

Co-op Power 

Supply 

 

7This total includes some sales to Class-D members, but this appears to be a very small part of the total. 

8Losses are inherent in all electric systems due to the physical properties of matter. For instance, line losses 

are caused by electrical resistance in power 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. 23 
Leland 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

Agralite 3 3

Capital Electric Co-operative 3

Crow Wing Power 3

Federated Rural Electric Association 3 3

KEM Electric Co-operative 3

Meeker 3 3

Minnesota Valley Co-operative Light & Power Assoc. 3

Minnesota Valley Electric Co-operative 3

Mor-Gran-Sou Electric Co-operative 3

Redwood 3 3

South Central 3 3

Wright-Hennepin Co-operative 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. 24 
Leland 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 Energya SD, MN 65% 

KEMb B ND 45% 

Rushmore Electricc G&T SD 82% 

Northwest Iowa Power Co-operatived IA 79% 

Verendryee ND 80% 

L&O G&T (serves Federated)f IA, MN, SD 66% 

Sheridan Electric Co-operativeg MT 61% 

East River G&T (serves 7 Minn. co-ops)h SD, MN approx. 70% 

aSouix Valley Energy 2011, bottom of page 

bEmmons County Record 2009 

cRapid City Journal 2007 

dNIPCO 2009, 2 

eCarlson 2006 

fOcheyedan Press 2002 

gMissoulian 2002 

hCharles 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 distribution 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-opsincreased this average 

to 5.7% of sales. Thus, Basin must deliver an average of 1.057 MWh of energy 

for every MWh delivered to ultimate customers. 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 requires a total of 1.091 MWh of generation. 

Line Losses 

The Cost of Clean Air • Resource Insight, Inc. 25 
Leland 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

Intermediatea

G&Ta

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% 0a 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% 0a 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% 0a 6.2% 

Minnesota Valley Electric Co-op 3.5% 0a 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% 0a 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. 

aBased 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 intermediate G&T co-op have zero intermediate G&T losses

We were able to find sales and the average retail rate for all of Basin’s 25 North 

Dakota and Minnesota distribution-co-op membersfor 2009, and for 20 ofthose 

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. 26 
Leland Olds Plant Analysis Rate Increase for North Dakota and Minnesota Co-ops 

from 2009 to 2010. We estimated average 2010 rates by increasing the 2009 

average by 4.2%. 

Table 15: Average Rates, Basin Electric’s Members in North Dakota and Minnesota a2009a b2010b

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

Agralitec 210,506 $83.30 206,400 $83.82

Lyon-Lincoln 88,258 $84.90 87,800 $89.98

Meekerc 168,292 $103.80 168,700 $106.11

Redwoodc 73,381 $95.20 90,100 $88.79

Renville-Sibleyc 168,601 $58.50 179,000 $59.78

South Centralc 183,728 $80.70 180,600 $83.06

Traversec 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 bEAI 2011a, except as noted c2010 data from East River Electric Co-operative (2011, 8) 

d 2010 values calculated from 2009 based on Minnesota Valley Electric Co-operative’s statement (2011, 4) that

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

Basin Electric (2010, 11, 38) projects that its 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 distribution co-ops have indicated that 

they will have continuing transmission and distribution investment (and in 

some cases, investment in wind generation) for some time to come. Hence, we 

The Cost of Clean Air • Resource Insight, Inc. 27 
Leland 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 the 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 average 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, times 70% of energy from Basin, times 

1.091 for losses, divided by $84.67/MWh average 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, times × 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 Continued System Growth,” Basin Today, July–

August 2011, pp. 10–11. Bismarck, N. D.: Basin Electric Power Co-operative 

Burns & McDonnell. 2006a. “NOx Best Available 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. 29 
Works 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

/a8f952395381d3968525701c005e65b5/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. “FormEIA-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 & customers.” 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> 

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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 electricity production or consumption 

NDDH................North Dakota Department of Health 

NIPCo................Northwest Iowa Power Co-operative 

NMPA ................Northern Municipal Power Agency 

NOx .................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. 33 
Abbreviations 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 

SO2 ...................Sulfur dioxide 

SOFA .................Separated Overfire Air 

WAPA ................Western Area Power Administration