20110926Application.pdf

JASON B. WILLIAMS
Corporate Counsel
iwilliams~idahopower.com
esIDA~PO~
An IDACORP Company
September 26, 2011
VIA HAND DEI.IVERY NEW r:A
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
Boise, Idaho 83702
Re: Case No. IPC-E-11-18
IN THE MATTER OF IDAHO POWER COMPANY'S REQUEST FOR
ACCEPTANCE OF ITS REGULATORY PLAN REGARDING THE EARLY
SHUTDOWN OF THE BOARDMAN POWER PLANT
Dear Ms. Jewell:
Enclosed for filng please find an original and seven (7) copies of Idaho Power
Company's Application in the above matter.
Very truly yours,
d'! Jason B. Willams
JBW:kkt
Enclosures
JASON B. WILLIAMS
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
jwilliamsCâidahopower.com
InordstromCâidahopower.com
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20f I SEP 26 PM 4: 52
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Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MAnER OF IDAHO POWER
COMPANY'S REQUEST FOR
ACCEPTANCE OF ITS REGULATORY
PLAN REGARDING THE EARLY
SHUTDOWN OF THE BOARDMAN
POWER PLANT.
)
) CASE NO. IPC-E-11-18
)
) APPLICATION
)
)
)
Idaho Power Company ("Idaho Powet' or "Company"), in accordance with Idaho
Code § 61-524 and RP 52, hereby respectfully makes Application to the Idaho Public
Utilities Commission ("IPUC" or "Commission") for an Order that (1) accepts the
Company's regulatory accounting and cost recovery plan regarding the early shutdown
of the Boardman Power Plant ("Boardman") and (2) approves the establishment of a
balancing account whereby incremental costs and benefits associated with the
shutdown of Boardman wil be tracked for recovery in a future proceeding. The
Company does not seek current approval for rate recovery of future expenses
associated with the Boardman shutdown at this time.
APPLICATION - 1
In support of this Application, Idaho Power represents as follows:
I. BACKGROUND
1. Boardman is a pulverized-coal plant located in north-central Oregon. It
went into service in 1980 and consists of a single generating unit. Based upon currently
approved depreciation rates, Boardman's expected plant life extends through at least
2030. Idaho Power owns a 10 percent interest, or 58.5 megawatts (net dependable
capacity), in Boardman. After adjusting for routine scheduled maintenance periods and
estimated forced outages, Idaho Power's share of the plant's annual energy generating
capability is approximately 50 average megawatts. Portland General Electric ("PGE")
has 65 percent ownership, Bank of America Leasing has 15 percent ownership, and
Power Resources Cooperative has 1 0 percent ownership. As the majority partner of the
plant, PGE operates the Boardman facility.
2. The Federal Clean Air Act requires that Oregon adopt and implement a
plan to reduce visibility impacts to background levels by 2064 in designated areas
(referred to as Class I areas). Oregon's plan to achieve this goal is referred to as the
Oregon Regional Haze Plan ("Regional Haze Plan"). A draft of the Regional Haze Plan
that included rules requiring specific emission reductions at Boardman by certain dates
was issued by the Oregon Department of Environmental Quality ("DEQ") in December
2008 and was subsequently adopted with modifications by the Environmental Quality
Commission ("EQC") on June 19, 2009. According to PGE, the EQC's modifications
require "the installation of environmental controls as Best Available Retrofit Technology
(BART) at the Boardman plant for the purpose of reducing visibilty-impairing emissions
and additional environmental controls as Reasonable Progress (RP) towards additional
APPLICATION - 2
haze causing emissions reductions." PGE 2009 Integrated Resource Plan ("IRP")
Addendum, p. 88. The then-approved Regional Haze Plan required two phases -
Phase 1 BART controls and Phase 2 RP controls, described as follows:
Phase 1 compliance requires installation of Low NOx
Burners and Modified Over-Fired Air ("LNB/MOFA") and
semi-dry flue gas desulfurization (scrubbers) with an
associated fabric filter. Phase 2 requires the installation of
selective catalytic reduction (SCR). Under the existing
Regional Haze Plan, PGE has the following options:
· Install all of the controls: LNB/MOFA by July
2011, scrubbers/fabric filter by July 2014 and
SCR by July 2017 and operate Boardman
through 2040 or beyond (modeled in the
"Diversified Thermal with Green" portolios).
· Install LNB/MOFA and scrubbers/fabric filters
and cease Boardman operations in 2017; do not
make the SCR investment (modeled in the
"Boardman through 2017" portolio).
· Install LNB/MOFA only and cease Boardman
operations in 2014 (modeled in the "Boardman
through 2014" portolio).
· Cease Boardman operations in July 2011 with
no obligation to install additional controls
(modeled in the "Boardman through 2011"
portolio ).
PGE 2009 IRP Addendum, p. 89.
3. In its 2009 IRP, PGE states that Boardman must meet these emissions
requirements by either installng controls or ceasing operations altogether. PGE notes
that "failure to comply with the plan can result in significant penalties, equitable
remedies, and possibly criminal sanctions." PGE 20091RP, p. 294.
4. In addition to the Regional Haze Plan, Boardman is also subject to the
Oregon Utilty Mercury Rule ("Mercury Rule"), which requires installation of mercury
APPLICATION - 3
control equipment. The mercury control equipment installation is required by July 1,
2012. PGE plans to meet this requirement for Boardman in the following manner:
. . . PGE determined that the injection of activated carbon
upstream of the existing ESP (electrostatic precipitator) is
most likely to result in the capture of at least 90 percent of
the mercury contained in the coaL. While this control
approach is not optimal on a long-term basis, as there is
material risk of rendering the ash unsellable, the approach
enables PGE to substantially decrease mercury emissions
prior to the time when a fabric filter can be installed.
PGE 20091RP, p. 294.
5. This approach wil significantly decrease Boardman's mercury emissions
while at the same time eliminating the need for a more expensive fabric filter equipment
installation. PGE received approval of this mercury reduction plan from the DEQ, thus
allowing PGE to provide a cost-effective solution for its customers.
II. BOARDMAN ANALYSIS
6. As part of its 2009 IRP, PGE analyzed "each of the Boardman-related
controls technologies and associated deadlines" required under the Regional Haze
Plan. PGE 2009 IRP, p. 295. A copy of the Boardman Analysis (Chapter 12) included
in PGE's 2009 IRP is provided as Attachment No. 1.1 Each of the Regional Haze Plan
scenarios was analyzed as a separate portolio with assumed end-of-life plant dates of
2040 (which included two portolios: Diversified Thermal with Green and Diversified
Green with On-Peak Energy Target), 2017, 2014, and 2011.
1 A complete copy of PGE's 2009 IRP can be found at:
http://ww.Dortlandgeneral.com/our company/news issues/current issues/energy strategy/docs/irp nov
2009.pdf.
APPLICATION - 4
7. PGE indicated the portfolio analyses provided a "comprehensive look at
Boardman's value and risks" and took "into account expected cost, as well as price and
reliability risk." PGE 2009 IRP, p. 307. A summary of PGE's results indicated:
Overall, 'Diversified Thermal with Green' scored better than
the Boardman 2014 portolio . . .. The 'Diversified Thermal
with Green' portolio which includes Boardman through 2040
also clearly outperformed the early closure cases with
respect to price risk and reliabilty. In general, although
more exposed to CO2 costs, the 'Diversified Thermal with
Green' portolio provides an effective hedge against natural
gas price volatilty, while maintaining system reliabilty at a
relatively low cost.
PGE 2009 IRP, p. 307.
8. However, in January 2010, subsequent to the "Boardman through 2040"
recommendation, rules recommended by the DEQ and requests from stakeholders
suggested further analysis of a 2020 closure of Boardman.
9. PGE submitted an alternate proposal to the DEQ on April 2, 2010,
requesting a petition that would allow for amendment to the Regional Haze Plan ("BART
II Petition"). With the BART II Petition, PGE sought approval to shutdown or cease
coal-fired operations at Boardman in 2020 while utilizing "a more limited emissions
control upgrade package." PGE 2009 IRP Addendum, p. 89. With the BART II Petition,
PGE:
. . . would cut haze-causing emissions of sulfur dioxide and
nitrogen oxides from the Boardman plant by:
. Installing new, state-of-the-art LNB/MOFA
burners by July 1, 2011. The new burners are
expected to reduce nitrogen oxides emitted by the
plant by nearly 50 percent.
APPLICATION - 5
. Using coal with a lower sulfur content to fire the
plant's boiler. This would be completed in two
stages as PGE's current coal supply contracts
expire. In addition, PGE has recommended an
initial 20 percent drop in permitted sulfur dioxide
emissions that would take effect in 2011. This is
followed by a further reduction in 2014 that would
bring allowed sulfur dioxide emissions down by a
total of 50 percent from current permit levels.
. Closing the plant in 2020, ending all coal-related
emissions at least 20 years ahead of schedule
and significantly reducing Oregon's contribution to
green house gas emissions.
PGE 2009 IRP Addendum, pp. 89-90.
10. PGE analyzed the BART II Petition scenario ("Boardman through 2020")
as part of its IRP portolio analysis and filed an addendum to its 2009 IRP with the
Public Utility Commission of Oregon ("OPUC") in April 2010 (see Attachment No. 22).
The analysis found that the "Boardman through 2020" portolio performed better overall
than all other alternatives. PGE stated that, the "'Boardman through 2020' portolio
strikes a good balance between the key risk drivers of natural gas and CO2 prices, while
maintaining system reliability at a relatively low cost." PGE 2009 IRP Addendum, p.
103. Based on this analysis, a 2020 closure of Boardman was included in PGE's
preferred portolio.
11. While the IRP portolio analyses provide a comprehensive look at the
costs and risks associated with various Boardman scenarios, PGE points out the
following benefits the IRP analysis did not capture with regards to "Boardman through
2020":
2 Attachment NO.2 is the Boardman Analysis (Chapter 12A) of PGE's 2009 IRP Addendum. A
complete copy of the Addendum can be found at:
http://ww.portlandgeneral.com/our company/news issues/current issues/energy strategy/docs/irp add
endum.pdf.
APPLICATION - 6
· It preserves the near-term economic value of the plant
thereby saving customers around $600 milion dollars
over the next decade compared to the earlier closure
alternatives.
. It avoids the acceleration of additional costs and the
corresponding customer rate pressure during a time
when other I RP resource actions are also being
implemented.
. It allows time for other greener technologies beyond
wind to develop and economically mature, potentially
allowing for a greater range of replacement options by
2020 than are available today for implementation by
2014.
· It provides a hedge against compliance costs of any
future greenhouse gas legislation when compared to
plans that operate Boardman through 2040.
. It allows for orderly transition for Boardman plant
employees and the local community.
PGE 2009 IRP Addendum, p. 105.
12. The OPUC acknowledged PGE's 2009 IRP, including "Boardman through
2020" as the preferred portolio, on November 23, 2010 (see Attachment No.3).
Shortly after, on December 9, 2010, the Oregon EQC approved revised BART rules
"which require the installation of controls at Boardman to reduce NOx and S02 in 2011
and a Dry Sorbent Injection system in 2014 to further address S02, with cessation of
coal-fired operations by the end of 2020." PGE Advice 11-07 Attachment A -
Discussion and Summary, p. 6. These revised rules were submitted as part of a
revision to Oregon's Clean Air Act State Implementation Plan to the U.S. Environmental
Protection Agency ("EPA") and were approved on July 5,2011 (see Attachment No.4).
13. In July 2011, a consent decree was filed with the U.S. District Court for the
District of Oregon memorializing a settlement reached among the Sierra Club, four other
APPLICATION - 7
non-profit corporations and PGE related to Boardman. The Sierra Club and other
plaintiffs had filed a complaint against PGE alleging Clean Air Act and opacity permit
limit violations at Boardman. The consent decree provides that PGE will pay $2.5
millon to the Oregon Community Foundation to be used for environmentally beneficial
projects and will pay $1.0 million of the plaintiffs' legal expenses. Further, the consent
decree imposes certain sulfur dioxide emission caps on the Boardman coal-fired boiler
and would allow continued operation of Boardman until December 31, 2020. The
consent decree is subject to approval of the court following a 45-day review period by
the EPA and the U.S. Department of Justice. The consent decree was not contested
during the 45-day review period and was approved by the Court on September 12,
2011.
II. PGE'S BOARDMAN ADJUSTMENT TARIFF
14. In late 2009, PGE filed a depreciation study with the OPUC requesting to
update depreciation lives, curves, and net salvage rates for its plant accounts. Because
PGE was in the process of developing its IRP portolio analyses at the time the
depreciation study was filed, and the Boardman end-of-life date had not been
determined, the OPUC approved the new rates but indicated Boardman related items
would be addressed at a later time. In February 2010, PGE fied a general rate case
with the OPUC requesting a rate change effective January 1, 2011. Because the
general rate case filing occurred before PGE had amended its 2009 IRP to include the
2020 Boardman closure date, PGE's test year expenses included depreciation rates
and projected decommissioning costs for Boardman that assumed a December 31,
2040, end-of-Iife date. The filing also included a proposal for the Boardman Power
APPLICATION - 8
Plant Operating Life Adjustment Tariff ("Boardman Adjustment Tariff"), which is a
mechanism that would allow for an update in rates to include the incremental revenue
requirement resulting from a change in the Boardman end-of-Iife date. The mechanism
is intended to capture annual changes to depreciation expense, amortization expense,
and associated Schedule M and rate base adjustments until costs are incorporated into
rates during a general rate case proceeding. The mechanism currently does not take
into account capital costs associated with pollution control upgrades required at
Boardman. The OPUC approved the Boardman Adjustment Tariff on December 17,
2010, with a zero dollar rate until a final determination was made on the Boardman
closure date.
15. With "Boardman through 2020" recommended as the preferred portolio
and OPUC acknowledgement of this plan, PGE hired Black and Veatch ("B&V") to
conduct a new decommissioning study based on the December 31, 2020, closure. In
March 2011, B&V provided an initial estimate of total decommissioning costs less
salvage of approximately $80 million in 2010 dollars. PGE Advice 11-07 Staff Report, p.
3. On April 4, 2011, PGE submitted an advice filing with the OPUC requesting a seven-
month incremental revenue requirement increase of $9.3 millon associated with the
Boardman Adjustment Tariff. The rate request included the incremental depreciation
expense and additional decommissioning costs associated with the Boardman
December 31, 2020, closure. The advice filing was approved by the OPUC effective
July 1, 2011.
APPLICATION - 9
iv. IDAHO POWER'S BOARDMAN PLAN
16. As a 10 percent owner in Boardman, Idaho Power is directly impacted by
PGE's decision for a 2020 closure. In addition to providing the Commission with
information regarding PGE's evaluation of Boardman's need to meet Oregon emission
reduction rules, this filng is intended to detail Idaho Power's proposed plan for
responding to the 2020 decommissioning of Boardman. The Company does not
request recovery of any incremental costs associated with the Boardman closure at this
time. However, Idaho Power requests that the Commission acknowledge its support for
a proposed regulatory and accounting plan for responding to the plant closure. The
Company respectfully requests acknowledgement of support of the plan by mid-
February 2012 to allow time to prepare necessary regulatory filings.
17. In response to PGE's currently approved plan for a 2020 shutdown of
Boardman, Idaho Power has developed a proposed regulatory and accounting strategy
that involves three primary steps. First, the Company plans to begin a new depreciation
study that it will file with the Commission in early 2012. This filing wil request new
depreciation rates for all plant investment, including Boardman, to become effective
June 1, 2012. Second, the Company proposes the establishment of a balancing
account to track the incremental costs and benefits that wil exist as a result of the
Boardman shutdown. Third, the Company plans to file a request with the Commission
in early 2012 for authorization to increase customers' rates to recover future Boardman
decommissioning costs to become effective June 1, 2012, coincident with the change in
depreciation rates.
APPLICATION - 10
v. DEPRECIATION STUDY
18. Boardman's depreciation rates were established as part of Idaho Power's
most recent depreciation study, which was performed in 2008 based on December 31,
2006, plant values. Both the Commission and the OPUC have instructed the Company
to file depreciation studies approximately every five years, with the next study
scheduled for 2013. However, in light of Boardman's early closure and the soon to be
completed 330 megawatt Langley Gulch Power Plant, the Company has retained a
consultant, Gannett Fleming, Inc., to perform a depreciation study. This study wil
evaluate all plant accounts, acknowledging the closure of Boardman in 2020 and
associated decommissioning costs. Idaho Power anticipates filng a request for new
depreciation rates for all plant accounts in early 2012, with a change in rates requested
to occur June 1,2012.
19. Currently, depreciation rates associated with Boardman plant accounts
include a portion related to estimated net salvage values of Boardman facilities as of
December 31,2040. The net salvage component of the depreciation rate is intended to
minimize potential stranded costs at the time of final retirement but does not include
specific decommissioning costs. Rather, the estimated Boardman decommissioning
costs are accounted for as an Asset Retirement Obligation ("ARO") under Financial
Accounting Standards Board Accounting Standards Codification ("ASC") 410. In
accordance with IPUC Order No. 29414, Idaho Power records, as a regulatory asset,
the cumulative financial statement impact resulting from the Company's implementation
of ASC 410 (previously Statement of Financial Accounting Standards 143), and the
ongoing annual differences between the ASC 410 depreciation and accretion expenses
APPLICATION - 11
and the annual depreciation expenses that are currently authorized by the Commission
in depreciation rates and reclamation accruals. With the change in the Boardman
closure date and an updated decommissioning study, the Company now has a more
accurate estimate of expected decommissioning costs. In their 2011 study, B&V
assumed a December 31,2020, decommissioning of Boardman and based costs on the
assumption that the site would be returned to the same conditions that existed prior to
its construction. As described by PGE:
In addition to the main power block, the ancillary facilties to
be decommissioned include offices, shops, warehouses,
evaporative lagoons, settling ponds, the water supply well,
the coal storage area, coal handling facilities, the ash
disposal area, Carty reservoir, a 15-mile rail spur, several
miles of the privately-owned portion of Tower Road, and two
17 -mile transmission lines3. The estimate also includes all
currently known disposal and environmental clean up costs.
As part of the study, B&V calculated the scrap value of all
useful metals and materials and used this value to offset
overall decommissioning costs.
PGE Advice 11-07, p. 4
20. In its revenue requirement calculation, PGE included the straight-line
recovery of the future value of the projected decommissioning costs with the exception
of two items from B&V's decommissioning cost estimate because it felt there was too
much uncertainty around the following items: costs for decommissioning the ash pile
and remaining coal supply costs. PGE's rationale for adjusting current rates to recover
future decommissioning costs is based on the premise that current customers receiving
the benefits of Boardman's generation will be the same customers that pay for the costs
to decommission the plant. This matching approach, which was ultimately approved by
3 PGE has subsequently decided that no transmission lines associated with the Boardman plant
will be decommissioned.
APPLICATION - 12
the OPUC, is also the methodology preferred by Idaho Power. The Company will
continue to estimate its share of decommissioning costs using the decommissioning
costs by multiplying PGE's total estimate and applying the Company's 10 percent
ownership percentage.
Vi. BOARDMAN BALANCING ACCOUNT
21. Based upon PGE's plan to cease operations of Boardman in 2020, Idaho
Power expects to incur incremental costs associated with the accelerated depreciation
of the plant, new investment related to pollution controls, and costs associated with the
decommissioning of the plant.4 While the incremental depreciation expense for current
.investment is easily calculated based upon the current shutdown timeline, the specific
level of investment in capital additions, actual decommissioning costs, and potential
salvage proceeds are not yet known. With the approval of PGE's Boardman shutdown
plan by the OPUC and the EPA, the incremental cost impacts are certain to occur.
However, the exact impact is not yet known. For that reason, Idaho Power proposes
the establishment of a balancing account that would allow flexibility for the timing and
recovery of the incremental revenue requirement. A balancing account would allow for
the tracking, on a cumulative basis, of the difference between revenues and expenses
associated with the Boardman shutdown and ensure that customers pay no more and
no less than the actual expenditures.
22. In addition to providing a mechanism to track the revenue requirement
impacts associated with Boardman, a balancing account would likely mitigate the
possibilty that the shutdown of Boardman in 2020 would result in impairment under
4 There may be opportunities to continue serving customers with a different fuel at the Boardman
site. For example, PGE is investigating the possibility of using giant cane as a biofuel.
APPLICATION - 13
FASB Accounting Standards Codification ("ASC") 360, Property, Plant and Equipment.
ASC 360 states that an impairment loss shall be recognized if the carring amount of a
long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a
long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows
expected to result from the use and eventual disposition of the asset. Under ASC 360,
Idaho Power would potentially be required to record an impairment loss if not allowed to
recover the full amount of the Boardman-related balances, and thus having an adverse
financial impact on the Company.
23. In addition, ASC 980-360-35 states that when it becomes probable that an
operating asset wil be abandoned, the cost of the asset must be removed from plant-in-
service and set up as a regulatory asset and any disallowed amount be recognized as a
loss. Idaho Power concluded that the decision to shutdown Boardman by December
31, 2020, is not an abandonment of Boardman; rather, it is an adjustment to
Boardman's useful life. Adjustments to the useful life of Boardman have previously
occurred in 2001 from an original end-of-Iife date of 2015 to 2020 and most recently in
2008 to an end-of-Iife date of 2030. If, however, Idaho Power is not allowed to collect
the Boardman plant-related balances by the end-of-life date of December 31, 2020,
Idaho Power could be required to account for the Boardman plant as an abandonment,
which would also trigger impairment treatment under ASC 360.
24. Idaho Power has prepared a preliminary estimate of a revenue
requirement using a 2012 test year that includes impacts resulting from the accelerated
depreciation of the Boardman plant accounts and from increased decommissioning
costs. Incremental depreciation expense was based on expected December 31, 2011,
APPLICATION - 14
plant balances and the decommissioning costs were calculated using Idaho Powets 10
percent share of the costs PGE found reasonable in the B&V study. The preliminary
estimate results in a revenue deficiency of approximately $1.45 milion on a total system
basis, or $1.38 millon for the Idaho jurisdiction (see Attachment No.5).
VII. SUMMARY OF ATTACHMENTS
25. Attachment No. 1 to this Application is a copy of the Boardman Analysis
(Chapter 12) included in PGE's 2009 IRP.
26. Attachment NO.2 to this Application is the Boardman Analysis (Chapter
12A) of PGE's 2009 IRP Addendum.
27. Attachment NO.3 to this Application is a copy of Order No. 10-457, the
OPUC's acknowledgment of PGE's 2009 IRP, including the Addendum.
28. Attachment NO.4 to this Application is a copy of the EPA's approval of the
revision to Oregon's Clean Air Act State Implementation Plan.
29. Attachment NO.5 to this Application is the preliminary estimate of the
Idaho jurisdictional revenue deficiency resulting from the accelerated depreciation of the
Boardman plant accounts and the increased decommissioning costs.
VII. MODIFIED PROCEDURE
30. Idaho Power believes that a hearing is not necessary to consider the
issues presented herein and respectfully requests that this Application be processed
under Modified Procedure; Le., by written submissions rather than by hearing. RP 201
et seq. If, however, the Commission determines that a technical hearing is required, the
Company stands ready to present its testimony and support the Application in such
hearing.
APPLICATION - 15
ix. COMMUNICATIONS AND SERVICE OF PLEADINGS
31. Communications and service of pleadings with reference to this
Application should be sent to the following:
Jason B. Wiliams
Lisa D. Nordstrom
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
jwilliamscæidahopower.com
Inordstromcæidahopower.com
Courtney Waites
Greg Said
Tim Tatum
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
cwaitesß?idahopower.com
gsaid ß?idahopower.com
ttatumß?idahopower.com
X. CONCLUSION
32. PGE's currently approved plan for the 2020 shutdown of Boardman
represents a reasonable combination of least-cost and least-risk compliance with the
Federal Clean Air Act requirements. This plan wil bring with it certain increased
revenue requirements for Idaho Power-related to accelerated depreciation expense,
additional plant investments, and decommissioning costs. Therefore, Idaho Power
requests that the Commission acknowledge its support for the Company's proposed
regulatory plan and grant the Company's request to establish a balancing account to
track incremental costs and benefits associated with Boardman decommissioning and
shutdown activities.
XI. REQUEST FOR ACCEPTANCE
33. Idaho Power respectfully requests that the Commission issue an Order by
mid-February 2012 (1) authorizing that this matter may be processed by Modified
Procedure, (2) accepting the Company's Boardman plan as set forth above, and (3)
APPLICATION - 16
approving the establishment of a balancing account to track costs and benefits
associated with the early shutdown of Boardman.
DATED at Boise, Idaho, this 26th day of September 2011.
¿~rJASON aïL ~
Attorney for Idaho Power Company
APPLICATION - 17
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO.IPC-E-11-18
IDAHO POWER COMPANY
ATTACHMENT NO.1
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
12. Boardman Analysis
Boardman is a key resource for PCE. It is a low-cost, baseload plant that enables
us to provide 15% of our customers' energy needs with a reliable, stable source of
power. The plant also contributes to the diversity of our supply mix. Due to
efficiency upgrades, Boardman is in the top quintile among U.s. coal plants for
efficiency (heat rate) in convertig fuel to electricity. Those same upgrades mean
that many of the major components of the plant are comparatively new making it
likely that Boardman wil continue to operate reliably and efficiently for many
years into the future.
In this chapter we describe the emissions controls required under the recently
approved Oregon Regional Haze Plan and the Oregon Utility Mercury Rules. We
also describe how our scenario and stochastic analyses indicate that the best
combination of expected costs and associated risks and uncertainties for our
customers is achieved in a portfolio in which PCE invests in the required
emissions controls and continues to operate Boardman through 2040.
291
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
12.1 Boardman Plant Overview
Boardman is a pulverized-coal plant located in north-central Oregon
approximately 13 miles southwest of the city of Boardman, and 160 miles east of
Portland. It went into service in 1980. Its expected plant life extends through at
least 2040. Coal for Boardman is transported by rail from the Powder River Basin
(PRB) coal mines of central Wyoming. PGE is the operator of the plant, and we
have a 65 percent ownership interest, or 380-MW share of the plant output.
Forecasted average annual energy availabilty for PGE's share is 318 MWa. The
585-MW net capacity output serves the equivalent of about 341,500 residences.
The Boardman area was chosen for the plant's location because it has good
access to land, water, transmission and rail transportation. A large cooling pond,
Carty reservoir, was built to provide cooling water for the plant. The pond
eliminates the need for returning cooling water to natural streams or rivers, thus
avoiding discharge that might impact fish and wildlife. It also minimizes the
draw on river water.
The fuel is a low-sulfur sub-bituminous coal, primarily from the PRB mines. Coal
is transported to the plant by railcar. Boardman can stockpile up to 400,000 tons
of PRB coal at the on-site coal yard, the equivalent of 55 days at full operations.
Boardman typically shuts down once a year in the spring to perform its annual
planned maintenance. The plant is primarily a base-load resource, but is
economically dispatched during some periods where regional loads and prices
are low. Economic dispatch and load cycling generally occurs only in the spring.
12.2 Oregon Regional Haze Plan
Section 169A of the Federal Clean Air Act (as implemented through 40 CFR
51.308) requires that Oregon adopt and implement a plan to reduce visibilty
impacts in designated areas (referred to as Class I areas) to background levels by
2064. Oregon's plan to achieve this visibilty goal is referred to as the Oregon
Regional Haze Plan or the Plan. The Oregon Department of Environmental
Quality (DEQ) issued a draft Oregon Regional Haze Plan for public comment in
December 2008. The Plan included rules that would require specific emission
reductions at the Boardman plant by dates identified in the proposed rules.
During the public comment period PGE proposed an alternative approach
whereby PGE would have to decide, at dates certain, to either proceed with the
next phase of controls or cease operations at the Boardman plant by a specific
date after the date that controls were otherwise required. This plan would have
provided PCE the flexibilty to address the general uncertainty associated with
future electric prices and potential changes in legislation impacting generation.
292
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Specifically, it would have allowed PGE to consider though future IRP
processes the cost-effectiveness of implementing the controls in light of changes
to natural gas and coal prices, as well as C02 allowance prices.
The added flexibilty would have enabled PGE to have access to better
information about gas, coal and carbon prices at the time the investment decision
would be made, thus reducing the financial risk to customers. PGE's proposal
recognized that time is the only effective hedge against the uncertainty
surrounding upcoming carbon legislation as well as the commodities markets.
On June 19, 2009 the Environmental Quality Commission (EQC) adopted DEQ's
proposed Oregon Regional Haze Plan, as modified in response to public
comment. The Oregon Regional Haze Plan, as adopted, did not include PGE's
proposal and largely consisted of the approach DEQ proposed for public
comment. The Oregon Regional Haze Plan requires the installation of
environmental controls at the Boardman plant for the purpose of reducing
visibilty - impairing emissions.
The Plan calls for a two-phase approach identified as Phase 1 - Best Available
Retrofit Technology and Phase 2 - Reasonable Progress. Phase 1 (OAR 340-223-
0030) requires compliance with a reduced nitrogen oxides (NOx) limit by 2011
and a reduced sulfur dioxide (S02) and particulate matter (PM) limit by 2014.
The NOx limit was based on the assumption that PGE would install combustion
controls (low-NOx burners and modified over-fired air or LNB/MOFA). If
compliance with this limit is not demonstrated by July 1, 2012, then DEQ can
grant an extension until July 1, 2014 under the condition that the emissions meet
a more restrictive NOx limit. The S02 and PM limits are based on the installation
of semi-dry flue gas desulfurization (scrubbers) with an associated fabric filter.
Phase 2 (OAR 340-223-0040) requires compliance with a further-reduced NOx
limit by 2017. This limit was based on the assumption that PGE would install
selective catalytic reduction (SCR).
Under these rules, PGE has the following options:
· Install all of the controls: LNB/MOF A by July 2011, scrubbers/fabric filter
by July 2014 and SCR by July 2017 and operate Boardman through 2040
or beyond.
. Install LNB/MOF A and scrubbers and cease Boardman operations in
2017; do not make the SCR investment.
· Install LNB/MOFA only and cease Boardman operations in 2014.
. Cease Boardman operations in July 2011 with no obligation to install
additional controls.
293
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Non-compliance with the Oregon Regional Haze Plan (and also Oregon Utility
Mercury Rule) is, however, not an option. The plant must meet emissions
requirements by either installation of controls or by ceasing operations. Failure to
comply with the plan can result in significant penalties, equitable remedies, and
possibly criminal sanctions.
12.3 Oregon Utility Mercury Rule
In addition to the Oregon Regional Haze Plan, Boardman is also subject to the
Oregon Utilty Mercury Rule. PGE conducted a detailed engineering cost
analysis as well as a study on the impact these modifications wil have on
operating and maintenance costs once installed. When the Oregon Utility
Mercury Rule was first adopted, DEQ PGE and the public anticipated that the
mercury limits would take effect at the same time as the Oregon Regional Haze
Plan requirements. This expectation arose from the Department's intent to
establish a multi-pollutant strategy whereby mercury, sOi, and particulate
matter (PM) would all be addressed by an integrated control system. However,
delays in the development of the Oregon Regional Haze Plan have resulted in
the S02 scrubber and PM control compliance date being extended to July 1,
2014-two years after the date that the mercury emission standards take effect.
The mercury rule revisions adopted by the Environmental Quality Commission
(EQc) on June 19,2009, authorize a two-year compliance extension in the event
that it is not practical for PGE to install mercury controls by July 1, 2012, due to
supply limitations, electrostatic precipitator (ESP) fly ash contamination or other
circumstances beyond PGE's control.
However, based on pilot testing results, PGE determined that the injection of
activated carbon upstream of the existing ESP is most likely to result in the
capture of at least 90 percent of the mercury contained in the coaL. While ths
control approach is not optimal on a long-term basis, as there is material risk of
rendering the ash unsellable, the approach enables PGE to substantially decrease
mercury emissions prior to the time when a fabric filter can be installed.
Therefore, PGE is submittng for DEQ approval a mercury reduction plan in
accordance with OAR 340-228-0606(1). PGE believes that this plan complies with
all rule requirements and wil enable a high level of mercury control in reliance
on the existing ESP until such time that the scrubbers and associated fabric fiter
is installed consistent with the Oregon Regional Haze Plan. At that time, the
activated carbon injection point wil be moved to enable collecton of the carbon
(and mercury) in the fabric filter. The costs of this approach were included in our
modeling.
294
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
12.4 Boardman Portfolio Analysis
As part of the IRP overall economic analysis, each of the Boardman-related
controls technologies and associated deadlines were modeled in AURORAxmp
as distinct portfolios. Boardman-specific assumptions in these portfolios are
listed below by the following assumed plant run-through dates:
. 2040: Install all of the controls: LNB/MOF A by July 2011, scrubbers by
July 2014 and SCR by July 2017 and operate Boardman through 2040 (the
"Diversified Thermal with Green" and "Diversifed Green with on-peak
Energy Target" portfolios).
. 2017: Install LNB/MOFA and scrubbers; cease Boardman operations in
mid-2017; no SCR investment. Assumes the addition of a CCCT for
energy replacement in 2017 ("Boardman through 2017").
. 2014: Install LNB/MOFA; cease Boardman operations in mid-2014; no
further emissions controls investment. Assumes a CCCT for energy
replacement online in 2015 (earliest online date for a greenfield CCCT),
with market power purchases to bridge through remainder of 2014.
("Boardman through 2014").
. 2011: Cease Boardman operations in July 2011 with no obligation to
install additional controls. Assumes a fixed price power purchase
through 2014 as a bridge strategy, and then the addition of a CCCT in
2015. ("Boardman through 2011").
Except for the above-noted differences, all of these portfolios are built on the
"Diversified Thermal with Green" portfolio assumptions as the starting point.
PGE used both scenario (deterministic) as well as stochastic analyses in
evaluating the Boardman portfolios. For the scenario analysis, PGE uses
AURORAxmp to calculate a Net Present Value of Revenue Requirements
(NPVRR) for each portfolio under 21 differing potential futures, starting with a
reference case. For the stochastic analysis, PGE "shocks" the following five input
variables: WECC-wide load, natural gas prices, historic water years (for PGE
only), plant forced outages, and the intermittency of wind production. Detailed
descriptions of our portfolios and analytical approach are in Chapter 10.
12.5 Results of Portfolio Analysis
Please refer to Chapter 10 for a detailed description of our portfolio analysis
approach.
295
PCE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Deterministic Portolio Analysis Results
The Trade-off between Expected Cost and Associated Risk
The relationship between expected costs and the associated risk of each portfolio
provides a good way to quickly assess the relative performance of portfolios. In
this IRP, for each portfolio PCE uses the expected NPVR from the reference
case future as the measure for expected cost (plotted on the X-axis in Figure 12-1)
and the average NPVRR of the four worst futures as the measure for portfolio
cost risk (plotted on the Y-axis in Figure 12-1). Portfolios that for a given level of
risk have the lowest cost, or for a given cost have the lowest risk, are deemed to
be efficient. 92 Visually, portfolios that plot closer to the origin generally
outperform portfolios located further from the origin.
Figue 12-1: Efficient Frontier for Boardman Portfolios
35,500
35,250
'" c 35,000l! 0.a ;:::Eu.- ..
~ i:34,750
~ g;
v 0-
Õ Z 34,50011 0Ol .,~ 011 ~'" 0"l N 34,250
34,000
Boardman through 2017
I! Boardman though 2011
41 Boardman through 2014
to
Diversified Green with On-
peak Energy Target
33,750
$27,750 $28,000 $28,250 $28,500 $28,750 $29,000 $29,250 $29,500
Base Case NPVRR, 2010-40, $ milion
92 Whle ths is not the same as an efficient frontier as defined in financial portfolio theory, the
concept of looking at the trade-off between a return (or cost in this case) and its associated risk is
similar. Thus, at times we refer to a portfolio as being on an efficient frontier, meaning that the
portfolio performs better than others when considering both expected cost and risk.
296
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Three of the five Boardman portfolios are efficient. Portfolios titled "Diversified
Thermal with Green" and "Boardman through 2014" outperform the third
efficient portfolio "Diversified Green with On-peak Energy Target" based on
expected cost. As a result, we focus on them. The remaining portfolios
"Boardman through 2011" and "Boardman through 2017" proved to be both
more costly and risky, and therefore are not efficient. When compared to
"Diversified Thermal with Green," these two portfolios are both more costly and
more risky (by more than $100 milion and $300 milion respectively). When
compared to "Boardman through 2014", expected costs for these two portfolios
are almost $200 milion greater. These portfolios also have a higher risk by more
than $100 milion.
The "Diversified Thermal with Green" and "Boardman through 2014" both
outperform the other Boardman choices. Between these two choices, "Boardman
through 2014" has a lower expected cost by $81 milion, while performing worse
on the risk measurement by approximately $200 milion. For every dollar of
expected cost incurred by choosing "Diversified Thermal with Green" over
"Boardman through 2014", risk exposure can be reduced by roughly $2.20. In
other words the risk differential is more than two times the cost differential.
On the graphs in this section, for comparison, we also show our two top-
performing portfolios with Boardman operating through 2040, "Diversified
Green with On-Peak Energy Target" and "Diversified Thermal with Green".
Portfolio Durability: Combined Probability of Achieving Good and Avoiding
Bad Outcomes
Although the deterministic approach to portfolio analysis does not assign
probabilties to the likelihood of a particular future taking place, one way to look
at portfolio durabilty is to count the frequency of good outcomes vs. bad
outcomes. A bad outcome is defined as the number of times that a given
portfolio ranks among the worst four out of the 15 portfolios we tested against all
21 futures. And conversely, a good outcome is defined as the number of times
that a given portfolio ranked among the best four out of the 15 portfolios we
tested against all 21 futures. The goal is to avoid bad outcomes while seeking
good outcomes.
Better portfolios have a high probabilty of combined good vs. bad outcomes. In
our scoring, a portfolio that always ranked in the top four would get a 100%
score, a portfolio that always ranked in the bottom four would get a -100%.
Mediocre portfolios that had mixed results would score 0%. The same two
portfolios that lie on the efficient frontier ("Diversified Thermal with Green" and
"Boardman through 2014") also outperform all other Boardman options in this
metric - see Figure 12-2. "Boardman through 2014" and "Diversified Thermal
297
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
with Green" resulted in scores of 67% and 76% respectively, meaning that these
portfolios are comparatively durable when evaluated against most futures. On
the other hand, "Boardman through 2011" and "Boardman through 2017" both
resulted in a score of 0%.
Figue 12-2: Combined Probabilty of Good and Bad Outcomes for Boardman
Portolios
80%
70%
600/
l 50%i..
5 40%
~
~
:. 30%
20%
10%
0%
Diversified Greenwitl On- Diversified Thermal with Boardman through 2014 Boardman thrugh 2017 Boardman through 2011
peak Energy Target Green
Scenario Risk Magnitude
This metric addresses the magnitude of adverse outcomes. It is the cost
difference between the reference case performance of a given portfolio vs. the
average performance within the four worst futures for each portfolio. The best
portfolio would have the lowest score for this metric. "Diversified Green with
On-Peak Energy Target" performs best when compared to other Boardman
alternatives with a portfolio risk magnitude of $5 bilion. Second best is
"Diversified Thermal with Green" with a risk magnitute of $6.2 bilion,
"Boardman through 2014", "Boardman through 2011" and "Boardman through
2017"have a similar risk magnitude of approximately $6.5 bilion.
298
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Summary of Results from Deterinistic Measures:
Our portfolio scoring includes three measurement categories from the
deterministic portfolio analysis: Expected Cost, Risk Durabilty and Risk
Magnitude (Risk Magnitude includes Average of the four worst cases, as well as
Average of the four worst cases vs. Reference Case). In all, four deterministic
measurements comprised 70% of the combined score (see Table 12-2). Both
"Diversified Thermal with Green" and "Boardman through 2014" perform
materially better than "Boardman through 2011" and "Boardman through 2017"
with respect to the deterministic portion of the score. "Boardman through 2014"
slightly outperforms "Diversified Thermal with Green" by 1% of the
deterministic portion of the score.
Stochastic Portfolio Analysis Results
By stochastically modeling WECC-wide load, natural gas prices, historic water
years, plant forced outages and the intermittency of wind production, we were
able to assess probabilstic metrics of Boardman portfolio risks. As detailed in
Chapter 10, the portfolios were run 100 times subject to stochastic variations in
the above variables. For stochastic analysis, we employ a NPVRR TailVar less
Mean to look at portfolio risk over our dispatch modeling horizon of 2010 to
2040, as well as a year-to-year variabilty metric.
TailVar 90 less Mean:
This metric measures the right-tail risk or magnitude of bad outcomes for each
individual portfolio, as measured by averaging the portfolio NPV that resides in
the most expensive 10% of the distribution (right tail risk) and subtracting from
this the portfolio mean NPV (Le., expected cost). The result is a measure of how
widely a portfolio can deviate from its expected cost.
The "Diversified Thermal with Green" portfolio has a TailVar 90 less Mean
amount of $7.2 bilion compared to $8.4 bilion, $8.3 bilion and $8.2 for
"Boardman through 2014", "Boardman through 2011" and "Boardman through
2017" respectively - see Figure 12-3. "Diversified Thermal with Green"
outperforms the other Boardman alternatives by more than $1 bilion on average.
These results show the increased risk exposure when moving from coal as a fuel
to a greater concentration of natural gas, which has more volatile prices.
299
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Figue 12-3: Stochastic Risk - TaiVar less Mean for Boardman Portfolios
Boardman through 2014
Boardman through 2011
Boardman through 2017
Diversified Thermal with
Green
Diversified Green w ith On-
peak Energy Target
o 1 2 3 4 5 6 7 8 9
TailVar less Mean - $Billons
Stochastic Year-to-Year Variation
This metric addresses the innate volatility of a given portfolio. It measures the
average year-over-year variation, based on 100 independent iterations of the
stochastic inputs. While the "TailVar less mean" measures the worst 10%
possible outcome of the expected portfolio costs over the 31 forecast years, the
"Year-to- Year Variation" metric measures changes in year-to-year portfolio costs.
In other words, "TailVar less Mean" measures "how bad can the worst outcomes
be?" over the life of the portfolio while "Year-to-Year Variation" measures "how
bumpy is the road?" for a particular portfolio.
The best portfolio would have the lowest year-to-year variation. As shown in
Figure 12-4 below, "Diversified Thermal with Green" outperforms the other
Boardman portfolios with an expected variation of 21 trilion compared to
"Boardman through 2014", "Boardman through 2011" and "Boardman through
2017" all with expected variations exceeding 24 trilion.
300
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Figue 12-4: Stochastic Risk - Year-to- Year Vanation for Boardman Portfolios
Boardman through
2014
Boardman through
2017
Boardman through
2011
Diversified Green with
On-peak Energy Target
Diversified Thermal
with Green
o 5 10 15 20 25 30
Expected Variance. Trilions
Summary of Results from Stochastic Measures
We included in scoring thee measurement categories from the stochastic
portfolio analysis: TailVar, TailVar less Mean and Year to Year Variation.
Stochastic measurements comprised 10% of the total weighed combined score
(see Table 12-2). Diversified Thermal with Green performs materially better than
the other three Boardman portfolios by an average of 31 % of the stochastic
portion of the score.
Reliabilty and Diversity Analysis Results
Tailvar Unsered Energy
We calculate the Tailvar Unserved Energy (Tailvar UE) as the average of the
worst 10% of outcomes (across 100 iterations where PGE's plants are subject to
random forced outages and associated mean times to repair) of the amount of
power PGE must purchase on the spot market in order to meet customer load.
Expressed in MWa, market purchases are required when PGE's owned and
contracted resources are insufficient to meet customer load. This metric is
calculated as the average for all years from 2010 through 2020, plus 2025. The
higher the amount, the less reliable that portfolio is relative to the other
portfolios.
301
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
"Diversified Green with On-peak Energy Target" is the most reliable based on
the Tailvar and EVE metrics - see Figure 12-5. In our inputs, we assume that the
Boardman plant has a higher forced outage rate compared to a CCCT
replacement. The "Boardman through 2014" portfolio, fares somewhat worse
than the "Boardman through 2011" portfolio because the 2014 closure assumes
that PGE must rely on spot market purchases until a replacement resource can be
brought on-line.
Figure 12-5: Unserved Energy Metrcs for Boardman Portfolios, 2012-2020 & 2025
Boardman through 2014
Boardman through 2017
Boardman through 2011
Diversified Thermal with Green
Diversifed Green with On-
peak Energy Target
100 200 300 400 500 600
Energy Deficit (MWa)
Technology and Fuel Diversity
PGE has applied the Herfindahl-Hirschman Index (HHI), which has traditionally
been used to measure concentration of commercial market power. In this case,
the HHI is used to measure the portfolio concentration in technologies and fuels
(coal, natural gas, hydro, wind, market purchases, etc.) from 2010 through 2020.
A lower value means less portfolio concentration in any given technology or fuel
type over the period. A lower HHI value is preferred as it indicates higher
portfolio diversity and thus less exposure to fuel and generation technology
driven risks. The diversified portfolios outperform all of the early Boardman
closure portfolios from fuel and technological perspectives. See Figure 12-6 and
Figure 12-7 below respectively. While the early Boardman closure portfolios are
equivalent on a technological basis, the later closures perform better from a fuel
diversity perspective.
302
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Figue 12-6: Herfindahl-Hirschman Index Boardman Fuel Results
Boardman thru 2017
2,112
Diversified Green with On-
peak Energy Target
Diversified Thermal with
Green
Boardman thru 2014
Boardman thru 2011
500 1,000 1,500 2,000 2,500
Figue 12-7: Herfindahl-Hirschman Index - Boardman Technological Results
Boardman thru 2014
,718
Diversified Green with On-
peak Energy Target
Diversifed Thermal with
Green
Boardman thru 2011
Boardman thru 2017
500 1,000 1,500 2,000 2,500 3,000 3,00 4,000
Summary of Results from Reliabilty and Diversity Measures
We included in scoring three measurement categories from the reliabilty and
diversity portfolio analysis: Tailvar VE, Technology HHI and Fuel HHI.
Reliabilty and Diversity measures comprised 20% of the total weighed
combined score (see Table 12-1). Diversified Thermal with Green performs
materially better than the other three Boardman portfolios.
303
PCE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Other Metrics
At the recent suggestion of OPUC Staff, PGE has added a variation of two
metrics described above to its scoring. Rather than look solely at the
deterministic average of the worst four futures less the reference case expected
cost and the similar stochastic metric of TailVar 90 less the Mean, we have added
these two right-tail metrics as absolute measurements without subtracting from a
mean value. This allows for an absolute look at risk exposure without being
influenced by distance from the mean. These metrcs do not have a significant
impact on the top-performing portfolios, particularly given the relatively small
weights they have been assigned in the scoring matrix. Figure 12-8 shows the
average NPVRR for the four worst future outcomes. "Diversified Green with On-
peak Energy" has the lowest NPVR of the five cases, while "Boardman 2017"
shows the highest worst-case average.
Figure 12-8: Average NPVRR of Four Worst Futures
35,50
fA 35,25co
~
,5..
35,000
34,750
~~ 34,500
..Z
~~
:'
34,25
34,000
33,750
33,500
33,250
Diversifed Green with On- Diversified Therml with Boardman through 2014 Boardman through 2011 Boardman through 2017peak Energy Target Green
Portfolios
Similar results are shown in Figure 12-9 for the selected portfolios when looking
at the TailVar analysis. Here again "Diversified Green with On-peak Energy"
shows the lowest value, just over $28 bilion. The early Boardman closure
portfolios all have higher TailVar scores - with the earlier the closing, the worse
the outcome.
304
PCE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Figue 12-9: Stochastic Risk - TaiVar
Boardman through 2011
Boardman through 2014
Boardman through 2017
Diversified Thermal with Green
Diversified Green with On-peak Energy
Target
26 27 28 29 30 31 32
TailVar - $Billons
Primar Drivers of Uncertainty
Portfolios were stress-tested with several discrete futures. Of all the futures
tested, variation in natural gas price, C02 price and load growth had the most
impact on our portfolio NPVRR. Natural gas price was modeled with low,
reference and high price futures at $5.19, $7.86 and $12.84 (real levelized 2009$)
respectively. cOi prices ranged from $0 per short ton to $65 per short ton with a
reference price at $30 (real levelized 2009$) and non-EE adjusted load growth
rates were modeled at 1.21 % and 2.72% per year for low and high scenarios with
a reference growth rate at 1.91 %.
Figure 12-10 shows the "Diversified Thermal with Green" and "Boardman
Through 2014" portfolios' sensitivity to these futures. "Boardman Through 2014"
is more exposed to gas price risk than "Diversified Thermal with Green." This
portfolio assumes a CCCT as the replacement technology for Boardman past
2014. "Boardman Through 2014" has an expected NPVRR change from the
reference case gas price of $7.582 bilion compared to $6.636 bilion for
"Diversified Thermal with Green". For the same magnitude of natural gas price
increase (from $7.86 to $12.84, both real levelized in 2009$), "Boardman Through
2014" has an NPVR of $946 milion more than "Diversified Thermal with
Green."
305
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Figue 12-10: Boardman Portfolios' Sensitivity to Gas Prices
Diversifed Thermal with Green
2009$
Gas Prices
'"
2!=::U.
~ C02 Tax
..c...c..:t
Load Growth
-$6,00 -$4,000 -$2,000 $0 $2,000 $4,000 $6,000 $8,00
NPVRR Change from Reference Case
Sin milions
Boardman Through 2014
2009$
Gas Prices
'"
2!=::U.
~ C02 Tax..c...c'":t
Load Growth
-$6,00 -$,000 -$2,000 $0 $2,000 $4,000 $6,000 $8,00
NPVRR Change from Reference Case
$ in milions
"Diversified Thermal with Green" is more exposed to C02 risk. This reflects the
higher C02 output profile of a coal plant compared to a CCCT. Exposure to C02
price is $4.526 bilion for "Diversified Thermal with Green" and $4.003 bilion for
"Boardman Through 2014". Exposures to load growth are identical at $3.199
bilion for downside and $2.345 bilion on the upside for both portfolios.
Another insight from these graphs is the apparent asymmetry between upside
and downside exposure to gas price risk, while C02 price and load growth have
fairly balanced risk profiles. For "Diversified Thermal with Green" and
306
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
"Boardman through 2014," upside and downside of portfolio NPVRR for C02
price risk are +$4.526 vs. -$4.002 and +$4.003 vs. -$3.312 bilion respectively. But
for gas price risk exposure, the range is +$6.636 vs. -$3.662 and +$7.582 vs. -$4.076
respectively for those portfolios. This reflects the asymmetry of the high and low
natural gas prices as compared to the reference case price. Most natural gas price
forecasts (including PGE's) indicate that there is more risk that prices wil rise
rather than fall; this is a logical deduction with a log-normally distributed price.
Of the three major cost drivers, natural gas price risk emerges as the greatest
driver of the portfolio NPVRR and as a result, the single largest risk factor. C02
price is second and load growth is third. Load growth risk magnitude is identical
for both portfolios. "Diversified Thermal with Green," though more exposed to
C02 risk, performs better under a high gas price future than "Boardman Through
2014."
12.6 Assessing Boardman Analytical Results
The portfolio analysis, using both scenario and stochastic approaches, provides a
comprehensive look at Boardman's value and risks. PGE's recommendation
takes into account expected cost, as well as price and reliabilty risk. Overall,
"Diversified Thermal with Green" scored better than the Boardman 2014
portfolio - see Table 12-1 below. The "Diversified Thermal with Green" portfolio
which includes Boardman through 2040 also clearly outperformed the early
closure cases with respect to price risk and reliabilty. In general, although more
exposed to C02 costs, the "Diversified Thermal with Green" portfolio provides
an effective hedge against natural gas price volatility, while maintaining system
reliabilty at a relatively low cost.
307
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8
PCE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Other Considerations
There are other considerations that are not captured in our IRP portfolio scoring
but are relevant to the decision to invest in emissions controls at Boardman.
These considerations favor keeping the plant open through 2040.
As of this writing, if and when climate legislation is adopted by the Congress, it
appears that the most likely policy outcome is legislation that resembles the
Waxman-Markey bil. Legislation introduced in the Senate by Senators Kerry and
Boxer (S. 1733) on September 30, 2009 resembles Waxman-Markey in several
respects. Preliminary analysis of the September 30 version of S.1733 conducted
by EPA (published October 23, 2009) suggests that the economic impacts of the
bils wil be similar, with S.1733 resulting "sight" or "small" allowance price
increases due to differences in the bil provisions affecting the 2020 cap levels,
offset limits, strategic reserve, EE and renewable energy provisions and the CCS
bonus allowances. However, in order for the Senate to secure 60 votes for cloture,
additional negotiation and compromise can be expected including the possibilty
of adding a firm price collar for allowances.PGE's current reference case price is
$30 per short ton. The PGE reference case price is a composite of EPA and EIA
studies of legislative proposals and includes the EPA work on Waxman-Markey.
PGE's approach to assessing CÜ2 risk and selecting a reference case price is
described in greater detail in Chapter 6. Although the C02 price is unnown at
this point, ongoing discussions in the Senate about a price collar mechanism
could further diminish the probabilty of a higher C02 price.
In addition, it is reasonable to expect that operational changes and/or techology
advancements wil affect C02 reductions for coal-fired plants. These may include
biomass co-firing, biogenic C02 capture and recycling, and C02 capture with
geologic sequestration. PGE's algae sequestration pilot project (described in
Chapters 6 and 7) is a promising example. Improvements in C02 abatement
technology do not need to be specific to Boardman in order to benefit Boardman
economics. If development in such technology is accelerated due to an increase
in policy-based incentives, even if only available in other parts of the country,
PGE's customers wil benefit from such incentives since they would likely affect
CÜ2 prices. Furthermore, the availabilty of international offsets could put further
downward pressure on C02 prices.
Boardman Recommendation
With respect to Boardman emissions controls investments and the future
operations of the plant, the choices left to us as a result of the Oregon Regional
Haze Plan and Utility Mercury Rule are not optimal for our customers compared
to the other options that PGE proposed to the DEQ in its Decision Point Plan. In
309
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
addition, the process of evaluatig whether or not to invest in emissions controls
is both complex and challenging. As discussed above, however, non-compliance
with the Oregon Regional Haze Plan and Oregon Mercury rule is not an
alternative. We must also keep in mind that an appropriate course of action for
Boardman must be consistent with the objectives of the IRP - that is, to identify a
resource action plan, that when considered with our existing portfolio, provides
the best combination of expected cost and associated risks and uncertainties for
the utility and its customers. Given these goals, we recommend compliance with
the Oregon Regional Haze Plan and Oregon Mercury Rules in two phases:
Phase 1
. NOx Controls: install the LNB/MOF A control system which, as proposed,
is estimated to reduce NOx by 4,000 tons per year, for a 46% reduction
compared to current emission levels. These controls wil be installed by
July 2011 to meet the 0.28lb/MMBtu (30-day rollng average) and 0.23
lb/MMBtu (12-month rollng average) emissions limit. The estimated
overnight capital cost is $33 milion (100% of Boardman plant).
Engineering Procurement and Construction (EPC) work wil start in early
2010 to support the July 2011 schedule. We anticipate that it wil not be
necessary to request a compliance extension, thereby changig the dual
limits to a single 0.23 lb/MMBtu (30-day rollng average) emissions limit.
. Mercury Controls: install the mercury (Hg) control system by 2012 for an
estimated overnight capital cost of $7.7 milion (100% of Boardman plant).
. S02 Controls: install scrubbers, which wil cut S02 emissions by 12,000
tons per year for an 80% reduction compared to current emission levels.
These controls wil be installed by July 2014 to meet the 0.12 lb/MMBtu
30-day average emissions limit.
. Particulate Matter Controls: install a pulse jet fabric fiter as part of the
scrubber installation to supplement the existing electrostatic precipitator.
This installation wil cut particulate matter emissions by 122 tons per year
for a 29% reduction from current levels. These controls wil be installed
by July 2014 to meet the 0.012lb/MMBtu emissions limit. The particulate
matter controls, together with the scrubbers, are estimated to have
overnight capital cost of $289.9 milion (100% Boardman plant).
Phase 2
. NOx Controls: install Selective Catalytic Reduction (SCR), which wil cut
NOx emissions by an additional 4,000 tons per year for an additional 38%
reduction, beyond the Phase I upgrades. These controls wil be installed
310
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
by July 2017 to meet a 0.070 Ib/MMBtu emissions limit for an estimated
overnight capital cost of $180 millon (100% Boardman plant).
Table 12-2 below provides the dates by which equipment must be installed in
order for PGE to meet its compliance obligations. An all inclusive engineering,
procurement and constrction (EPC) approach is preferred, except for the Hg
controls. Delay in meeting contract dates wil correspondingly delay the date
when equipment is operational and the plant can operate in compliance with the
Oregon Regional Haze Plan and Oregon Mercury Rule.
Table 12-2: Boardman Engineering Procuement and Constmction Schedule
EQC EPC
Controls
Emission Compliance Date Contract Date
1.LNB/OFA July 2011 Feb 2010
2.Mercury July 2012 Q2-2011
3.FGD July 2014 Q1-2011
4.SCR July 2017 Q1-2014
Table 12-3 below summarizes the capital costs associated with each of the DEQ's
recommended emissions controls; capital costs in this table are for 100% of the
Boardman plant output. Installation of the new systems is expected to take place
during our normally scheduled spring maintenance outages.
311
PCE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
Table 12-3: Boardman Emissions Controls Capital Costs, Nominal $
With all controls in place in 2017, total fixed and variable O&M for PGE's 65%
share of Boardman is projected to increase by approximately $8.1 milion in 2009
$. About two-thirds of this amount is variable O&M. At the same time, the net
plant heat rate is projected to increase by about 2% and plant output is projected
to decrease by the same percentage. The ongoing impacts to the dispatch cost
due solely to emissions controls (the variable O&M and change in heat rate) are
fairly modest. In 2017, when all controls are in place, the dispatch cost is
expected to increase by approximately $3 per MWh in 2009 $ exclusive of C02
costs.
This analysis is based on PGE's cost of capitaL. Tax-favored pollution control
bond financing, if available, could improve the economics. Our modeling
assumes no extension of the Oregon Pollution Control Facilities Tax Credit
program, which currently does not benefit controls that were placed in service
after December 31, 2007.
The PGE Power Supply Engineering Services group and the Boardman plant
operations team are comfortable in this assessment of expected plant life and
believe it may, in fact, be conservative. There are many instances of thermal
plants operating well beyond their original book life and Boardman has a
number of relatively new major components or upgrades, including steam
312
PGE 2009 Integrated Resource Plan Chapter 12. Boardman Analysis
turbines, pulverizers and boiler tubing. Other scheduled replacements over the
next few years include generator components and burners.
In summary, PGE recommends proceeding with the Phase 1 and 2 emissions
control upgrades required under the Oregon Regional Haze Plan and the Oregon
Utility Mercury Rule, and retaining Boardman in our resource portfolio. This
recommendation is based on the results of our portfolio analysis, which indicate
that the portfolio which includes the operations through 2040, and the portfolio
that ceases plant operations in 2014 yield similar expected cost results. However,
the 2040 Boardman portfolio performs better across most risk metrics, including
price risk and reliabilty measures. The Boardman 2040 portfolio also provides
for increased fuel and technology diversity when compared to the early
shutdown cases. Further details regarding the results of our portfolio analysis
can be found in Chapter 11. Because of the importance of Boardman to PGE's
resource portfolio and the significant adverse consequences that would result if
PGE were not to comply with the Oregon Regional Haze Plan and Oregon
Mercury rule, it is imperative that the Commission act promptly in its review of
PGE's Integrated Resource Plan.
313
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO.IPC-E-11-18
IDAHO POWER COMPANY
ATTACHMENT NO.2
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
12A. Boardman Analysis
Boardman, a pulverized-coal plant located in north-central Oregon, is a key
resource for PGE and our customers. It is a low-cost, baseload plant that enables
us to provide 15% of our customers' energy needs with a stable fuel source and
also contributes to the diversity of our supply mix. Boardman is in the top
quintile among U.s. coal plants for efficiency (heat rate) in converting fuel to
electricity. Because Boardman has been well maintained, it is expected to have
continued reliable and efficient operations for the foreseeable future.
In this chapter we describe the emissions controls required under the recently
adopted Oregon Regional Haze Plan and the Oregon Utility Mercury Rules. We
also present a new emissions control and operating plan which PGE has
proposed in a petition to amend the existing Oregon Regional Haze Plan filed
with the Oregon Department of Environmental Quality (DEQ) on April 2, 2010
(BART II Petition). This new plan is incorporated via our "Boardman through
2020" portfolio, which forms the basis of our preferred Action Plan. This chapter
also provides detailed analysis of the different cases for Boardman emissions
controls and operations, including PGE's new proposal to implement a more
limited controls package in conjunction with a plan to cease coal-fired operations
at the plant in 2020.
Our analysis of the "Boardman through 2020" portfolio balances several
important objectives, including cost and risk for customers, system reliabilty,
meetig state and federal emissions standards, and reducing the impact of
electric generation on the environment. The portfolio also allows for an orderly
transition to replacement supply sources and reduces the impact of a change in
plant operations on affected communities and employees. The "Boardman
through 2020" portfolio is our preferred portfolio. However, as described in
detail in Chapter 13A, implementation of the "Boardman through 2020" portfolio
is dependent on the resolution of certain contingencies. Given the reliabilty and
cost risk to customers of a 2014 plant closure, as discussed later in this chapter,9
we are asking the Commission to acknowledge that is prudent for us to proceed
with an alternate Action Plan based on the Diversified Thermal with Green
portfolio (with or without lease), which continues Boardman operations through
2040 if contingencies are not resolved by March 31, 2011. The details of both our
preferred and alternate plans for Boardman are presented in the balance of this
chapter and in Chapter 13A.
9 In partcular, refer to the discussions immediately after Figure 12A-l and prior to Figure 12A-5.
87
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
12A.l Oregon Regional Haze Plan
As part of the implementation of the Federal Clean Air Act section 169A, the
Oregon Department of Environmental Quality (DEQ) issued a draft Oregon
Regional Haze Plan that was later adopted by the Environmental Quality
Commission (EQc) on June 19, 2009. The Oregon Regional Haze Plan requires
the installation of environmental controls as Best Available Retrofit Technology
(BART) at the Boardman plant for the purpose of reducing visibilty-impairing
emissions and additional environmental controls as Reasonable Progress (RP)
towards additional haze causing emissions reductions.
In addition to the Oregon Regional Haze Rule, Boardman is also subject to the
Oregon Utilty Mercury Rule. PGE has received DEQ approval of a proposed
approach whereby activated carbon is injected upstream of the
existing electrostatic precipitator in possible combination with calcium halide
additive on the coaL. This approach is expected to result in the capture of 90
percent of the mercury contained in the flue exhaust gases, enabling the plant to
meet the emissions standard under the Utilty Mercury Rule. While this control
approach increases the risk of rendering the fly ash unsellable, it provides an
overall cost benefit to PGE customers by substantially decreasing mercury
emissions while avoiding the installation of expensive fabric fiter equipment.
88
PCE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
12A.2 Current Regional Haze Plan Requirements
The current Regional Haze Plan requirements applicable to Boardman consist of
two phases: Phase 1 BART controls; and Phase 2 RP controls. Phase 1 compliance
requires installation of Low NOx Burner and Modified Over-Fire Air
(LNB/MOFA) and semi-dry flue gas desulfurization (scrubbers) with an
associated fabric fiter. Phase 2 requires the installation of selective catalytic
reduction (SCR). Under the existing Regional Haze Plan, PGE has the following
options:
Install all of the controls: LNB/MOF A by July 2011, scrubbers/fabric filter
by July 2014 and SCR by July 2017 and operate Boardman through 2040
or beyond (modeled in the "Diversified Thermal with Green" portfolios).
Install LNB/MOF A and scrubber/fabric filters and cease Boardman
operations in 2017; do not make the SCR investment (modeled in the
"Boardman through 2017" portfolio).
· Install LNB/MOFA only and cease Boardman operations in 2014
(modeled in the "Boardman through 2014" portfolio).
· Cease Boardman operations in July 2011 with no obligation to install
additional controls (modeled in the "Boardman through 2011" portfolio).
12A.3 BART II
On April 2, 2010, PGE submitted a Petition to amend the Oregon Regional Haze
Rule to the DEQ (BART II Petition). This BART II Petition seeks changes to allow
Boardman meet BART /R requirements through an alternate proposal that
utilzes a more limited emissions control upgrade package in conjunction with a
change in the plant's operation and a commitment to cease coal-fired operations
or shut down the plant in 2020. Under this proposed petition, PGE would cut
haze-causing emissions of sulfur dioxide and nitrogen oxides from the Boardman
plant by:
· Installng new, state-of-the-art LNB/MOFA burners by July 1, 2011. The new
burners are expected to reduce nitrogen oxides emitted by the plant by nearly
50 percent.
Using coal with a lower sulfur content to fire the plant's boiler. This would be
completed in two stages as PGE's current coal supply contracts expire. In
addition, PGE has recommended an initial 20 percent drop in permitted
sulfur dioxide emissions that would take effect in 2011. This is followed by a
further reduction in 2014 that would bring allowed sulfur dioxide emissions
down by a total of 50 percent from current permit levels.
89
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
Closing the plant in 2020, ending all coal-related emissions at least 20 years
ahead of schedule and significantly reducing Oregon's contribution to green
house gas emissions.
Under a separate rulemaking procedure with DEQ PGE already has agreed to
install controls that are expected to eliminate 90 percent of the plant's mercury
emissions by 2012. Current construction schedules should allow PGE to meet this
deadline a year early, in 2011.
Table 12A-l: Comparison of Existing vs. Proposed BART Rule
$7.7 Millon Jul-12
20
Reduced Sulfur Coal Restriction 1
Reduced Sulfur Coal Restriction 2
Selective Catalytic Reduction (SCR)
Mereu Controls
Aggregate Emissions tons)
Totals
. LbslMmbtu
"Costs are nominal Ca itl dollars and do not include AFDC and ro ert taxes
;~~~S:MJjJ1Qø:¿~
The concept of potentially closing Boardman early was first introduced by the
company in response to a December 1, 2008 DEQ proposed BART determination
for the Boardman Plant Boiler. During the public comment period the company
requested that DEQ consider allowing PGE to have options to forego certain
controls if the company committed to cease operation of the Boardman Plant
boiler by dates certain.
On June 19,2009, the Oregon Environmental Quality Commission (EQC)
adopted DEQ's proposed Oregon Regional Haze Plan which included extensive
emission controls. Although the EQC did not adopt the company's proposal it
did include in its adopted plan an express statement that "Should PGE determine
that the impact and cost of carbon regulations wil require the closure of the PGE
Boardman plant, PGE may submit a written request to the Department for a rule
change". In response to feedback from IRP stakeholders and further analysis of
the EQC ruling, the company began analyzing a portfolio with a 2020 closure of
the Boardman plant. Based on that feedback and analysis, as well as our belief
that such a portfolio could meet the emissions standards required under the
Regional Haze Program, PGE submitted the BART II request to DEQ.
While a DEQ schedule has not yet been established, the following is from the
DEQ press release of April 2, 2010:
90
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
DEQ officials wil study PGE's proposal and analysis to assess whether it
adequately addresses all the factors needed to comply with federal
regulations. If so, DEQ wil begin a new rulemaking process that wil
provide the opportunity for the public to review and provide comment.
Depending on the outcome of DEQ's review and public process it may be
possible to bring a proposed rule revision to the EQC for consideration by
the end of the year.
12A.4 Portfolio Analysis
Throughout the remainder of this chapter we focus on a set of portfolios that
represent five distinct emission control upgrade and operatig plan cases for
Boardman. Four of the portfolios, "Boardman through 2011", "Boardman
through 2014", "Boardman through 2017" and "Boardman through 2020"
represent early closure scenarios. The fifth case, "Diversified Thermal with
Green", represents a plan where all emissions controls required under the
current DEQ rules are implemented at Boardman and the plant is retained in
PGE's portfolio through 2040. Of the above portfolios, only "Boardman through
2020" represents a new case from those presented in PGE's November 2009 IRP
filing. This new portfolio provides a Boardman capital and operatig plan that is
consistent with our BART II Petition. The "Boardman through 2020" portfolio
includes the following primary elements:
Installation of LNB/MOF A in 2011;
The use of low sulfur coal to meet a 20% reduction in permitted 502
emissions by the end of 2011;
. Injection of carbon to eliminate 90 percent of the plant's mercury emissions
by 2012;
. The use of low sulfur coal to meet a 50% reduction in permitted 502
emissions by July 2014;
. Cessation of coal-fired operations of Boardman at the end of 2020;
. No further emissions control investments;
· Replacement of Boardman with a CCCT at the beginning of 2021.
In addition to the above components, please see Chapter lOA, section lOAA, for a
detailed description of the portfolio composition.
12A.5 Results of Portfolio Analysis
Please refer to Chapter lOA for a detailed description of our portfolio analysis
approach.
91
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
Deterministic Portfolio Analysis Results/
The Trade-off between Expected Cost and Associated Risk
Portfolios with a lower level of risk for a given amount of cost (or vise versa) are
deemed to be efficient. This is visually represented on an Effcient Frontier graph
where efficient portfolios are closest to the origin when plotting expected costs
(plotted on the X-axis) and portfolio risk (plotted on the Y-axis) measured by the
average NPVRR of the four worst futures. We originally presented an Effcient
Frontier graph in Figure 12.1 of our initial IRP. When the "Boardman through
2020" portfolio is added to the graph, as ilustrated in Figure 12A-1, it becomes
the best performer. This is a result of the fact that the "Boardman though 2020"
provides a better trade-off between cost and risk than any of the other four
portfolios. Following "Boardman through 2020", "Diversified Thermal with
Green" and "Boardman through 2014" provide the next best cost and cost risk
performance. However, "Boardman through 2014" also poses increased
implementation and replacement supply risk that is not reflected in the Efficient
Frontier Graph.
Figue 12A-l: Efficient Frontier for Boardman Portfolios
35,500
Risk
Boardman through 2011
35,250 I
cfI~l!=" E-.." ..II ..-Ne..~~..;:_ a.o Z....01..I! .... '1"'"q: -..N
Boardmanthugh2017
II Boardmanthrough2014
35,000
~ Diversified Therml with Green
Boardman through 2020
34,750
34,500
$28,000 $28,750 $29,000$28,250 $28,500
Base Case NPVRR, 2010.204, $2009 milion
This graph also demonstrates that "Boardman through 2020" outperforms the
other 4 portfolios on both expected cost and risk, by $197 milion in expected cost
92
PCE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
and $356 milion in cost risk compared to the next best early closure portfolio,
"Boardman through 2014".
Portfolio Durability: Combined Probability of Achieving Good and Avoiding
Bad Outcomes
Although the deterministic approach to portfolio analysis does not assign
probabilties to the likelihood of a particular future taking place, one way to look
at portfolio durabilty is to count the frequency of good outcomes vs. bad
outcomes. Our IRP analysis defines a bad outcome as the number of times that a
given portfolio ranks among the worst four out of the 16 candidate portfolios we
tested across 21 futures. And conversely, a good outcome is defined as the
number of times that a given portfolio ranked among the best four out of the 16
portfolios we tested across 21 futures. The goal is to avoid bad outcomes while
seeking good outcomes.
Better portfolios have a high probabilty of combined good vs. bad outcomes. In
our scoring, a portfolio that always ranked in the top four would get a 100%
score, a portfolio that always ranked in the bottom four would get a -100%.
Mediocre portfolios that had mixed results would score closer to 0%.
"Boardman through 2020" again outperforms the other four portfolios in this
metric - 81 % of the time it is in the top four performing portfolios through the 21
futures it was tested against.
Figue 12A-2: Combined Probabilty of Good and Bad Outcomes for Boardman
Portfolios
00"
70"
l 50"
I 30..
I
l!10".i
-10%
-30"
-50"
Portlio
93
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
Scenario Risk Magnitude
Scenario (deterministic) risk is measured by two metrcs; (1) the average NPVRR
of the four worst futures, and (2) the average NPVR of the four worst futures
less the reference case. The first metrc addresses the potential magnitude of
adverse outcomes. The second metrc measures the extent to which performance
could adversely change from the expected case. Performance according to the
first scenario risk metric is described above under the discussion regarding the
trade-off between risk and cost. Looking at the second of these two metrics,
"Diversified Thermal with Green", which retains Boardman through 2040,
performs best when compared to the other four Boardman alternatives.
Our portfolio scoring includes three measurement categories from the
deterministic portfolio analysis: Expected Cost, Risk Durabilty and Risk
Magntude (Risk Magnitude includes Average of the four worst cases, as well as
Average of the four worst cases vs. Reference Case). In total, these deterministic
risk measures comprise 70% of the overall portfolio score (see Table 12A-2).
"Boardman through 2020" performs best according to the combined
deterministic risk measures when compared to the other four Boardman
alternatives presented in this chapter.
Stochastic Portfolio Analysis Results
By stochastically modeling WECC-wide load, natural gas prices, historic water
years, plant forced outages and the intermittency of wind production, we were
able to assess probabilstic metrics of Boardman portfolio risks. As detailed in
Chapter lOA, the portfolios were run 100 times subject to stochastic variations in
the above variables. For stochastic analysis, we employ a NPVRR TailVar less
Mean to look at portfolio risk over our dispatch modeling horizon of 2010 to
2040, as well as a year-to-year variabilty metric.
TailVar 90 less Mean:
This metric measures the right-tail risk or magnitude of bad outcomes for each
individual portfolio, as measured by averaging the portfolio NPV that resides in
the most expensive 10% of the distribution (right tail risk) and subtracting from
this the portfolio mean NPV (i.e., expected cost). The result is a measure of how
widely a portfolio can deviate from its expected cost.
The "Diversified Thermal with Green" portfolio outperforms the other
Boardman alternatives by more than $1.2 bilion on average. These results show
the increased risk exposure when moving from coal as a fuel to a greater
concentration of natural gas, which has more volatile prices.
94
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
Figue 12A-3: Stochastic Risk - TailVar less Mean for Boardman Portfolios
Boardman through 2014
Boardman through 2011
Boardman through 2017
Boardman through 2020
Diversified Thermal with Green
2 3 4 5 6 7 8 9 10
TailVar less Mean - $Billons
Stochastic Year-to- Year Variation
This metric addresses the innate volatility of a given portfolio. It measures the
average year-over-year variation, based on 100 independent iterations of the
stochastic inputs. While the "TailVar less mean" measures the worst 10%
possible outcomes of the expected portfolio costs over the 31 forecast years, the
"Year-to-Year Variation" metric measures changes in year-to-year portfolio costs.
In other words, "TailVar less Mean" measures "how bad can the worst outcomes
be?" over the life of the portfolio while "Year-to-Year Variation" measures "how
bumpy is the road?" for a particular portfolio.
The best portfolio would have the lowest year-to-year variation. As shown in
Figure 12A-4 below, "Diversified Thermal with Green" outperforms the other
Boardman portfolios. "Boardman through 2020" is the next best performing
portfolio according to this risk metric.
95
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
Figue 12A-4: Stochastic Risk - Year-to- Year Varation for Boardman Portfolios
Boardman through
2014
Boardman through
2011
Boardman through
2017
Boardman through
2020
Dil.rsified Thermal
with Green
o 10 20 30 40 50 60 70
Expected Variance - $Trilions
Summary of Results from Stochastic Measures
We included three metrics from stochastic analysis in our portfolio scoring
methodology: TailVar, TailVar less Mean and Year to Year Variation. Stochastic
measurements comprised 10% of the total combined score (see Table 12A-2).
Again, the "Diversified Thermal with Green" portfolio performs materially
better than the other Boardman cases when considering stochastic cost risk.
Reliabilty and Diversity Analysis Results
Tailvar Unserved Energy
We calculate the Tailvar of Unserved Energy (Tailvar UE) as the average of the
worst 10% of outcomes (across 100 iterations where PGE's plants are subject to
random forced outages and associated mean times to repair) where PGE must
purchase power on the spot market in order to meet customer load. Expressed in
MWa, market purchases are required when PGE's owned and contracted
resources are insufficient to meet customer demand. This metric is calculated as
the average for all years from 2010 through 2020, plus 2025. The higher the
amount, the less reliable that portfolio is relative to the other portfolios.
According to the TailVar UE and EUE metrics "Boardman through 2011" has the
highest reliabilty - see Figure 12A-5. This is largely due to two factors; (1) our
model inputs assume a higher forced outage rate for Boardman than a CCCT
replacement, and (2) the 2011 portfolio includes a bridge PP A with a forced
96
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
outage rate equal to a CCCT. However, the TailVar UE and EUE results across
the five portfolios presented in Figure 12A-5 are relatively small, with little
overall difference in reliabilty performance for these cases.
It should also be noted that this analysis does not consider reliabilty risk
associated with securing replacement supply sources. It only assesses relative
reliabilty performance of candidate portfolios once all resources are procured
and in place. Accordingly, the TailVar UE and EUE metrcs do not include
uncertainty and potential timing problems with respect to replacing a large
current source of baseload energy and capacity such as Boardman. If PGE is
unable to secure adequate replacement supply by the time Boardman is closed,
our reliabilty risk would increase. For the earliest Boardman closure portfolios,
"Boardman through 2011" and "Boardman through 2014" the replacement
supply risk is much higher and more tangible due to the short amount of time
that PGE would have to build or procure replacement resources.
Figue 12A-5: Unserved Energy Metrcs for Boardman Portfolios, 2012-2020 & 2025
Boardman through 2020
Diversified Thermal with Green
Boardman through 2014
Boardman through 2017
Boardman through 2011
100 200 300 400 500 600 700 800 900
Energy Deficit (MWa)
Technology and Fuel Diversity
PGE has applied the Herfindahl-Hirschman Index (HHI), which has traditionally
been used to measure concentration of commercial market power. In this case,
the HHI is used to measure the portfolio concentration in technologies and fuels
(coal, natural gas, hydro, wind, market purchases, etc.) from 2010 through 2021.
97
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
A lower value means less portfolio concentration in any given technology or fuel
type over the period. A lower HHI value is preferred as it indicates higher
portfolio diversity and thus less exposure to specific fuel and generation
technology driven risks.
The diversified portfolios outperform all of the early Boardman closure
portfolios from fuel and technological perspectives. See Figure 12A-6 and Figure
12A-7 below respectively. While the early Boardman closure portfolios are
equivalent on a technological basis, the later closures perform better from a fuel
diversity perspective.
Figure 12A-6: Herfindahl-Hirschman Index Boardman Fuel Results
Diversified Thermal with
Green
2.245
Boardman through 2020
Boardman through 2017
Boardman through 2014
Boardman through 2011
500 1.000 1.500 2.000 2.500
98
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
Figure 12A-7: Herfndah-Hirschman Index - Boardman Technological Results
Diversified Thermal with
Green
3,075Boardman through 2011
Boardman through 2014 3,075
Boardman through 2020 3,075
Boardman through 2017 3,076
500 1,000 1,500 2,000 2,500 3,000 3,500
Summary of Results from Reliability and Diversity Measures
Our portfolio scoring includes three measurement categories from the reliabilty
and diversity analysis: Tailvar VE, Technology HHI and Fuel HHI. Reliabilty
and Diversity measures comprise 20% of the total score (see Table 12A-2).
"Diversified Thermal with Green", which includes Boardman through 2040,
performs better than the other four Boardman portfolios in the combined areas of
Reliabilty and Diversity.
Other Metrcs
At the suggestion of OPUC Staff, PGE added a variation of two cost risk metrcs
described above to its scoring. Rather than look solely at the deterministic
average of the worst four futures less the reference case cost and the similar
stochastic metric of TailVar 90 less the Mean, we have added two right-tail
metrics that provide absolute measurements of cost without subtracting a mean
or reference case value. This allows for an absolute look at risk exposure without
being influenced by distance from the mean. Figure 12A-8 shows the average
NPVR for the four worst future outcomes. "Boardman through 2020" has the
lowest NPVRR of the five cases.
99
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
Figue 12A-8: Average NPVRR of Four Worst Futues
35,500
35,250
35,000
i 34,750"
l 34,500
~34,250
~
l 34,000
ii 33,750
33,500
33,250
33,000
Boardman through 2020 Dh.ersified Thrmal with Green Boardman through 2014 Boardman through 2011 Boardman thugh 2017
Portolio
Similar results are shown in Figure 12A-9 for the selected portfolios when
considering TailVar analysis. Here "Diversified Thermal with Green" shows the
lowest value. The early Boardman closure portfolios all have higher TailVar
scores - with earlier closure dates performing progressively worse.
Figue 12A-9: Stochastic Risk - TailVar
Boardman through 2011
Boardman through 2014
Boardman through 2017
Boardman through 2020
Diversified Thermal with Green
35 36 38 3937
TailVar - $Bilions
Primary Drivers of Uncertainty
Portfolios were stress-tested with several discrete futures. Of all the futures
tested, variation in natural gas price, C02 price and load growth have the largest
impact on portfolio NPVRR. Figure 12A-lO shows the "Diversified Thermal with
100
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
Green", "Boardman Through 2014" and "Boardman Through 2020" portfolios'
sensitivity to these cost drivers.
"Boardman Through 2014" and "Boardman Through 2020" are more exposed to
gas price risk than "Diversified Thermal with Green", because a gas-fuelled
CCCT is the assumed replacement technology for Boardman in these portfolios.
However, of these two, "Boardman Through 2020" has less gas price risk than
"Boardman Through 2014" .
"Diversified Thermal with Green" is more exposed to C02 risk. This reflects the
higher C02 output profile of a coal plant compared to a CCCT. Exposures to load
growth are essentially the same for all three portfolios.
Another insight from these graphs is the apparent asymmetry between upside
and downside exposure to gas price risk, while C02 cost risk and load growth
have fairly balanced risk profiles. This reflects the asymmetry of the high and
low natural gas prices as compared to the reference case price, since gas prices
can rise higher than they can fall.
Of the three major cost drivers, natural gas price risk emerges as the greatest
driver of the portfolio NPVRR and as a result, the single largest risk factor. C02
compliance cost is second and load growth is third. Load growth risk magnitude
is equivalent for all three portfolios.
101
PCE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis.
Figue 12A-I0: Boardman Portfolios' Sensitivities
Boardman Through 2014
2009$
Gas Prices
..
~::
'JIL
~C02 Tax..
11...c.!!J:
Load Growth
-6000 -4000 -2000 0 2000 4000 6000 8000
NPVRR Change from Reference Case
$ ¡nmillons
Diversified Thermal with Green
2009$
Gas Prices....
!3
'JILl C02 Tax
i:c...c.!!J:Load Growt
-6000 -4000 -2000 a 2000 4000 6000 8000
NPVRR Change from Reference Case
$ ¡nmilions
Boardman Through 2020
2009$
Gas Prices
II
I!:::;IL
;:0 C02 Tax ....C...c01:r
Load Growth
-6000 -4000 -2000 a 2000 4000 6000 8000
M'VRR Change from Reference Case
$inmillons
102
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
12A.6 Assessing Boardman Analytical Results
Our portfolio analysis, using both scenario and stochastic approaches, provides a
comprehensive look at Boardman's value and risks. Overall, "Boardman through
2020" performs better than the other Boardman alternatives, when considering
the combined portfolio scoring measures - see Table 12A-2 below. The
"Boardman through 2020" portfolio clearly outperforms the other early closure
cases with respect to both cost and price risk. In general, the "Boardman through
2020" portfolio strikes a good balance between the key risk drivers of natural gas
and C02 prices, while maintaining system reliabilty at a relatively low cost.
Diversified Thermal with Green also provides a good balance between cost and
risk, performing relatively well on expected cost as well most of the risk,
durabilty and diversity measures. Given these results, "Boardman through
2020" is our preferred portfolio, while "Diversified Thermal with Green"
represents our next best option when compared to other Boardman alternatives.
103
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4
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
Other Considerations
The "Boardman through 2020" portfolio has other compellng advantages not
captured in our IRP scoring compared to the "Boardman through 2014" and
other Boardman alternatives examined here:
. It preserves the near-term economic value of the plant thereby saving
customers around $600 millon dollars over the next decade compared to
the earlier closure alternatives.
. It avoids the acceleration of additional costs and the corresponding
customer rate pressure during a time when other IRP resource actions are
also being implemented.
. It allows time for other greener technologies beyond wind to develop and
economically mature, potentially allowing for a greater range of
replacement options by 2020 than are available today for implementation
by 2014.
. It provides a hedge against compliance costs of any future greenhouse
gas legislation when compared to plans that operate Boardman through
2040
. It allows for an orderly transition for Boardman plant employees and the
local community.
Boardman Recommendation
PGE's preferred Action Plan is based on the "Boardman through 2020" portfolio.
It includes the following investments in emissions controls:
. NOx Controls: install the LNB/MOFA control system which, as proposed,
is estimated to reduce NOx by 4,000 tons per year, for nearly a 50%
reduction compared to current emission levels. These controls wil be
installed by July 2011 to meet the 0.28 Ib/MMBtu (30-day rollng average)
and 0.23 Ib/MMBtu (12-month rollng average) emissions limit. The
estimated overnight capital cost is $33 milion (100% of Boardman plant).
Engineering Procurement and Constrction (EPC) work wil start in early
2010 to support the July 2011 schedule.
. Mercury Controls: install the mercury (Hg) control system by 2012 for an
estimated overnight capital cost of approximately $8 milion (100% of
Boardman plant).
105
PCE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
· SOi Reductions: procure lower sulfur coal which wil reduce 502
emissions 20% below current permit levels by the end of 2011 and 50%
below current permit levels in 2014. (Incremental costs to procure new,
lower sulfur coal supply have not been factored into our portfolio
analysis, but any additional costs are not expected to have a material
impact on the comparative economics of the candidate portfolios.)
Table 12A-3 below provides the dates by which equipment must be installed in
order for PGE to meet its compliance obligations. An all-inclusive engineering,
procurement and constrction (EPC) approach is preferred for the LNB/OF A
controls.
Table 12A-3: Boardman Engineering Procurement and Constrction Schedule
1.LNB/OFA July 2011 March 2010
2.mercury July 2012 Q2-Q32010
Table 12A-4 below summarizes the capital costs that are modeled in our IRP
analysis and are associated with each of PGE's recommended emissions controls.
Capital costs in this table are 100% share of the Boardman plant. Installation of
the new control systems is expected to take place during our normally scheduled
spring maintenance outages.
106
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
Table 12A-4: Proposed Boardman Emissions Controls Capital Costs, Nominal $
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
75
468
1,554
16,628
14,123
25
156
77
233
4,819
2,345
100
624
1,632
16,861
18,943
2,345
AFDC
Propert Tax
Total
32,849
3,636
386
36,872
7,655
912
108
8,675
40,504
4,548
494
45,546
With all proposed BART II controls in place in 2014, variable and fixed non-fuel
O&M wil not change materially.
This analysis is based on PGE's cost of capital. Tax-favored pollution control
bond financing, if available, could improve the economics. Our modeling
assumes no extension of the Oregon Pollution Control Facilities Tax Credit
program, which currently does not benefit controls that were placed in service
after December 31, 2007.
Boardman Alternate Recommendation
As discussed in detail in Chapter 13A, if PGE is not able to move forward with
its preferred Action Plan by March 31, 2011, then it requests that the Commission
acknowledge that it is prudent to move forward with an alternate Action Plan
based on the "Diversified Thermal with Green" portfolio (with or without lease).
The costs for the emissions control equipment associated with the alternate
Action Plan are described in our November, 2009 IRP filng, which for
convenience we replicate below.
Phase 1
. NOx Controls: install the LNB/MOF A control system which, as proposed,
is estimated to reduce NOx by 4/000 tons per year, for a 46% reduction
compared to current emission levels. These controls wil be installed by
July 2011 to meet the 0.28 Ib/MMBtu (30-day rollng average) and 0.23
Ib/MMBtu (12-month rollng average) emissions limit. The estimated
107
PGE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
overnight capital cost is $33 milion (100% of Boardman plant).
Engineering Procurement and Constrction (EPC) work wil start in early
2010 to support the July 2011 schedule. We anticipate that it wil not be
necessary to request a compliance extension, thereby changing the dual
limits to a single 0.23lb/MMBtu (30-day rollng average) emissions limit.
. Mercury Controls: install the mercury (Hg) control system by 2012 for an
estimated overnight capital cost of $7.7 milion (100% of Boardman plant).
. 502 Controls: install scrubbers, which wil cut 502 emissions by 12,000
tons per year for an 80% reduction compared to current emission levels.
These controls wil be installed by July 2014 to meet the 0.12lb/MMBtu
30-day average emissions limit.
. Particulate Matter Controls: install a pulse jet fabric filter as part of the
scrubber installation to supplement the existing electrostatic precipitator.
This installation wil cut particulate matter emissions by 122 tons per year
for a 29% reduction from current levels. These controls wil be installed
by July 2014 to meet the 0.012lb/MMBtu emissions limit. The particulate
matter controls, together with the scrubbers, are estimated to have
overnight capital cost of $289.9 milion (100% Boardman plant).
Phase 2
. NOx Controls: install Selective Catalytic Reduction (SCR), which wil cut
NOx emissions by an additional 4,000 tons per year for an additional 38%
reduction, beyond the Phase I upgrades. These controls wil be installed
by July 2017 to meet a 0.070 lb/MMBtu emissions limit for an estimated
overnight capital cost of $180 milion (100% Boardman plant).
Table 12A-5 below provides the dates by which equipment must be installed in
order for PGE to meet its compliance obligations. An all inclusive engineering,
procurement and construction (EPC) approach is preferred, except for the Hg
controls.
108
PCE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
Table 12A-5: Boardman Engineenng Procurement and Constrcton Schedule
1.LNB/OFA July 2011 March 2010
2.Mercury July 2012 Q2-2011
3.FGD July 2014 Ql-2011
4.SCR July 2017 Ql-2014
Table 12A-6 below summarizes the capital costs associated with each of the
emissions controls according to the alternate Action Plan recommendation;
capital costs in this table are for 100% of the Boardman plant output. Installation
of the new systems is expected to take place during our normally scheduled
spring maintenance outages.
Table 12A-6: Boardman Emissions Controls Capital Costs, Nominal $
I'); .),/.,iT/,.................)i.i iF .T.."'....."it
2007 $75 $100 $75 $250
2008 $468 $624 $468 $1,560
2009 $1,554 $376 $77 $2,007
2010 $16,628 $3,785 $116 $20,529
2011 $14,123 $85,862 $94 $100,079
2012 $-$127,146 $116 $127,262
2013 $-$58,570 $684 $59,254
2014 $-$21,042 $38,789 $59,831
2015 $-$-$80,564 $80,564
2016 $-$-$43,720 $43,720
2017 $-$-$15,350 $15,350
Overnight
Capital $32,848 $297,505 $180,053 $510,406
AFDC $3,636 $73,627 $42,352 $119,615
Property
Tax $386 $9,913 $5,727 $16,026
Total $36,870 $381,045 $228,132 $646,047
109
PCE 2009 Integrated Resource Plan Chapter 12A. Boardman Analysis
With all controls in place in 2017, total fixed and variable O&M for PGE's 65%
share of Boardman is projected to increase by approximately $8.1 milion in
2009$. About two-thirds of this amount is variable O&M. At the same time, the
net plant heat rate is projected to increase by about 2% and plant output is
projected to decrease by the same percentage. The ongoing impacts to the
dispatch cost due solely to emissions controls (the variable O&M and change in
heat rate) are fairly modest. In 2017, when all controls are in place, the non-fuel
dispatch cost is expected to increase by approximately $3 per MWh in 2009 $
exclusive of C02 costs.
As discussed in furter detail in Chapter 13A, PGE recommends
acknowledgement of our preferred Action Plan based on the Boardman through
2020 portfolio. In the event that the contingencies associated with the preferred
Action Plan (as outlned in Chapter 13A) can not be resolved, we recommend
proceeding with our alternate Action Plan based on the Diversified Thermal with
Green portfolio.
110
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-11-18
IDAHO POWER COMPANY
ATTACHMENT NO.3
ORDER NO. 10-457
Entered 11/23/2010
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
LC48
In the Matter of
PORTLAND GENERAL ELECTRIC
COMPANY,
ORDER
2009 Integrated Resource Plan.
DISPOSITION: PLAN ACKNOWLEDGED WITH REQUIREMENTS
I. INTRODUCTION
Portland General Electric Company (PGE or the Company) seeks
acknowledgment of its 2009 Integrated Resources Plan (IRP) and 2010 Addendum. In this
order we acknowledge the plan subject to certain requirements that are discussed below.
A. IRP Guidelines
We require regulated energy utilities to engage in integrated resource planning
and to fie an IRP every two years. We review the fied plans to determine whether they
adhere to our IRP guidelines and either "acknowledge" them, or return to the utility with
comments. Acknowledgement does not guarantee favorable ratemaking treatment, but
means that the plan seems reasonable at the time of Commission review.
The Commission has adopted thirteen IRP guidelines. The first guideline
includes substantive requirements under which the utility must (1) evaluate all resources on a
consistent and comparable basis; (2) consider risk and uncertainty; (3) have as its primary
goal the selection of a portfolio of resources with the best combination of expected costs and
associated risks and uncertainties for the utility and its customers; and (4) draft a plan that is
consistent with the long-run public interest as expressed in Oregon and federal energy
policies.l The remaining twelve guidelines include procedural requirements that provide
direction on how to prepare and update the plan, and other provisions that address specific
resources such as transmission and conservation.
i Docket UM 1056, Order No. 07-002 (Jan 8, 2007).
ORDER NO. 10-457
B. Effect of Acknowledgement of an IRP on Future Ratemaking Actions
The Commission's role in reviewing an IRP is to determine whether the IRP
meets the substantive and procedural guidelines in Order Nos. 89-507 and 07-002. The
Commission generally does not address the need for specific resources, but rather determines
whether the utility has proposed a portfolio of resources to meet its energy demand that
presents the best combination of cost and risk.2 Commission acknowledgement of an IRP
means only that the Commission finds that the utility's preferred portfolio is reasonable at the
time of acknowledgement. 3
In Order No. 89-507, the Commission described its role in reviewing and
acknowledging a utility's least-cost plan:
The establishment of Least-Cost Planning in Oregon is not
intended to alter the basic roles of the Commission and the utility
in the regulatory process. The Commission does not intend to
usur the role of utility decision-maker. Utility management wil
retain full responsibility for making decisions and for accepting the
consequences of the decisions. Thus, the utilities wil retain their
autonomy while having the benefit of the information and opinion
contributed by the public and the Commission.
* * * * *
Acknowledgment of a plan means only that the plan seems
reasonable to the Commission at the time the acknowledgment is
given. As is noted elsewhere in this order, favorable rate-making
treatment is not guaranteed by acknowledgment of a plan.4
This order does not constitute a determination on the ratemaking treatment of
any resource acquisitions or other utility expenditues. As a legal matter, the Commission
must reserve judgment on all ratemaking issues. Notwithstanding these legal requirements,
we consider the integrated resource planning process to complement the ratemaking process.
In ratemaking proceedings, in which the reasonableness of resource acquisitions is
considered, the Commission wil give considerable weight to utility actions that are
consistent with acknowledged plans. A utility is expected to explain actions they take that
are inconsistent with Commission-acknowledged plans.
c. Procedural History
PGE fied its 2009 Integrated Resource Plan on November 5, 2009. In that
fiing, PGE proposed to invest over $500 milion to retrofit its Boardman coal-fired plant
2 See Order No. 07-002 at 25.
3 See ¡d. at 16.
4 See Order No. 89-507 at 6, 11 (Docket UM 180). The Commission affirmed these principles in Docket
UM 1056. See Order No. 07-002 at 24.
2
ORDER NO. 10-457
(Boardman) to meet requirements of the Oregon Environmental Quality Commission's
(EQC) Regional Haze Plan and operate the plant until 2040. Following a prehearing
conference on December 1,2009, an administrative law judge issued a procedural schedule
that included a presentation to the Commission on January 19,2010.
On January 14,2010, PGE asked the Commission to postpone PGE's
presentation to the Commission scheduled for January 19,2010. PGE explained that it
intended to meet with stakeholders to assess whether PGE could devise alternatives to its
proposal to retrofit the Boardman plant and operate it until 2040 in a maner that would be
acceptable to the EQC and other stakeholders. On January 15,2010, the Commission stayed
all proceedings in this docket.
On April 9,2010, PGE filed an addendum to its IRP that included a revised
operating plan for Boardman. Following the adoption ofa new procedural schedule,
however, we delayed proceedings to allow PGE, intervenors, and Commission Staff (Staff)
the opportnity to consider whether certain EQC and Departent of Environmental Quality
(DEQ) actions might impact PGE's revised IRP. Staff noted that EQC would soon consider
(1) PGE's request to modify the EQC's 2009 Regional Haze Plan in a maner that would
allow PGE to pursue its revised operating plan for Boardman, and (2) DEQ's
recommendation that the EQC direct DEQ to base analysis regarding potential revisions to
the Regional Haze Plan on a range of operating options for Boardman, rather than on the
single operating plan underlying PGE's proposed rule change.
A final procedural schedule was subsequently adopted that required PGE to
file reply comments analyzing three DEQ-proposed alternatives for Boardman retrofits and
operation and responding to earlier fied comments. The procedural schedule gave
intervenors the opportnity to respond to PGE's supplemental comments, PGE the
opportity to fie reply comments on September 27,2010, and directed Staff to fie
recommendations and a proposed order. On September 21, 2010, the Commission issued a
Bench Request directing PGE to fie additional analysis regarding the three DEQ retrofit and
operation scenarios, and allowing intervenors the opportnity to reply to PGE's response.
In sum, the procedural schedule in this docket included multiple opportities
for the parties to address PGE's IR. This included three rounds of wrtten comments; thee
public meetings; two technical workshops (to address Cascade Crossing and Boardman); and
public comment hearings in Portland and Boardman, Oregon.
D. Parties and Comments
The following entities intervened in this proceeding: the Northwest and
Intermountain Power Producers Coalition; the Citizens' Utility Board of Oregon (CUB);
NW Energy Coalition (NWEC); Ecumenical Ministries of Oregon (EMO); Oregon
Environmental Council, PacifiCorp, dba Pacific Power; Iberdrola Renewables, Inc.; Oregon
Department of Energy (ODOE); the Sierra Club, Columbia Riverkeeper, Friends of the
Columbia Gorge, and the Northwest Environmental Defense Center; Renewable Northwest
Project (RNP); Physicians for Social Responsibility; Northwest Pipeline GP; the City of
3
ORDER NO. 10-457
Portland; Industral Customers of Northwest Utilities; Turlock Irrgation Distrct;
International Brotherhood of Electrical Workers, Local 125 (IBEW Local 125); Northwest
Food Processors Association; Portland Metropolitan Building Owners and Managers
Association; Oregon Forest Industres Council, Oregon Cattlemen's Association; Wilard
Rural Association; Power Resources Cooperative; Salem Area Chamber of Commerce
(Salem Chamber); Strategic Economic Development Corporation; Clackamas County
Business Alliance; Columbia Corrdor Association; Associated Oregon Industries; Westside
Economic Allance; Portland Business Allance; Association of Oregon Counties; the
Wilsonvile Chamber of Commerce; SEDCOR, Morrow County; Oregonians for Food and
Shelter; Oregon Farm Bureau Federation; Community Action Partnership of Oregon; and
Pareto Energy, LTD.
In addition, well over one thousand people fied written public comments with
the Commission. Many of the comments are form letters that the Commission received at the
public comment hearings held in Boardman and Portland, Oregon. More than 800 form
letters support closure of Boardman by 2014. More than 250 form letters support operating
Boardman through 2040, or at the minimum, through 2020.
II. DISCUSSION
A. Load Forecast and Resource Need
1. Parties' Positions
The Sierra Club, Columbia Riverkeeper, Friends of the Columbia Gorge, and
the Northwest Environmental Defense Center (NEDC) (collectively referred to as the
Coalition), as well as NW Energy Coalition (NWEC); Wilard Rural Association (WRA);
and Ecumenical Ministries of Oregon (EMO) argue that PGE has overstated its reference
case load forecasts and, therefore, its future energy and capacity needs. Many of these
parties argue that this has a direct bearing on the options for shutdown of Boardman.
The Coalition, NWEC, and EMO all argue that PGE's load forecasts are
inconsistent with recent historical load growth in PGE's service terrtory. The Coalition
emphasizes that since 2000 the yearly growth in sales has exceeded PGE's March 2009
projected growth rate of 1.9 percent per year for 2010 through 2030 only once.5 NWEC
points to analysis by WRA that shows PGE's load growth has been essentially flat over the
past ten years and questions why the next ten years should be projected to be any different. 6
The Coalition urges the Commission to consider the differences between the
Company's March 2009 load forecasts used in the IRP and its more recent December 2009
load forecasts.7 The Coalition provides the year-by-year reductions in peak load and annual
average energy and argues that the forecast reductions are significant and materiaL. For
5 Coalition's Sept 1,2010 Comments at 17-18 (Schlissel Technical Consulting, Inc. (Schlissel))
6 NWEC's May 14,2010 Comments at 5.
7 Coalition's Sept 1,2010 Comments at 16-17 (Schlissel).
4
ORDER NO. 1O~457
example, the December 2009 forecasts show reductions of 157 megawatts (MW) in peak
load and 152 average MW (MWa) in annual energy during 2015.
NWEC, the Coalition, and EMO all argue that POE's load forecasts are
inconsistent with those of independent forecasters. NWEC takes issue with POE's
comparison of its projected load growth of 1.72 percent for the period 2010-2015, assuming
a continuation of historic levels of embedded energy effciency, to the Northwest Power and
Conservation Council's (NPCC) Draft Sixth Plan projected load growth for Oregon of 1.96
percent. NWEC argues that the appropriate comparison is to an adjusted load growth
forecast for Oregon of 0.47 percent per year. NWEC calculated this adjusted growth rate
after subtracting the NPCC's forecast of future energy effciency from its medium-load
forecast.8
Staff argues that POE's reference case forecast is too high because it does not
adequately account for the continued effect of the 2007-2009 recession.9 Staff contends that
the NPPC's Final Sixth Plan projected annual load growth of 1.4 percent for 2010-2015 is
more reasonable than POE's projected 1.7 percent. Staff indicates that this level of growth is
consistent with POE's low-case forecasts. Staff also attempts to put this adjustment into the
context of POE's overall resource need. Staff indicates that under POE's reference case load
forecast, with Boardman operating, POE is short 952 anual MWa of energy in 2016. Staff
notes that shutting down Boardman in late 2015 would push that deficit to 1,266 MWa in
2016. Updating POE's model to include its low-load scenario, with Boardman shutdown in
2015, the resource deficit would be 1,158 MWa in 2016. Under this low load scenario, the
winter and summer capacity deficits are 1,979 MW and 1,788 MW, respectively, in 2016.
Staff asserts that these resource gaps under the low load forecasts are stil significant and
would be challenging to fill if Boardman were shut down in 2016.
POE responds that its forecasts appropriately incorporate data from both the
recent and distant historical past. POE acknowledges that load growth exceeded the
forecasted average rate of 1.9 percent only once since 2000, but adds that that historic anual
growth exceeded 1.9 percent durng sixteen of the last twenty-eight years. 10 POE also notes
that the differences between its March 2009 and December 2009 load forecasts can be
explained in part by different accounting treatment of Senate Bil 838 energy effciency and
by recession-driven reductions in a very limited set of large industral customer loads. POE
emphasizes that the load reduction of 152 average MW in 2015 needs to be put into the
context of POE's overall forecasted resource need of873 average MW in 2015.11
2. Commission Resolution
We agree that POE's reference case load forecast for the 2010-2015 period is
likely too high because it fails to account for the lingering effect of the
2007-2009 recession. We also agree with POE and Staff that we must consider this within
8 NWEC's May 14,2010 Comments at 5.
9 Staffs Oct 15,2010 Comments at 9.
IOPGE'S Sept 28,2010 Comments at 14.
ii Id at 13.
5
ORDER NO. 10-457
the context ofPGE's overall resource needs. Even under the low-load scenarios, and even if
Boardman keeps operating, PGE has significant resource needs. PGE's future resource needs
are driven not just by growing demand, but also by the expiration of key power purchase
contracts held by the Company.
In an IRP, we require utilities to evaluate alternative resource portfolios across
a wide range of potential futures, including those with low, medium, and high demand for
electrcity. PGE's range ofload forecasts appears reasonable. PGE evaluated its resource
portfolios across this range of load forecasts. Our finding that PGE's reference case load
forecast is likely overstated does not change our decision regarding Boardman and the best
resource options for ratepayers, as discussed in the next sections.
We do not agree with NWEC that PGE's projected average annual growth in
load is significantly higher than that projected by NPCC. PGE correctly compares its
forecasts with embedded energy effciency to NPCC' s "frozen efficiency" forecasts. This
"apples-to-apples" comparison is consistent with the IR objective of measuring resource
need prior to the addition of any demand- or supply-side resource actions. More
fundamentally, we agree with PGE that this comparison is founded on the faulty premise that
the Pacific Northwest is one large homogeneous region in terms of economics and
demographics. As PGE points out, for example, its service terrtory is more urban and has
more high-technology customers than the rest of the region. There are many good reasons
why load growth rates wil differ by area within a state and within the region.
B. Natural Gas Price Forecast Method
1. Parties' Positions
The Coalition argues that PGE uses unreasonably high natural gas prices in its
IRP modeling and biases the results in favor of continued operation of the Boardman plant
and against the early shutdown scenarios. The Coalition compares PGE's reference case
natural gas prices forecasts to those of the NPCC, Staff, and the U.S. Energy Information
Administration (EIA).12 The Coalition argues that it is critically important that planning
analyses and decisions be based on current information. The Coalition recommends that the
Commission require PGE to update its reference case natural gas price forecast before
accepting the modeling results.
13
Staff agrees also with the Coalition that PGE's reference case natual gas price
is slightly overstated. Staff argues that PGE's forecasting methodology is flawed because the
Company only relies on a single source, PIRA Energy Group, for its long-term natual gas
price forecast. Staff also argues that PGE' s short-term price forecast is flawed because it
only relies on NYMEX futures prices, and does not include fundamentals based price
forecast. Staff recommends that the Commission require PGE to obtain natual gas prices
forecast from multiple third party sources.
12 Coalition's May 19,2010 Comments at 4-10 (Schlissel).
13 Coalition's Sept 1,2010 Comments at 12 (Schlissel).
6
ORDER NO. 10-457
In response to Staffs analysis and recommendations, PGE states that it is
unaware of any bias in PlRA' s forecasts. PGE also notes that it appears that Staff compared
the IRP's August 2009 PlRA forecast to the 2010 forecasts ofEIA and Wood MacKenzie
Research and Consulting. PGE notes that comparing PIR's 2009 forecast to these 2010
forecasts is misleading because most forecasters reflected a downtu in prices for 2010.14
With respect to Staffs observations regarding PGE's use of NY ME X future prices for near-
term forecasting, PGE maintains that using prices from actual trades reflects the most current
and accurate information that is available in the market. 15
2. Commission Resolution
We agree that PGE' s reference case natual gas price forecast is likely
overstated because of the lingering effect of the 2007-2009 recession and recent
developments related to shale gas production. In IRPs, we require utilities to evaluate
alternative resource portfolios across a wide range of potential futues, including those with
low, medium, and high prices for natual gas. PGE's range of natual gas prices appears
reasonable. PGE's natural gas forecasts satisfy IRP Guidelines Ib and 4g.
Our finding that PGE's reference case natual gas prices are likely overstated does not
change our decision regarding Boardman. We decline to require PGE to use multiple
forecasting sources in future IRPs. We expect PGE to continue to update its natural gas price
forecasts in future IRPs and IR Updates.
C. Boardman
1. Parties' Positions
PGE requests that the Commission acknowledge continued coal-fired
operations at Boardman as outlined in the Company's BART II proposal submitted to the
DEQ on July 30,2010. PGE argues that its BART II compliance actions, when combined
with its energy efficiency, renewable energy, and other resource actions, comprise a portfolio
of resources that provide the best combination of cost and associated risk for ratepayers over
the IRP planning period.
As part of its BART II proposal, PGE proposes the following compliance
actions to meet Oregon Regional Haze Plan and Oregon Utility Mercur Rule standards:
1. Installation of low-nitrogen oxide (NOx) burers with a modified
overfire air control system in July 2011;
2. Installation of mercury controls in July 2012;
3. Installation of selective non-catalytic reduction (SNCR) in July 2014;
4. Operation using reduced sulfu coal beginning in July 2014;
14 PGE's Nov 1,2010 Comments at 13-14.
15 ¡d.
7
ORDER NO. 10-457
5. Installation and pilot testing of a Dry Sorbent Injection (DSI) system
in July 2014; and
6. Cessation of coal-fired operations at the end of2020.16
Contingent on the results of the DSI pilot testing, PGE would commit to meeting a OAlb.
sulfur dioxide (S02) per milion British thermal unit (MMBtu) emission limit through 2020,
using DSI. If the pilot testing demonstrated that operating the plant with DSI technology is
incapable of achieving this level of S02 emissions without triggering an increase in
emissions of particulate matter, then PGE proposes to meet an alternative S02 limit
established by DEQ procedure based on the DSI testing. It is unclear whether the EQC wil
adopt PGE's BART II proposal.
PGE analyzed its BART II proposal, as well as three alternative DEQ
options, using its IRP portfolio modeling. DEQ Option 3 calls for installation of a low-NOx
burer system in 201 1 and mercury controls in 2012; but would require the shutdown of
Boardman by late 2015 or early 2016. DEQ Option 2 is similar to PGE's BART II proposal,
but would result in cessation of coal-fired operations in 2018. DEQ Option 1 includes the
low-NOx burer system in 2011, the mercur controls in 2012, adds installation of semi-dr
flue gas desulfuzation (dr scrubbers) in 2014 to control S02 emissions, and would cease
coal-fired operations at Boardman in 2020. Based on its IRP modeling, PGE concludes that
its BART II resource portfolio is both less costly and less risky than the three DEQ
options.
I?
PGE contends that its BART II proposal is superior to these alternatives, and
observes that among the early closure options, those that keep Boardman operating longer
perform better. PGE suggests that DEQ Option 1 is unacceptable because the dry scrubbers
are a very costly additional layer of control. PGE questions the regulatory implementation of
DEQ Option 2, which does not include pilot testing of the DSI technology, and therefore fails
to account for the possibility that achieving the S02 emission limit may simultaneously
trigger a violation of particulate matter limits.
Finally, PGE argues that DEQ Option 3, which would shutdown Boardman in late 2015 or
early 2016, offers an extremely poor outcome for ratepayers in terms of cost and risk.
PGE concedes that its BART II proposal does not guarantee that futue
regulation of hazardous air pollutants or the resolution of pending litigation in United States
District Court wil not require PGE to install additional controls at Boardman prior to 2020.
However, PGE no longer makes its acknowledgment request contingent upon obtaining a
reasonable assurance by March 31, 2011 that it wil be able to operate Boardman through
2020 without installing additional emission control technologies. PGE asks the Commission
to acknowledge its BART II compliance actions despite these risks.
18
16 PGE's Aug 10,2010 Comments at 8-9.
17 Id at 10-13.
is ¡d. at 16.
8
ORDER NO. 10-457
PGE does, however, make its acknowledgement request contingent on EQC
approval of its BART II proposal by March 31, 2011. In the event that the EQC fails to
approve BART II, PGE requests acknowledgement of a backstop proposaL. PGE's backstop
is full implementation of BART I controls and continued operation of Boardman through a
least 2040. Based on incremental rate impact analysis, PGE concludes that the BART I
emission controls, as modeled in the Diversified Thermal with Green portfolio, outperform
the three DEQ early shutdown options and is the second best option for ratepayers. 19
PGE argues that the backstop proposal acknowledgment is necessar because
any delay in ordering the equipment needed to implement BART I wil subject ratepayers to
increased costs and risks associated with a compressed Engineering, Procurement and
Construction (EPC) schedule and with a potential temporary shutdown of Boardman in 2014
as a result of failure to install the dr scrubbers by the BART I deadline.2o PGE has
continuously emphasized throughout this proceeding that failure to comply with the Oregon
Regional Haze Plan is not an option. The Boardman plant must meet the emissions
requirements by either installing the required controls or by ceasing coal-fired operations.
In its comments on Staffs proposed draft order, PGE states that it asked DEQ
to reopen the record in the ongoing DEQ rulemaking proceeding to allow PGE to make a
refinement to the BART II plan. PGE noted that CUB, RNP, Angus Ducan,21 Oregon
Environmental Council (OEC), and NWEC support the refined BART II plan. PGE also
informed the Commission that PGE has committed to work with stakeholders in the
Company's next IRP to evaluate and consider carbon-reduction options for replacement
power.
22
The following paries submitted opening comments that largely support
PGE's BART II proposal without qualification: Morrow County, Portland Business
Alliance, Oregon Forest Industres Council, Associated Oregon Industries (AOI), Oregon
Cattlemen's Association, the Community Action Partership of Oregon, Strategic Economic
Development Corporation, Association of Oregon Counties, Salem Area Chamber of
Commerce (Salem Chamber), Wilsonville Chamber of Commerce, Clackamas County
Business Association, Columbia Corrdor Association, Oregon Farm Bureau, and Oregonians
for Food and Shelter. In their reply comments, AOI, Salem Chamber, West Side Economic
Alliance, Oregon Forest Industries Council, Association of Oregon Counties, Columbia
Corridor Association, and Morrow County strongly suggest the Commission acknowledge
PGE's 2040 option as a backstop alternative.
IBEW Local 125 urges the Commission to acknowledge operation of the
Boardman plant until 2040 and beyond, with nothing less than 2020 as a backstop.
19 ¡d. at 15.
20 ¡d. at 5; IRP Addendum at 124 (April 9, 2010).
21 Angus Duncan, is an interested person in this docket, is the President and CEO of the Bonneville
Environmental Foundation.22 POE's Oct 29, 2010 Comments at 3.
9
ORDER NO. 10-457
The Physicians for Social Responsibility implored the Commission to
consider the serious health concerns and costs associated with continued operation of
Boardman beyond 2014.
Other paries submitted comments that challenge PGE's analysis of the
Boardman compliance options and contained alternative recommendations for the
Commission. We summarze these parties' positions below, as well as some reply
comments.
a. The Coalition
The Coalition characterizes PGE's proposed compliance actions as a plan to
transition off coal in 2020-or never?3 The Coalition argues that PGE's proposed BART II
is virtally identical to its BART II proposal that was already rejected by the EQC. The
Coalition recommends that the Commission order PGE to start over and develop a balanced
and reasonable outcome for Boardman that is consistent with clean air laws and Oregon's
greenhouse gas emissions reduction goals.
The Coalition argues that PGE' s own modeling shows that compared to
PGE's BART I backstop both DEQ Option 2, with early shutdown in 2018, and DEQ Option
3, with early shutdown in late 2015, are lower-cost alternatives.24
The Coalition further argues that PGE uses unreasonably high natual gas
prices in its IRP modeling and biases the results in favor of continued operation of Boardman
and against early shutdown scenarios.25 The Coalition concedes that it did not prepare its
own natural gas prices forecasts, but instead relied upon the forecasts provided in the record
of this proceeding by other parties. However, the Coalition argues that it is critically
important that planning analyses and decisions be based on curent information. The
Coalition recommends that the Commission require PGE to update its reference case natual
gas price forecast before accepting the modeling results.
The Coalition also believes that PGE has overstated its energy and capacity
needs.26 Again, emphasizing the importnce of current information, the Coalition argues that
PGE should use its December 2009 peak and average energy load forecasts in its IRP
modeling. The Coalition argues that the differences between the December 2009 forecasts
and the March 2009 forecasts used in PGE's IRP modeling are significant and material to the
development of PGE's IRP Action Plan.
The Coalition opines that contrary to PGE's assertions, a natural gas-fired
combined-cycle combustion tubine (CCCT) can be built in two, to two-and-a-halfyears.27
23 Coalition's Sept 1,2010 Comments at 1-2.
24 ¡d. at 2.6 (Schlissel).
25 ¡d. at 7-16.
26 ¡d. at 16-18.
27 ¡d. at 18.
10
ORDER NO. 10-457
Given actual construction times, the Coalition believes that a CCCT could be built and ready
to replace Boardman by 2016.
The Coalition states that PGE has completely failed to evaluate the economic
costs and benefits of replacing some or all of Boardman's output with a mid-term power
purchase agreement (PPA).28 According to the Coalition a mid-term PPA strategy could be
used to implement DEQ Options 2 & 3.
The Coalition points to PGE' s IRP modeling which shows Boardman
operating as an intermediate-load resource in the future, and questions the prudence of
investing in emissions controls at the plant if it would no longer operate as a baseload
resource.29
b. The Joint Parties
CUB, RNP, NWEC, OEC, Angus Duncan, EMO, Sierra Club, and NEDC,
(collectively referred to as the Joint Parties) view the proposal to install BART I emissions
controls to allow the continued operation of Boardman through 2040 as the most
objectionable option before this Commission. They request the Commission not
acknowledge the BART I emission controls, as modeled in the Diversified Thermal with
Green portfolio or any other portfolio, even as a backstop plan.3o
The Joint Parties support closing Boardman as early as possible, yet indicate
that they would prefer a broadly supported plan, even if the plan closed the plant at a
somewhat later date. Therefore, PGE and DEQ are urged to use DEQ's Option 2 and PGE's
BART II proposals as the basis for achieving convergence on a broadly supported plan. The
Commission is urged to only acknowledge the pollution controls that are immediately
necessary and to leave the door open for fuher amendments to this IRP. According to the
Joint Parties these actions wil allow room for PGE, DEQ, and other regional stakeholders to
agree on a comprehensive plan to achieve the responsible closure of Boardman.
The Joint Parties argue that the replacement of Boardman should be
significantly cleaner and more flexible resource than replacement with only a base load
natural gas plant.3! The Joint Parties are confident that PGE could replace Boardman in the
2015/2016 timeframe with a diverse mix of resources. The Joint Parties concede the risk,
however, that early closure would likely result in replacing the plant with a natural gas
resource and its associated carbon emissions. Again, the Joint Parties urge the Commission
to create space for stakeholders to develop a clean and diverse replacement strategy.
28 !d. at 19.
29 Id at 20-21.
30 Joint Parties' Sept 1,2010 Comments at 1.
31 ¡d. at 2.
11
ORDER NO. 10-457
C. The NW Energy Coalition
The NW Energy Coalition (NWEC) joins the Joint Parties in recommending
shutdown of Boardman no later than 2020. Like the Joint Parties, NWEC prefers an
agreement between POE, DEQ, and regional staeholders on a mutually acceptable plan. As
a result, NWEC recommends that the Commission only indicate the boundaries of an
acceptable closure plan. According to NWEC, formal acknowledgement should only occur
after an actual agreement to close Boardman is achieved.
32
NWEC opines that not enough effort has been put into developing a resource
strategy to replace Boardman?3 NWEC urges the Commssion to consider the state's carbon
reduction goals and in the next IR cycle to begin work on a comprehensive plan to achieve
significant reductions in emissions. NWEC repeatedly argues that the risk metrics used by
POE in its IRP portfolio analysis assign no weight to the risk of carbon regulation because
they average scenarios with high and low carbon costs. NWEC recommends that the
Commission require future IRPs to include a risk metric that directly measures carbon
dioxide emissions.
NWEC is most forceful in its objection to POE's request for backstop
acknowledgment of the BART I compliance actions.34 NWEC argues the DEQ Option 3
with closure of Boardman in late 2015 or early 2016 is the better backstop. According to
NWEC a comparison of the modeling results of POE's BART I backstop proposal to DEQ
Option 3 shows no significant difference on a cost basis. NWEC argues that the lower
carbon dioxide emissions ofDEQ Option 3 should be used to break this tie. NWEC suggests
that the advantage in emissions could be even larger if Boardman is replaced with power
sources cleaner than a natural gas-fired CCCT. NWEC scolds POE for introducing new tie-
breaking criteria, such as near-term rate impacts, inadequate time to develop replacement
resources, and insufficient transition time for its employees and the Boardman community.
Although NWEC joins the Coalition in questioning POE's timeline for
construction ofa CCCT, it more fundamentally questions the need for immediate and full
replacement of Boardman's capacity and energy OUtpUt.35 NWEC has repeatedly argued that
the load forecast used by POE in its IR modeling is higher than the NPCC forecast. NWEC
also asserts that POE has overstated its resource need by deciding to lower its exposure to the
wholesale power market. NWEC criticizes POE for not analyzing its level of market
exposure in this IR. NWEC concludes that there is little need for quick and full
replacement of Boardman by 2015.
Finally, NWEC concedes that over reliance on the wholesale power market
can be risky and detrimental to ratepayers. It then points to a healthy surlus of generating
capacity in the Northwest and the area covered by the Western Electrcity Coordinating
Council and concludes this risk is worth taking to close Boardman in late 2015 or early 2016.
32 NWEC's Sept 1,2010 Comments at 1.
33 ¡d. at 1-2.
34 ¡d. at 2-6.
35 ¡d. at 4.
12
ORDER NO. 10-457
NWEC argues that reliance on the market can provide the space needed in time to acquire a
clean mix of replacement resources.
d NIPPC
The Northwest and Intermountain Power Producers Coalition (NIPPC) offers
no opinion regarding the cessation of coal-fired operations at the Boardman plant,36 NIPPC
emphasizes, however, that the shutdown risks being debated in this proceeding are largely
ratepayer risks, and believes that diversifying ownership of generation resources is in the best
interest of ratepayers. NIPPC says it is well established that PPAs lower a utility's business
risk. Contrasting PGE's Boardman ownership with PGE's PPA with TransAlta for a portion
of the output of the coal-fired Centralia plant, NIPPC concludes that power secured through a
PPA with an independent power producer is far less risky for ratepayers?7
NIPPC offers more detailed criticism ofPGE's analysis of the potential
replacement resources for Boardman. NIPPC argues that PGE has not adequately evaluated
the costs and risks, including the reliability risks, of entering into PP As with independent
power producers. NIPPC' s criticism is not limited to the evaluation of PP As for long-term
replacement of Boardman, but also covers the evaluation of short-term PPAs that could
temporarily bridge the capacity and energy need until a permanent replacement is built or
purchased. According to NIPPC, PGE's repeated assertions that this tye of analysis is more
appropriate in a competitive procurement proceeding are misplaced. Commission IRP
Guideline 1 requires utilities to evaluate all resources on a consistent and comparable basis.38
NIPPC argues that postponement of the evaluation of PPAs to the competitive bidding
process makes PGE's IRP noncompliant with this guideline.
NIPPC has specific recommendations to remedy PGE' s lack of analysis of the
PP A option. NIPPC asks the Commission to require PGE to issue a Request for Information
(RFI) to potential suppliers of replacement power.39 This streamlined information gathering
process would allow PGE to adequately consider the PPA resource and to re-evaluate its
replacement options. NIPPC states that PGE should be required to fie an IRP addendum
explaining the results of the RFI and to allow paries to fully vet the merits of the PPA
replacement option.
NIPPC also has recommendations for improving PGE's upcoming Request for
Proposals (RFP) process.40 Concerned that PGE intends to favor its own self-built
benchmark resources, NIPPC recommends the Commission encourage PGE to identify the
actual amount of nameplate megawatts that it intends to acquire through unit contingent
PP As linked to resources that PGE does not intend to build or subsequently acquire. NIPPC
also recommends that the Commission strongly encourage PGE to solicit bids that include
build-to-own replacement options at PGE's sites, long-term PPAs linked to replacement
36Id at 2.
37 ¡d. at 7.
38 Order No. 07-002 at 3.
39 NIPPC's Sept 1,2010 Comments at 5.
40 ¡d. at 8-9.
13
ORDER NO. 10-457
resources located at non-PGE sites, as well as sales of existing assets from independent
power producers.
e. Staff
Staff recommends that the Commission acknowledge PGE's BART II
proposal. Staff adds that the Commission should not acknowledge PGE's BART I backstop
proposal, but instead require PGE to present an alternative proposal and supporting analysis
in its next IR Update if EQC denies its request to revise the Regional Haze Plan to facilitate
PGE' s BART II proposal.
Staff primarily focuses its analysis ofPGE's portfolio modeling on three
metrics: (1) expected cost; (2) the average of the four worst deterministic futures; and (3) the
stochastic TailVar90 risk metric. Staff also reviewed the analysis and comments of the other
paries in this case. Based on this analysis, Staff agrees with PGE that its BART II proposal
represents the portfolio with the best combination of cost and risk for PGE's ratepayers. The
BART I portfolios, including Diversified Thermal with Green, would impose too great of a
risk on ratepayers from futue federal and state regulation of carbon emissions. Staff also
agrees with PGE that the execution risks associated with implementing the earlier shutdown
scenaros are significant.
Staff agrees with NIPPC and NWEC that power purchases from independent
power producers or the wholesale power market could be used to bridge the early energy and
capacity deficits associated with these scenarios. Staff concludes, however, that the risk
associated with the deliverability and cost of such power is not in the best interest of
ratepayers.
Staff agrees with comments of other parties that that there is evidence that
PGE's reference case load forecast may overstate future demand. However, Staffs analysis
indicates that PGE' s energy and capacity need remains significant even under a lower load
scenario. As previously discussed, Staff believes that PGE's resource gaps are significant and
would be challenging to fill if Boardman were shut down in 2016.
Staff also agrees with the Coalition and NWEC that PGE's reference case
natural gas price is slightly overstated. Staff notes, however, that PGE's response to the
Commission's Bench Request, which tested a combined low natural gas price and low load
forecast scenario, continues to show very little difference between the shutdown scenarios on
an expected cost basis. Staff prefers PGE's BART II proposal because it allows adequate
time to implement a lower-risk replacement resource strategy.
f Reply Comments
In its reply comments, CUB agrees with Staff that of the options presented in
the IRP, BART II is the best performer from a least cost/least risk basis. Nonetheless, CUB
believes that the Commission should not specifically acknowledge BART II in the event the
14
ORDER NO. 10-457
EQC adopts a rule that is substatially similar to BART II, but with a different off-ramp for
the DSI technology. CUB recommends the Commission use the following language:
If the EQC adopts the BART III compliance actions or compliance
actions that are substantially similar to BART III then this
combination of pollution control investments and commitment to cease
operation at Boardman no later than 2020 provides the best
combination of expected costs and risks for customers. We
acknowledge compliance actions that are substantially similar to
BART III for the Boardman plant. 41 (emphasis in original).
NWEC also recommends that the Commission should broaden the scope of its
acknowledgment regarding Boardman to allow PGE to proceed with its proposed
refinements to BART II, should the EQC and the EPA allow it.42
CUB, NWEC, RNP, Angus Duncan, and the OEC also fied joint comments
urging the Commission to issue an acknowledgment order "flexible enough to accommodate
the refinements that PGE have worked to make possible." These parties also urge the
Commission impose a requirement on PGE that tracks with the commitment PGE has made
to certain parties to develop low-carbon portfolios for evaluation in PGE's next IR.43
2. Commission Resolution
There are six Boardman options curently under consideration:
· The BARTl option with shutdown targeted for 2040
. The Boardman through 2014 option
. PGE's proposed BART II option with shutdown targeted for 2020
. DEQ Option 1 with shutdown targeted for 2020
. DEQ Option 2 with shutdown targeted for 2018; and
. DEQ Option 3 with shutdown targeted for 2015/2016
Of these options, PGE' s proposed BART II option offers the best
combination of cost and risk for ratepayers. We consider PGE's BART II to be the superior
option because (1) it is a low-cost option for ratepayers; (2) it mitigates the risk of future
carbon regulation by closing the plant at the end of 2020; (3) it mitigates the risk of acquiring
replacement resources by providing the time needed to evaluate and implement a reasonable
replacement strategy; and(4) it provides the flexibility needed to test the effectiveness ofDSI
technology and to adapt the plant's operation to control both S02 and particulate matter (PM)
emissions prior to the plant's closure.
41 CUB's Oct 29, 2010 Comments at 4.
42 NWEC's Oct 29,2010 Comments at 2.
43 Group Comments at 2 (Oct 29, 2010).
15
ORDER NO. 10-457
The BART I option, which requires a $510 milion investment in pollution
control equipment in order to operate the plant though 2040, is too costly and too risky. The
risk of future carbon regulation, whether it takes the form of cap-and-trade regulation, carbon
taxation, or the mandated closure of specific coal plants, makes this an inferior option for
ratepayers. Under a worst-case scenario, PGE's ratepayers could potentially pay the cost of
replacing Boardman with low carbon emission resources while continuing to pay for
pollution control equipment at a plant that no longer operates.
DEQ Option 3, which calls for shutdown of the Boardman plant in late 2015
or early 2016, does not allow enough time for PGE and interested paries to develop and
implement a reasonable resource replacement strategy. PGE has argued that any replacement
for Boardman needs to be a base load resource and has modeled replacement with a natural
gas CCCT. The Joint Parties and others have indicated a strong preference for replacing
Boardman with a mix of renewable resources. The choice of the best replacement resources
is a complex decision that should be considered in PGE's IRP process. Closing Boardman in
late 2015 or early 2016 does not allow enough time to fully consider and develop alternative
replacement options and could result in ratepayers bearing higher costs in the long-run. The
same logic and conclusion applies to the Boardman through 2014 option.
DEQ Option 1, which requires a $343 milion investment in pollution control
equipment and closes the Boardman plant in 2020, is simply too costly for ratepayers. In
PGE's IRP modeling, this option and the BART I option are consistently the highest cost
options over a wide range of potential futures, including both PGE's reference case scenario
and our Bench Request scenario.
DEQ Option 2 lacks the flexibility needed to test the effectiveness of OS I
technology and to adapt the plant's operation to control both S02 and PM emissions prior to
shutdown in 2018. This lack of flexibility makes operating the plant to 2018 a more risky
endeavor. If OSI technology is incapable of controlling S02 emissions without
simultaneously violating PM emission standards, then PGE and its ratepayers would be
confronted with the choice of making an expensive investment in additional pollution control
equipment or closing the plant prior to the 2018 target. The increased risk of shutdown prior
to 2018 raises the issue of having enough time fully develop and implement a reasonable
resource replacement strategy. For these reasons, we find PGE's BART II option to be
superior to OEQ Option 2.
As noted, PGE requested that OEQ re-open its BART rulemaking to consider
a refinement to PGE's BART II option. The refinement consists of a lower S02 emissions
requirement beginning July 2018 and a request to repeal the existing BART I option ifPGE's
BART II option is ultimately approved by the EQC and the EPA. With this refinement, and
a PGE commitment to work with regional stakeholders to develop low-carbon resource
portfolios for consideration in its next IRP, CUB, NWEC, OEC, and RNP now support
Boardman shutdown no later than 2020.
PGE proposes to reach the lower S02 emissions standard with increased use
of OS I beginning in July 2018. This change increases the total expected net present value
16
ORDER NO. 10-457
cost of the BART II option by $10 milion. This change in cost is not significant enough to
alter our finding that BART II is the best option for ratepayers. We acknowledge both
PGE's original and refined BART II options.
We decline, however, to adopt CUB's recommendation to acknowledge other
compliance actions that are "substantially similar" to BART II for the Boardman plant.
Although we share CUB's preference to not be involved in an IR Update proceeding that is
comparng small differences in BART compliance actions, the evaluation of differences in
resource portfolios is complex and the determination that two options are equivalent is not
amenable to allowing parties to interpret the phrase "substantially similar."
We also decline to acknowledge BART I as a backstop option. The
acknowledgement of a backstop option would require us to predict or prejudge which
compliance options might remain if the EQC denies PGE' s BART II proposal. If the EQC
denies the Company's BART II proposal, then PGE has the ability to present its next
preferred option, and ask for Commission acknowledgment, in an IR Update. There is no
limit on the frequency ofIRP Updates and, if needed PGE can expeditiously file a
Boardman-Only Update and also file a general IRP Update a year from now.
We also decline to not acknowledge BART i. We wil wait for the EQC to
make its decision on BART II before we consider any backstop option. Our decisions do
not address the question of the prudence of pursuing the BART I compliarice actions; they
simply mean that we refuse to prejudge the EQC's actions.
Finally, our acknowledgement ofPGE's BART II, conditional on EQC
approval, does signal our intention to address the replacement strategy for Boardman in
PGE's next IRP.
D. Cascade Crossing
The Cascade Crossing Transmission Project (Cascade Crossing) is a proposed
500 kV transmission line connecting PGE's Boardman and Coyote Springs plants to the
southern portion of the Company's service territory. The proposed project would begin at
the Coyote Springs' substation, go to the Boardman plant, and terminate at PGE's Bethel
substation. The project would parallel existing utility lines for the first 106 miles from the
Boardman substation toward Bethel, and parallel PGE's existing Bethel-to-Round Butte 230
kV line over the Cascades for the last 77 miles. The project wil require the construction of a
500/230 kV substation, 500/230 kV transformer, and 500/230 kV transformer ban, as well
as improvements to two existing substations.44
PGE asserts that Cascade Crossing wil (1) directly connect west-side load to
existing and new resources on the east side of the Cascade; (2) add transfer capacity to the
Cross-Cascades South and West ofSlatt cutplanes; (3) reduce stress on the 1-5 cutplanes by
providing another path to its system from the south; (4) provide firm transmission service for
44 IRP at 187.
17
ORDER NO. 10-457
existing generators as an alternate to service furnished by the Bonnevile Power
Administration (BPA); and (5) improve reliability by providing additional transmission and
reducing load on transfer paths parallel to Cascade Crossing, thus reducing the severity of
curently limiting contingencies.45
PGE conducted a benefit-cost analysis of the Cascade Crossing transmission
project to determine whether it should include Cascade Crossing its IRP Action Plan and
continue to invest in the project. The choice analyzed was whether it is preferable for PGE's
ratepayers to continue to purchase transmission capacity from the BP A or to obtain
transmission capacity by building Cascade Crossing. PGE' s analysis consisted of five case
studies with different assumptions regarding third part equity participation in Cascade
Crossing and different assumptions regarding the growth of BP A's transmission rates after
2025.
PGE analyzed both a single-circuit and double-circuit configuration ofthe
Cascade Crossing. For the single-circuit configuration, PGE estimated total project costs to
be $613 milion and assumed a path rating of 1,500 MW of transfer capability. For the
double-circuit configuration, PGE estimated total costs of $823 milion and assumed a
transfer capability of2,200 MW. Under Case 3, its mid-point case study, PGE fuher
assumed that it would partner with a third part to share the costs of the 17 -mile segment of
transmission line from Coyote Springs to Boardman and for the expansion of the Coyote
Springs' substation.
PGE estimated the cost of continued service from BP A by assuming that
BPA's current transmission rates experience a one-time increase of 10 percent in 2015 and
grow at an average nominal rate of 4 percent from 2011 to 2025. Under its mid-point case
study, PGE further assumed that BPA transmission rates grow at a rate of3.2 percent from
2025 to 2082. In all five of the case studies, PGE included approximately $65.5 milion for
new transmission substations and radial lines needed to connect PGE's planned resources to
the BP A transmission system.
PGE, through its case studies, considered higher and lower levels of equity
participation and higher and lower growth ofBPA's transmission rates after 2025. For
example, in Case 1, PGE assumed no equity paricipation in the 17 -mile line segment from
Coyote Springs to Boardman and a growth rate of2.5 percent in BPA's transmission rates
after 2025. In Case 5, PGE assumed an additional third party equity share equivalent to 209
MW of transfer capability under the single-circuit configuration (or 300 MW under the
double-circuit configuation) and a growth rate of3.5 percent in BPA's transmission rates
after 2025.
PGE seeks acknowledgment to build Cascade Crossing as a double-circuit 500
kV and alternatively, as a single-circuit 500 kV facility. PGE states that whether it proceeds
with Cascade Crossing, as either a double-circuit or single-circuit, wil depend on future
economic analysis incorporating refined cost estimates, updated information regarding path
rating, the level of equity participation from third parties, transmission service requests
45 ¡d. at 189-190.
18
ORDER NO. 10-457
received by PGE, and updated information regarding PGE's generation facilities that would
utilize the project.
1. Parties' Positions
RNP believes Cascade Crossing wil directly facilitate wind interconnections
and wil provide links between eastern Oregon wind, solar, and geothermal resources with
western load centers. RNP supports acknowledgment of Cascade Crossing so long as it can
be responsibly sited and developed within parameters of a sensible and timely cost-benefit
analysis. RNP recommends that the Commission require PGE to update its analysis
regarding Cascade Crossing in a future IRP or IRP Update.46
CUB does not recommend against acknowledging Cascade Crossing, but
raises numerous questions and concerns. These include: (1) Why does the expected closure
of Boardman not affect PGE's plan for Cascade Crossing; (2) Why aren't BPA transmission
services suffcient to serve PGE's needs; (3) Does PGE have suffcient experience to manage
constrction of Cascade Crossing without incurng significant cost overrns; and (4) Should
new transmission be a top priority for PGE?
Wilard Rural Association (WRA) recommends that the Commission not
acknowledge Cascade Crossing. WRA asserts that PGE made many forecasting errors,
including: (1) overstating its load forecast; (2) understating the amount of transmission BPA
wil have in the future; (3) overstating the cost of BP A transmission; (4) underestimating the
cost to acquire right of way for Cascade Crossing; and (5) understating the risk associated
with an $823 milion investment.
Staff recommends that the Commission acknowledge Cascade Crossing in the
double-circuit configuration, subject to the requirement that PGE provide the Commission
certain information and updated analysis in its next IRP Update. Staff asserts that PGE's
proposal to acquire a transmission resource is supported by analysis under IRP Guideline 8.
Staff agrees with PGE's conclusions that adding transmission to PGE's system wil allow
additional purchases and sales, access to less costly resources in remote locations, access to
renewable resources developed on the east side of the state, and wil improve reliability.
Staff also asserts that PGE's financial and qualitative analyses (some done in
response to a Staff data request) support PGE's proposal to build Cascade Crossing, as
opposed to acquiring transmission in another manner.
2. Commission Resolution
The primary benefit of Cascade Crossing is that PGE can avoid futue
increases in BP A's transmission rates. Cascade Crossing can achieve these savings by
connecting PGE's existing Boardman and Coyote Springs plants, and any new generation
located in eastern Oregon, directly to PGE's load. PGE's analysis shows that the single-
circuit configuration of Cascade Crossing provides net benefits to ratepayer under the mid-
46 RNP's Sept 1,2010 Comments at 3.
19
ORDER NO. 10-457
point and high equity participation cases. The double-circuit configuration only shows net
benefits under the high equity participation cases.
PGE did not attempt to quantifY all ofthe potential benefits of Cascade
Crossing in its benefit-cost analysis. For example, in all cases PGE assumed zero revenues
from transmission sales or use in the west-to-east direction. PGE also did not estimate the
potential reliability benefits or the savings in energy losses that would accrue to PGE
ratepayers from building Cascade Crossing.
Further, under both the single- and double-circuit configuations, Cascade
Crossing would provide other load serving entities the opportity to access new renewable
resources located east of the Cascade Mountains. Pacific Power recently signed a
Memorandum of Understanding with PGE to explore obtaining an equity share in the line
equivalent to 600 MW ofbi-directional transfer capability.
PGE's benefit-cost analysis is sufficiently robust, and shows suffcient net
benefits under certain scenarios, to allow us to acknowledge Cascade Crossing at this time.
However, when developing an IR, we always expect utilities to update their assessments of
previously acknowledged projects that are stil in the planing or development stages. We
make this updating requirement explicit for the Cascade Crossing project because of the
curent uncertainty regarding equity participation and other key factors. We expect PGE to
provide a thorough update of the Cascade Crossing benefit-cost analysis in its next IRP, with
the understanding that Commission acknowledgment of the Company's next IRP wil depend
on the outcome of that updated analysis. Therefore, we acknowledge Cascade Crossing with
the following requirement:
PGE shall include an updated benefit-cost analysis of the Cascade
Crossing transmission project in its next IR. For the updated
analysis, PGE shall update its assumptions about project configuration,
capital cost, path rating, wheeling revenues, and equity participation
and conduct sensitivity analyses that address any uncertainty about
capital cost, path rating, levels of equity participation, and levels of
wheeling revenues.
Finally, we reiterate that, at the time of rate making, each utility is required to
show that its investment was a prudent decision. At that time, the utility wil be expected to
address any significant changes in construction cost, path rating, equity partnership, or third-
part subscription and how these changes influenced the Company's decision to continue
with the project.
E. Demand Response
1. Parties' Positions
Staff contends that PGE did not comply with IR Guideline 7 regarding
demand response (DR) because the Company failed to evaluate DR "on par" with other
20
ORDER NO. 10-457
options for meeting energy, capacity, and transmission needs. Staff notes that PGE included
60 MW of firm DR in its portfolios in 2012 through 2016 (50 MW from an RFP and 10 MW
from a curtailment tariff option for large industral customers) but that the Company did not
explain why those were the only DR resources projected in that time period. Staff
recommends that the Commission direct PGE to meet Guideline 7 and provide certain
information on projected amounts and costs of DR in its next IRP Update.47
CUB notes that PGE has not made much progress towards acquiring
significant DR since the Commission approved the company's Advanced Metering
Infrastructure (AMI) proposal in 2008. CUB agrees with Staff that PGE did not adequately
analyze DR in the IRP and recommends that Commission require the company to report in
the next IRP Update what steps it wil be taking to evaluate DR programs in the Company's
next full IR.48
In response, PGE contends that it did comply with the guideline, pointing out
in paricular that it evaluated DR on par with other resource options by assessing and
selecting DR using a benefit/cost ratio based on an alternative capacity resource (a simple
cycle combustion tubine or SCCT).49
2. Commission Resolution
We share the concerns expressed by Staff and CUB. PGE evaluated DR
against an SCCT but did not provide DR cost information in the IRP. The Company
included 10 MW from a critical peak pricing (CPP) program as a capacity resource in its last
(2007) IRP but did not do so in its 2009 IRP, without really explaining the change (other than
to say now that it primarily assumes acquisition of firm DR resources). PGE has not made
the progress we expected on acquisition of DR, e.g., it has delayed its CPP pilot for a year,
and its RFP for direct load control resources was unsuccessfuL.
We believe that DR can be a significant resource but realize that there is stil
much to learn about the potential for and reliability of different types of DR (mainly through
pilot programs by PGE and other electric utilities). We adopt a combination of the proposals
made by Staff and CUB and wil require PGE to provide information and show the steps it is
taking, and intends to take, to assess and acquire DR. Also, we agree with the timing of these
requirements recommended by CUB and Staff and direct PGE to comply with the following
directives at the time of its IR update:
47 Staff's Oct 15,2010 Comments at 9-10.
48 CUB's Oct 29, 2010 Comments at 5-7. CUB expressed concern about waiting two years to address DR,
apparently because it understood Staff to be proposing a condition for the next IRP. But Staff, like CUB,
recommends that PGE report on DR in the next IRP update (which should be filed a year after this order is
issued).49 PGE's Oct 29, 2010 Comments at 7-8.
21
ORDER NO. 10-457
In its next IR update, PGE must provide the following:
a. Its estimated cost per MW of capacity savings by demand
response (DR) type (i.e., firm vs. non-firm resources), and
projected MW acquisitions by DR type for the next 5 years;
b. A discussion of the steps it is and wil be taking to evaluate DR
in the Company's next IRP, and
c. An updated action plan for assessing (e.g., plans for pilot
programs) and acquiring DR for the next 3 years.
F. Energy Efficiency
1. Parties' Positions
Staff concludes that PGE met the IR guideline for conservation (IRP
Guideline 6) with two exceptions. First, Staff states that PGE did not treat
conservation voltage reduction (CVR) as a resource. Second, Staff states that PGE
did not consider whether to include CVR in the action plan. Staff notes that the
Energy Trust of Oregon identified technical potential for 19 MWa of savings from
CVR in the Company's service terrtory.
50
PGE replies that it views CVR as an operational effciency, not a long-term
resource planning issue. The Commission found that PGE complied with IRP Guideline 6
(except with respect to the planing horizon) in the Company's last IRP, even though its
treatment of CVR was the same as in the current IRP. PGE also points out that potential
CVR savings are small and would not have a material impact on its resource requirements or
action plan.51
2. Commission Resolution
We agree with Staff that PGE should consider CVR in its resource planning
and adopt the following requirement:
In its next IRP, PGE should consider conservation voltage reduction
(CVR) for inclusion in its best cost/risk portfolio and identify in its
action plan steps it wil take to achieve any targeted savings.
50 Staffs Oct 15, 2010Comments at 10-11.
51 PGE's Oct 29,2010 Comments at 8-9.
22
ORDER NO. 10-457
G. Renewable Portfolio Standard Requirements
1. Parties' Positions
PGE proposes to acquire 122 MWa of renewable wind generation by the end
of2012 to achieve physical compliance with the Renewable Portfolio Standard (RPS)
requirement for 2015. PGE asserts that baning renewable energy credits (RECs) from early
renewable resource actions provides a significant cushion for "meeting RPS compliance.,,52
Staff is concerned that PGE did not model the use of unbundled RECs to
comply with the RPS requirements for the entire planning period. Staff notes that PGE's
analysis is predicated on an assumption that PGE would comply with the RPS requirement
with physical resources, rather than unbundled RECs. Staff recommends that the
Commission require to PGE "relax" the assumption that PGE must be in physical compliance
with the 2015 RPS requirement. In other words, Staff recommends that PGE's analysis
include the possibility that PGE wil use unbundled RECs to comply with the 2015 RPS
requirement.
In support of this recommendation, Staff notes that several factors could result
in a situation in which it is more cost effective to acquire physical resources later, rather than
sooner, such as the later availability of emerging technology. Staff also notes that PGE's
concerns regarding penalties for non-compliance appear to be overstated.
The Oregon Department of Energy (ODOE) notes that PGE's plan for
physical RPS compliance overemphasizes the near term. ODOE finds the plan appropriate
where short-term REC sales provide value to current utility customers at the same time
prudent banking reduces RPS compliance risk beyond 2020. ODOE notes, however, that
PGE should address the substantial REC output to be made available in 2011 due to the
recent passage of House Bil 3674. ODOE reports that the bil makes a number of pre-1995
biomass facilities eligible for the RPS with the condition that REC output from those
facilities cannot be used until 2026. ODOE notes that these facilities are expected to produce
over 7 milion RECS.53
ODOE also notes that PGE's IRP contains an incorrect conclusion regarding
the penalty risk associated with failure to meet the RPS requirement. ODOE notes that the
Alternative Compliance Payment is not a direct penalty as the RPS allows a varety of paths
for a utility to invest those payments toward future project development. 54
PGE disagrees with Staffs recommendation that PGE should project future
prices and availability for unbundled RECs to assess the potential for acquiring unbundled
RECs to meet Oregon's RPS. PGE states, "(w)e believe that, given the lack ofliquidi% and
transparency in the REC markets, it would not be prudent to rely on such projections." 5
52 IRP at 114.
53 ODOE's May 14,2010 Comments at 3.
54 !d. at 4.
55 PGE's Oct 29,2010, Comments at 10.
23
ORDER NO. 10-457
2. Commission Resolution
We see no reason that POE's analysis of the least cost and least risk method to
comply with RPS requirements should exclude the possibility of using unbundled RECs to
meet RPS requirements at any point in the planning period, including the early years. Both
Staff and ODOE identify circumstances that could lead to the conclusion that relying on
unbundled RECs in early years ofthe planning period could be least cost and least risk.
Accordingly, we adopt the following requirement
In its next IR Update and in the next planning cycle, POE must evaluate:
(1) The use of unbundled renewable energy credits (RECs) in its strategy to
meet RPS Requirements for the entire planning period; and
(2) Alternatives to physical compliance with renewable portfolio standard
(RPS) requirements in a given year, including meeting the RPS
requirements in the most cost-effective/ least risk manner that takes into
consideration technological innovations, expiration or extension of
production tax credits, and different levels of integration costs for
renewable resources.
H. Wind Integration Study
1. Parties' Positions
RNP recommends that the Commission not acknowledge the wind integration
study POE used to estimate costs to operate and acquire wind generation. RNP asserts that
POE's study includes an unusually high cost of reserves and has not been provided for
stakeholders and the Commission to evaluate.56 RNP recommends that the Commission
order POE to continue to use the BP A wind integration rate to model new wind resources
until such time as POE is prepared to fully engage with stakeholders in review of its
methodology and results.
Staff agrees that POE did not comply with the Commission's order stemming
from POE's last IRP to "include in the (next IRP) analysis a wind integration study that has
been vetted by regional stakeholders.,,57 Staff echoes RNP's statements that POE has not
produced a study whose detailed methodology and results have been made available for
review.
POE disputes RNP's assertion that the wind integration costs underlying
POE's IRP analysis are unreasonably high. POE notes that RNP's assertions are largely
based on comparisons to other utilities' costs and to BP A's Balancing Authority within-hour
integration tariff. POE notes that these comparisons are inappropriate because: (1) each
56 RNP's Sept 1,2010 Comments at 1-3.
57 Docket LC 48, Order No. 08-246 at 10 (May 6, 2008).
24
ORDER NO. 10-457
utility's costs depend on the unique characteristics of the utility's system; and (2) POE's
wind integration costs is comprised of several components, only one of which is comparable
to the within-hour integration tariff.
58
POE also disputes RNP's and Staffs criticisms of the wind integration study
process. POE states that it included several stakeholders on its technical review committee to
evaluate the Company's study approach, inputs and findings, and conducted a three-hour
workshop to present the details of its wind integration study. POE also notes that, in addition
to the input it received from stakeholders the Company hired an independent examiner (IE)
in late 2008 to "vet" the study for docket UM 1345, and that the IE concluded the study was
a "thorough integration study.,,59 Nonetheless, although it believes it has already complied
with the requirement to produce a vetted wind integration study, POE agrees with Staffs
recommendation to include in its next IRP Update a wind integration study that has been
vetted by regional stakeholders.6o
2. Commission Resolution
We agree with RNP that it is important that "vetting" by regional stakeholders
of a wind integration study include opportnity for regional stakeholders to examine, in
detail, the methodology of the study and the results. We also believe that when vetting
POE's wind integration study, stakeholders should have the opportity to comment on the
methodology and make recommendations. Also, it is incumbent on POE to respond to any
such comments and, to the extent it does not adopt recommendations of stakeholders, explain
why.
As POE itself acknowledges, the stakeholder "vetting" consisted of
preliminary input from a technical group and a workshop attended by POE and interested
parties. POE's presentation at the workshop, a hard copy of which POE attached to its
comments, reflects that POE informed stakeholders how it intended to go about the study.
As RNP and Staff note, such a presentation is not a substitute for an opportity for regional
stakeholders to evaluate the methodology that POE actually used and the results obtained
from the methodology. Accordingly, we impose the following requirement:
In its next IRP planning cycle, POE must include a wind integration
study that has been vetted by regional stakeholders.
I. Risk Metrics
1. Parties' Positions
Staff cautions the Commission about the possible misinterpretation of two risk
metrcs used by POE in its 2009 IRP. POE calculated the "Average of Worst Four Futures
58 PGE's Sept 27, 2010 Reply to Intervenor Response Comments at 18.
59 PGE's Oct 29, 201OComments at 11.
60 ¡d.
25
ORDER NO. 10-457
Less the Reference Case Cost,,61 and "TailVar90 Less the Mean" risk metrcs by subtracting
a resource portfolio's reference case or mean cost from the average of its "worst-case" or
highest-cost outcomes. According to Staff, these calculations can produce counter-intuitive
and misleading results. The problem is that the risk metrics may assign a lower risk to a
portfolio that has both a higher expected (or reference case) cost and a higher extreme (or
worst case) cost. Staff recommends that the Commission rely on PGE's "Average of Worst
Four Futures" and "TailVar0" risk metrics that do not subtract the reference case or mean
value from the high cost outcomes.
RNP and NWEC also take issue with these two risk metrics. NWEC asserts
that these risk metrics are measures of spread or variability, and not measures of risk of bad
outcomes. NWEC argues that "any metrics such as these that subtracts out the mean, in
cases where the mean can be very different across tested portfolios, is faulty, since high
variability in itself is not a bad outcome.,,62 RNP asserts the metrics do not measure relevant
risks.63 RNP and NWEC also object to PGE' s "Y ear-to- Year Variation" risk measure.
64
RNP recommends that the Commission require PGE to revise its methodology
in futue IRPs to appropriately reflect relevant risk factors, dropping duplicative or irrelevant
metrics and adding a risk metric proportional to emissions of pollutants, including carbon
dioxide.65 NWEC urges the Commission to direct PGE to improve futue IRPs to correct the
flaws in its risk analysis and portfolio scoring.66 NWEC argues that the risk metrics used by
PGE assign no weight to the risk of future carbon regulation because they average scenarios
with high and low carbon costs. NWEC recommends that the Commission require future
IRPs to include a risk metric that directly measures carbon dioxide emissions.
In response to NWEC's and RNP's criticisms, PGE asserts that the disputed
risk metrcs are required by IRP Guideline 1 c, which require two measures of risk; one that
measures the variability of costs, and one that measures the severity of bad outcomes.67
According to PGE, the disputed risk metrics satisfy the requirement to have a measure of the
variability of costs. The Average of Worst Four Futures and TailVar90 risk measures satisfy
the requirement to have a measure of the severity of bad outcomes. Finally, according to
PGE, the "Year-to- Y ear Variance Metric," is necessary because rate stability is important to
customers.68 PGE also rebuts NWEC's assertion its risk metrics assign no weight to future
carbon regulation by indicating that the Average of Worst Four Futures and TailVar90 risk
metrics do not combine or average high and low C02 price futures.
61 POE also refers to this metric as the "Deterministic Portfolio Risk Variability vs. Reference Case." See IRP
at 249.62 NWEC's May 14,2010 Comments at 13.
63 RN's May 20, 2010 Comments at 3.
64 !d.
65 !d.
66 NWEC's May 14,2010 Comments at 14.
67 POE's Aug 10,2010 Comments at 46.
68 !d. at 47.
26
ORDER NO. 10-457
Staff agrees that the Y ear-to- Year Variance Metric is an important measure of
the variability in costS.69 According to Staff this specific metric obviates the need for the
disputed metrics that can be misleading.
2. Commission Resolution
In its 2009 IRP, PGE models the risk and uncertainty associated with load
requirements, natural gas prices, electrcity prices, plant forced outages, and the cost of
compliance with the future regulation of greenhouse gas emissions. Although we share
concerns about some of the specific measures used by PGE, PGE's 2009 IRP includes risk
metrcs that measure both the variability of costs and the severity of bad outcomes for each of
the candidate resource portfolios considered in the plan. PGE's risk analysis is robust and
satisfies the requirements ofIRP Guidelines Ib, lc, 4i, 4j and 8a.
We decline to adopt NWEC's and RNP's recommendations to require PGE to
drop the disputed risk metrics as long as they continue to provide measures that comply with
the IR risk guidelines. We also decline to require PGE to add an additional metrc that
measures a portfolio's carbon dioxide emissions in its next IRP. PGE provided carbon
dioxide emissions analysis, including total emissions in short tons and emissions in short tons
per megawatt-hour, for each of the portfolios under consideration in its 2009 IR. We
encourage Staff and other parties to continue to identify risk metrics and results that require
careful interpretation and to make resource recommendations based on the metrics and
results they find to be most relevant.
J. Reliabilty
1. Parties' Positions
NWEC comments that PGE's expected unserved energy (EUE) reliability
metric measures a resource portfolio's exposure to the wholesale power market and is
independent of the portfolio's mix of resources. NWEC notes that, because the EUE metrc
is a measure of market exposure, it is possible to improve a portfolio's performance simply
by adding additional resources. NWEC asserts that the EUE metrc should not be used to
judge the reliability ofPGE's resource portfolios. 70
Staff also takes issue with PGE's reliability analysis. Staff notes Guideline 11
requires the utility to determine by year for top-pedorming portfolios (l) the loss of load
probability (LOLP), (2) the expected plannng reserve margin, and (3) the expected and
worst-case unserved energy. Staff asserts that PGE included neither the LOLP metric nor
conventional metrics for EUE and Worst-Case Unserved Energy in scoring of its resource
portfolios.
Staff notes that instead of calculating a conventional EUE metrc, PGE
calculated a conditional EUE (CEUE) metrc. CEUE is defined as the average amount of
69 IRP at 267; 285.
70 NWEC's Sept i, 2010 Comments at 6-8.
27
ORDER NO. 10-457
unserved energy that occurs given the occurence of an unserved energy event. Staff echoes
NWEC's concern with this metric. Staff notes that a portfolio can get a low CEUE score
even ifit has a high frequency of unserved energy events. In other words, a paricular
portfolio may suffer from frequent exposure to the wholesale power market, but due to a low
purchase amounts durng these events receive an overall favorable CEUE score. Staff
recommends that the Commission require PGE to pedorm the analyses required by
Guideline 11 in PGE's next IRP Update.
PGE denies NWEC's assertion that PGE's EUE metrc is independent of the
resource mix of IRP portfolios. PGE asserts that this metrc "addresses the relative reliability
of the portfolios based on the paricular resources in them, with their assumed associated
forced outage rates and mean times to repair. 71
2. Commission Resolution
IRP Guideline 11 specifically requires electric utilities to provide measures of
expected and worst-case unserved energy for the top-performing resource portfolios. PGE's
EUE and CEUE metrics measure a portfolio's overall exposure to the wholesale power
market, not annual unserved energy. PGE correctly points out that its metrcs also reflect the
forced outage rates and mean times to repair of the resources included in the portfolios.
However, we cannot tell whether differences in outage rates and repair times impact the
likelihood and amount of unserved energy. It is important to be able clearly distinguish
between a portfolio's market exposure and its level of expected unserved energy.
This gap in the metrcs used by PGE does not impact on our decisions in this
IRP. In its 2009 IRP, PGE constructed its resource portfolios to meet specific energy and
capacity targets. With a few noted exceptions, all ofPGE's resource portfolios reflect similar
levels of wholesale market exposure. Since all the portfolios have roughly the same market
exposure, differences in the EUE metric largely reflect difference in the portfolios' overall
generation outage rate.
We direct PGE to work with Staff, NWEC, and other paries in its next IR
cycle to develop reliability metrcs that measure unserved energy. We recognize that this
may require parties to estimate the depth of the wholesale power market over the IRP
planning period.
71 POE's Aug 10,2010 at 34, citng its 2009 IRP at 245-247.
28
ORDER NO. 10-457
III. CONCLUSION
POE's 2009 IRP reasonably adheres to the principles of resource
planning established in Orders No. 89-507 and 07-002 and is acknowledged with the
following requirements:
In its next IRP, PGE must:
1. Include an updated benefit-cost analysis of the Cascade Crossing
transmission project. For the updated analysis, POE shall update its
assumptions about project configuration, capital cost, path rating,
wheeling revenues, and equity participation, and conduct sensitivity
analyses that address any uncertainty about capital cost, path rating,
levels of equity participation, and levels of wheeling revenues.
2. Provide the following:
(a) Its estimated cost per MW of capacity savings by Demand
Response (DR) type (i.e., firm vs. non-firm resources), and
projected MW acquisitions by DR type for the next 5 years,
(b) A discussion of the steps it is and wil be taking to evaluate
DR in the next IR, and
(c) An updated action plan for assessing (e.g., plans for
pilot programs) and acquiring DR for the next 3 years.
3. Consider Conservation Voltage Reduction (CVR) for inclusion in
its best cost/risk portfolio and identify in its action plan steps it
wil take to achieve any targeted savings.
In its next IRP Update and in its next IRP planning cycle, PGE must:
1. Include a Wind Integration Study that has been vetted by regional
staeholders.
2. Evaluate the use of unbundled RECs in its strategy to meet RPS
requirements for the entire planning period.
3. Evaluate alternatives to physical compliance with RPS Requirements
in a given year, including meeting the RPS Requirements in the most
cost-effective/least risk manner that takes into consideration
technological innovations, expiration or extension of production tax
credits, and different levels of integration costs for renewable
resources.
29
ORDER NO. 10-457
iv. ORDER
IT is ORDERED that:
1. The 2009 Integrated Resource Plan fied by Portland General Electric
Company is acknowledged with the requirements set forth in this
order.
2. Poi1land General Electric Company wil fie its next Integrated
Resource Plan no later than November 19,2012.
Made, entered, and effective NOV 2 8 2010
//
ê~tr~
Susan K. Ackerman
Commissioner
't...3l 'h:utl'
c'.
"ilyBaum
.~ ChaIlman
30
BEFORE THE
r
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO.IPC-E-11-18
. IDAHO POWER COMPANY
ATTACHMENT NO.4
Federal Register/Vol 76 No 128/Tuesday July 5 2011/Rules and Regulations 38997,,,
Name of non-~ei;ulatory sip re-Applicable geographic area State submittal EPA approval date Additional explanationvisiondate
.......
8-Hour Ozone Maintenance Tioga County ..........................9/28/06, 11/14/7/6/07, 72 FR 36892 ...............
Plan and 2002 Base Year 06
Emissions Inventory.
.......
(2) * * *
Name of source Permit State Additional explanation/§ 52.2063
No.County submittal EPA approval date citationdate
09-0006 Bucks .....................8/11/95,4/09/96, 61 FR 52.2036(b);52.2037(c);source shut-
11/15/95 15709.down date is 8/1/91.
37-065 Lawrence ................4/8/98 4/16/99, 64 FR 52.2036(k); source shutdown date is 4/
18818.1/93.
28-2008 Franklin ..................4/26/95 3/12/97, 62 FR 52.2037(h);52.2063(c)(114)(i)(A)(3)&
11079.(ii)(A).
USX Corp./US Steel Group-
Fairless Hills.
Rockwell Heavy Vehicle, Inc.-
New Castle Forge Plant.
Mercersburg Tanning Co.
(FR Doc. 2011-16636 Filed 7-1-11; 8:45 am)
BILLING CODE 65o-SO-P
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
(EPA-R1 lHAR-2011-Q035; FRL-9425-)
Approval and Promulgation of
Implementation Plans; State of
Oregon; Regional Haze State
Implementation Plan and Interstate
Transport Plan
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: EPA is approving portions of
a State Implementation Plan (SIP)
revision submitted by the State of
Oregon on December 20, 2010, as
meeting the requirements of Clean Air
Act (CAA) section 110(a)(2)(D)(i)(II as it
applies to visibilty for the 1997 8.hour
ozone and 1997 particulate matter
(PM2.S) National Ambient Air Quality
Standards (NAAQS). EPA is also
approving portions of the revision as
meeting certain requirements of the
regional haze program, including the
requirements for best available retrofit
technology (BART).
DATES: Effective Date: This final rule is
effective August 4, 2011.
ADDRESSES: EPA has established a
docket for this action under Docket ID
No. EPA-RI0-GAR-201D-0035. All
documents in the docket are listed on
the http://ww.regulations.govWeb
site. Although listed in the index, some
information is not publicly available,
e.g., Confidential Business Information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material. such as
copyrighted material, is not placed on
the Internet and wil be publicly
available only in hard copy form.
Publicly available docket materials are
available either electronically through
http://ww.regulations.gov or in hard
copy at the State and Tribal Air
Programs Unit, Office of Air Waste and
Toxics, EPA Region 10,1200 Sixth
Avenue, Seattle. WA 98101. EPA
requests that if at all possible, you
contact the individual listed in the FOR
FURTHER INFORMATION CONTACT section to
view the hard copy of the docket. You
may view the hard copy of the docket
Monday through Friday, 8 a.m. to
4 p.m., excluding Federal holidays.
FOR FURTHER INFORMATION CONTACT:
Keith Rose, EPA Region 10, Suite 900,
Office of Air, Waste and Toxics, 1200
Sixth Avenue, Seattle, WA 98101.
SUPPLEMENTARY INFORMATION:
Defitions
For the purpose of this document, we
are giving meaning to certain words or
initials as follows:
(i) The words or initials Act, CAA, or
Clean Air Act mean or refer to the Clean
Air Act, unless the context indicates
otherwise.
(ii) The words EPA, we, us or ourmean or refer to the United States
Environmental Protection Agency.
(iii) The initials SIP mean or refer to
State Implementation Plan.
(iv) The words Oregon and State
mean the State of Oregon.
Table of Contents
i. Background Information
II. Response to Comments
II. Final Action
IV. Oregon Notice Provision
V. Scope of EPA Approval
VI. Statutory and Executive Orders Review
I. Background Inormation
On July 18, 1997, EPA promulgated
new NAAQS for 8-hour ozone and for
fine pariculate matter (PM2.S)' This
action is being taken, in part, in
response to the promulgation of the
1997 8-hour ozone and PM2.S NAAQS.
Section 110(a)(1) of the CAA requires
states to submit a SIP revision to
address a new or revised NAAQS within
3 years after promulgation of such
standards, or within such shorter period
as EPA may prescribe. Section 110(a)(2)
lists the elements that such new SIPs
must address, as applicable, including
section 110(a)(2)(D)(i), which pertains to
interstate transport of certain emissions.
Section 110(a)(2)(D)(i) of the CAA
requires that a SIP must contain
adequate provisions prohibiting any
source or other type of emissions
activity within the state from emitting
38998 Federal Register/Vol. 76, No. 128/Tuesday, July 5, 20ll/Rules and Regulations
any air pollutant in amounts which will:
(1) Contribute significantly tononattainment of the NAAQS in any
other state; (2) interfere with
maintenance of the NAAQS by any
other state; (3) interfere with any other
state's required measures to prevent
significant deterioration of air quality;
or (4) interfere with any other state's
required measures to protect visibilty.
This action addresses the fourth prong,
section 110(a)(2)(D)(i)(II.
In the CAA Amendments of 1977,
Congress established a program to
protect and improve visibilty in the
national parks and wilderness areas. See
CAA section 169(A). Congress amended
the visibilty provisions in the CAA in
1990 to focus attention on the problem
of regional haze. See CAA section
169(B). EPA promulgated regulations in
1999 to implement sections 169A and
169B ofthe Act. These regulations
require states to develop and implement
plans to ensure reasonable progress
toward improving visibilty in
mandatory Class I Federal areas 1 (Class
I areas). 64 FR 35714 (July 1, 1999); see
also 70 FR 39104 (July 6, 2005) and 71
FR 60612 (October 13, 2006).
On December 20, 2010, the State of
Oregon submitted to EPA a State
Implementation Plan (SIP) revision
addressing the interstate transport
requirements for visibilty for the 1997
ozone and PMz.5 NAAQS, see CAA
§ 110(a)(2)(D)(i)(II, and the
requirements of the Regional Haze
program at 40 CFR 51.308. (Regional
Haze SIP submittal).
On March 8,2011. EPA published a
notice in which the Agency proposed to
approve the Oregon SIP revision as
meeting the requirements of both
section 110(a)(2)(D)(i)(II) of the CAA
and the Regional Haze requirements set
forth in sections 169A and 169B of the
Act and in 40 CFR 51.300-308 with the
exception of Chapter 11, Oregon
1 Areas designated as mandatory Class I Federal
areas consist of national parks exceeding 6000
acres. wilderness areas and national memorial parks
exceeding 5000 acres, and all international parks
that were in existence on August 7, 1977. 42 U.S.c.
7472(a). In accordance with section 169A ofthe
Clean Air Act, EPA, in consultation with the
Deparment of the Interior, promulgated a list of 156
areas where visibilty is identified as an important
value. 44 FR 69122 (November 30, 1979). The
extent of a mandatory Class I area includes
subsequent changes in boundaries, such as park
expansions. 42 U.S.C. 7472(a). Although states and
tribes may designate as Class I additional areas
which they consider to have visibility as an
important value, the requirements of the visibilty
program set fort in section 169A of the Clean Air
Act apply only to "mandatory Class I Federal
areas." Each mandatory Class I Federal area is the
responsibility of a "Federal Land Manager." 42
U.S.c. 7602(i). When we use the term "Class I area"
in this action, we mean a "mandatory Class I
Federal area."
Reasonable Progress Goal
Demonstration and Chapter 12, Long-
Term Strategy. 76 FR 12651. (Notice of
Proposed Rulemaking or NPR). For
Oregon's Reasonable Progress Goal
Determination and Long-Term Strategy,
EPA did not propose taking any action.
II. Response to Comments
EPA received a number of comments
on the proposed action to approve
certain elements of the Regional Haze
SIP submittaL. Comments in support
were received from: The Citizens'
Utilty Board of Oregon; International
Brotherhood of Electrical Workers Local
125; Morrow County; and Portland
General Electric Company (PGE).
Adverse comments were received by
two entities: The National Parks and
Conservation Association (NPCA); and
Pacific Environmental Advocacy Center
(PEAC). The comments submitted byNPCA incorporated multiple comments
which were previously submitted to
Oregon Department of Environmental
Quality (ODEQJ on some of the priorproposals the State was previously
considering. Some of these comments
related to options, closure time frames or
evaluations which were previously
considered by ODEQ but were not
included in the final Regional Haze SIP
submission. Accordingly, because these
now superseded aspects of ODEQ's
BART analysis or determination are not
before EPA. a response to the comments
about those options is not necessary.
The following discussion summarizes
and responds to the relevant comments
received on EPA's proposed SIP action
and explains the basis for EPA's final
action.
Comment: The Citizens' Utility Board
commented that the ODEQ BART rules
for the PGE coal-fired electric power
plant at Boardman, Oregon (PGE
Boardman or Boardman facility) allow
for cost effective pollution controls
which wil reduce air pollution
generated by the facility, including air
pollutants which contribute to haze in
Class 1 areas. The commenter states that
the rules also require the Boardman
facilty to be shut down by December
31,2020 and the shut down allows the
State of Oregon to move forward with its
goals to reduce carbon emissions
statewide and wil protect utilty
customers from the costs and risks that
wil be associated with carbon
regulation. The commenter further
stated that the Best Available Retrofit
Technology (BART) rules approved by
the ODEQ are the product of several
years of work resulting from a
collaborative process involving state
agencies, environmental organizations,
consumer groups, local governments.
and other stakeholders. The rules result
in significant reductions in air
pollution, while allowing Oregon to
pursue important state policies targeted
towards reducing carbon emissions. and
keeping electric rates affordable.
Response: EPA acknowledges the
comment and notes that there wil be a
significant reduction in NOx and SOz
from the Boardman facility due to the
BART controls for those pollutants, and
the further reasonable progress limits for
SOz in 2018. Also, ceasing to use coal
at the Foster-Wheeler boiler by end of
2020, wil result in a additional
reduction of NOx, SOz, and carbon
dioxide emissions from the facility and
significant cumulative visibilty
improvement in all impacted Class I
areas.
Comment: International Brothers of
Electrical Workers Local 125
commented that the Boardman facility
is more than an electrical generating
plant and that the city of Boardman and
county of Morrow are dependent on this
a facilty for a substantial portion of its
revenue. Boardman's citizens and
Morrow County's resident recognize
that the facilty wil cease using coal by
the end of 2020. but are hopeful that
alternative fuel sources wil be
approved to continue operations beyond
2020.
Response: EPA recognizes the
facility's importance to the community.
The approved rules do not prevent the
facilty owners from using alternate fuel
or from constrcting a new power
source. Ifthe Boardman facilty is
powered with alternative fuels or if a
new facility is constrcted all applicable
CAA requirements, including New
Source Performance Requirements
(NSPS) and Prevention of Significant
Deterioration (PSD) emission control
requirements, must be met. The
emission netting basis and plant site
emission limits (PSELs) used in
determining whether a modification to
facilty must meet PSD requirements,
wil be reduced to zero when the Foster-
Wheeler boiler at the facility
permanently ceases to burn coaL. OAR
340-223-0030(1)(e).
Comment: Morrow County
commented that they support EPA's
approval of Oregon's Regional Haze SIP
submittal and stated that the 10 year
timeframe in the BART rule provides
adequate time to put reliable
replacement generation in place,
protects this region and the state from
the economic blow that would result
from an earlier closure and is an
appropriate balance of environmental
and economic interests of Oregon and
its citizens. The County further stated
that the SIP accomplishes their wish to
Federal Register/Vol. 76, No. 128/Tuesday, July 5, 2011/Rules and Regulations 38999
have environmental standards in place
that wil preserve the beauty ofthe area
for future generations by reducing
emission of NOx, S02, and mercury,
during the plant's remaining lifetime
and ending all coal-related emissions
from the Boardman facility at least 20
years ahead of schedule.
Response: EPA acknowledges this
comment.
Comment: PGE commented that it
believes that the ODEQ BART rules for
the Boardman facility achieve the
proper balance of environmental
benefits, the cost to customers and the
reliability of the PGE electrical power
system. PGE states it found that it is
possible to secure greater environmental
benefits with a better balance of cost
and risk by transitioning the Boardman
facility away from coal at least 20 years
ahead of schedule. PGE believes that the
ODEQ Boardman BART rule includes
significant and cost-effective emission
control measures to improve visibilty
and ensure that the Boardman plant wil
cease coal-firing by December 31,2020.
Response: EPA believes that the
BART controls required for PGE
Boardman wil result in a significant
reduction in haze that impacts Class I
areas through 2020. Then, ceasing to
burn coal at the facility wil result in
additional and significant reductions in
S02 and NOx emissions from Boardman
at that time, and well as substantial
reductions in carbon dioxide emissions.
Furter, ceasing to burn coal by no later
than December 31,2020, wil result in
cumulative visibilty improvements in
all 14 impacted Class I areas. See
Regional Haze SIP submittal, Appendix
D atD-l71.
Comment: Comments were submitted
claiming an inappropriate double-
counting of "remaining useful life" by
ODEQ to justify lesser pollution control
requirements as BART for the Boardman
facility.
Response: ODEQ did not double-
count the remaining useful life of the
plant in the PGE Boardman BART
analysis. As ODEQ explained, closure of
the plant is not, by itself, considered
BART. Rather. the closure date
establishes the remaining useful life of
the plant which is used to determine the
cost effectiveness of the various control
technologies. See Regional Haze SIP
submittal, Appendix D at D-125. See
also Appendix Y to Part 51-Guidelines
for BART Determinations Under the
Regional Haze Rule (BART Guidelines),
Section D. step 4.k.1. (70 FR 39156 (July
6, 2005)). A decision to cease burning
coal by 2020 shortens the expected
useful life ofthe coal-burning Foster-
Wheeler boiler by 20 years when
compared to its expected useful life of
2040. ODEQ documented its method for
incorporating remaining useful plant
life in determining cost effectiveness of
control technologies. See Regional Haze
SIP submittal, Appendix D at D-125 and
D-131. The BART Guidelines
specifically provide that the remaining
useful lie of a source may affect the
annualized costs of retrofit controls and
explains that "where the remaining
useful life is less than the time period
for amortizing costs, you should use this
shorter time period in your cost
calculations." 70 FR 39169. Thus,
ODEQ appropriately applied the BART
Guidelines when it considered the
remaining useful life of the Foster-
Wheeler boiler when evaluating the cost
effectiveness of the control technologies.
In addition, EPA notes that ODEQ's
conclusion regarding cost effectiveness
for S02 controls, specifically Semi-dr
Flue Gas Desulfurization (SDFGD)
versus Dry Sorbent Injection (DSI)
technologies, varied appropriately
depending on the plant closure date.
See EPA Assessment of ODEQ
Determination of Best Available Retrofit
Technology for the PGE Coal Fired
Power Plant in Boardman, Oregon (EPA
Boardman BART Assessment) January
18,2011.
Comment: One comment stated that a
compilation of BART analyses across
the United States reveals that the
average cost per deciview (dv) proposed
by either a state or a BART source is $14
to $18 milion, with a maximum of $51
milion per dv proposed by South
Dakota at the Big Stone power plant.
The commenter noted that ODEQ has
chosen $10 milion/dv as a cost
criterion, which is somewhat below the
national average.
Response: ODEQ selected a dollars/dv
cost effectiveness theshold of $10
milion/dv based on what it considered
the most relevant cost effectiveness
figures available from similar coal-fired
power plants in other parts of the
country. See Regional Haze SIP
submittal, Appendix D-Table 16 (D-
137) for the estimated dollars/dv of the
various control technologies. EPA notes
that the comment is consistent with
EPA's review of dollars/dv cost
effectiveness data compiled by the
National Park Service (NPS) available
for a variety of coal-fired facilities
located across the country. The NPS
data show that ODEQ's dollar/dv
threshold is below the average cost for
BART NOx and S02 control
technologies selected for other coal-fired
power plants in the country. In EPA's
view. however, the dollars/dv metric is
a diffcult one to apply consistently
across BART sources given the
variabilty in the number of Class I areas
impacted by emissions from a BART
source and the number of days of
impacts at each area. In assessing the
reasonableness of a state's BART
determination. EPA does not consider it
appropriate to focus on a bright-line
theshold such as a dollars/dv cost
effectiveness threshold but rather on the
full range of relevant factors. In
reviewing the BART determination for
the Boardman facilty, EPA has
accordingly taken into account not only
ODEQ's analysis of dollars/dv, but also
the range of visibility impacts associated
with the various control options.
Comment: One comment expressed
concern with the way in which the
incremental cost analysis is used by
ODEQ. It stated that to use incremental
costs properly, they must be compared
to incremental costs for similar
situations.
Response: The Regional Haze SIP
submittal shows that that ODEQ
estimated the incremental cost and
average cost effectiveness of the various
control options considered in its cost
analysis for determining BART. ODEQ
first calculated the average cost
effectiveness of each technology, and
then calculated the incremental cost of
going from the most cost effective
technology to each of the more stringent
technically feasible control
technologies. See Regional Haze SIP
submittal, Appendix D-Table 8 at D-
132 and Cost effectiveness table on D-
168. The approach used by ODEQ to
determine average and incremental cost
effectiveness is consistent with the
procedure outlined in the BART
Guidelines. See 70 FR 39167. Given the
source-specific nature of a BART
determination and the emphasis not
only on the costs of control, but other
factors such as the degree of visibilty
improvement resulting from the use of
controls and the remaining useful lie of
the facility, comparisons of incremental
costs across sources are often not
meaningful in making BART
determinations.
Comment: Multiple comments were
submitted concerning the cost
effectiveness calculations. The
comments expressed concern regarding
the dismissal of controls that are cost-
effective even with the State's $7,300/
ton and $10 milion/dv thresholds
claiming that semi-dr flue gas
desulfurization (SDFGD), selective non-
catalytic reduction (SNCR), and
selective catalytic reduction (SCR) were
eliminated from consideration as BART
for PGE Boardman though
inappropriately inflated costs, inclusion
of costs not allowed by EPA's Cost
Control ManuaL, underestimated control
effectiveness, and arbitrarily and
39000 Federal Register / Vol. 76, No. 128/Tuesday, July 5, 2011 /Rules and Regulations
shortened equipment life due to
excessively long assumed installation
times.
Response: As explained in the SIP
submittal, ODEQ evaluated and
considered the costs, control efficiencies
of the various control technologies, and
expected equipment life in its BART
determination. ODEQ used an
independent contractor (ERG) to
evaluate PGE's cost estimates for the
Boardman facility and concluded that
while PGE's estimates were significantly
higher than ERG's, PGE's estimates
better reflected real world costs, and
were appropriate for the PGE Boardman
BART analysis. More specifically, ERG
concluded that the actual cost of
retrofits is, in general, higher than the
estimates provided by the EPA's Cost
Control ManuaL. ODEQ explained that
difference is due to a dramatic increase
is labor and material costs in recent
years. See Regional Haze SIP submittal,
Attachment 7.2, ODEQ response to
comments, i. 1. a-c , for more detaiL.
In reviewing ODEQ's BART
determination, EPA recognized that the
cost estimates ODEQ relied on included
two capital cost line items that are not
normally included when using the EPA
Cost Control manuaL. The effect of
including these two line items is that
the capital costs are likely "at the high
end" of the capital cost range estimate.
See EPA Boardman BART Assessment
at 2. To assess the impact of ODEQ's
decision to include these items in the
cost estimate, EPA further evaluated the
cost effectiveness value for SDFGD
without including the two capital cost
line items, and concluded that the cost
effectiveness of SDFGD would drop
from $5,535/ton to $4,810/ton. Although
EPA considers the $4,810/ton to better
reflect the true cost of SDFGD, we
conclude that the $725/ton difference
between the two estimates would not
materially affect ODEQ's evaluation.
EPA notes that the incremental visibilty
improvement between SDFGD and DSI-
1 (0.4 Ib/mmBtu) would only be 0.4 dv
at the most impacted Class I area.
Additionally, EPA found that with an
S02 limit of 0.3 Ib/mmBtu in 2018, the
incremental visibility improvement
between the two control technologies
would only be 0.26 dv in the most
impacted Class I area. In addition, while
SDFGD would achieve a cumulative
visibilty improvement of 10.6 dv in all
impacted Class I areas and DSI-l 2
would achieve a cumulative visibilty
20SI-1 is defined as the initial OSI system
performance that would achieve an S02 emission
limit of 0.4 IhsfmmBtu by July 1, 2014.
improvement of 7.0 dv and DSI-2 3
would achieve a cumulative
improvement of 9.3 dv in 2018, when
the facilty ceases to burn coal at the
end of 2020, the cumulative visibilty
improvement would be ~1.46 dv. See.
Regional Haze SIP submittal, Appendix
D at D-137, 168 and 171. When
choosing between the two technolo~ies,
it is reasonable for the state to consider
the sizable capital cost difference
between SDFGD and DSI, and the
relatively small incremental visibility
improvement between the two
technologies in light of the shutdown of
the unit in 2020. In EPA's view, ODEQ's
final selection of BART would not have
changed even if the cost effectiveness
had been adjusted to reflect the EPA
Cost ManuaL.
Regarding the comments concerning
control effectiveness of SCR, SNCR, and
SDFGD technologies, ODEQ determined
the control effectiveness of these control
options by evaluating actual emissions
data from other sources employing
similar types controls, taking into
consideration that BART limit must be
achieved at all times for a retrofit
installation at Boardman. ODEQ's
evaluation determined that the
Boardman facilty could not achieve the
lower emission rate suggested by the
commenter. See Regional Haze SIP
submittal, Appendix D at D-14 through
D-18, and Attachment 7.2, ODEQ
response to comments 11. 1.b.
Comment: A commenter notes that on
September 1,2010. Oregon released a
proposed rulemaking for public
comment that included BART
requirements for PGE Board~an ba~ed
on a variety of closure dates, including
2020. The comment claims that the
September 2010 proposal required
installation of SDFGD and SNCR for a
2020 shutdown but that the
requirements for a 2020 closure date
were relaxed significantly in the plan
EPA proposes to approve. The
commenter does not believe there is
suffcient justification for this relaxation
of BART and states the relaxation
appears arbitrary.
Response: As mentioned above, EPA's
action relates to the BART
determinations contained in the
Regional Haze Plan that was submitted
to EPA on December 20, 2010. EPA
explained the basis for its decision to
approve ODEQ's BART determi.nation in
the notice of proposed rulemaking. 76
FR at 12660-12662. Although ODEQ
may have considered establishing more
stringent BART emission limits at an
30SI-2 is defined as the OSI system performance
that would achieve an S02 emission limit of 0.3 Ibs/
mmBtu by July 1, 2018.
earlier point, this does not provide a
basis for disapproving its final BART
determination.
Comment: A commenter stated that it
is unclear whether the current
regulatory language proposed by ODEQ
would actually result in the "closure" of
the Boardman facilty because each
closure option states that it only applies
to the "Foster-Wheeler boiler" at
Boardman. To ensure no other coal-fired
boiler could be installed at Boardman
the commenter requested ODEQ to
strike the commercial name of the boiler
from OAR 340-223-0020 through OAR
340-223-0090 and replace it with either
"any coal-fired boiler" or "the
Boardman coal-fired power plant."
Response: The State rules are clear in
that they apply to the Foster-vyheeler.
boiler which is the only coal-fired umt
at the Boardman facility. The rules do
not prevent the plant owners from
applying for a permit to construct a new
power plant at the fac~lity ?r to use the
existing equipment with different fu?l.
See Oregon Regional Haze SIP submittal
Attachment 1.1 at 8-9. However any
new facility or change in the operations
would need to be permitted in
compliance with the CAA requirements.
Further, the rules explain that
notwithstanding the definition of
netting basis and the process for
reducing plant site emission limits
(PSEL) in the Oregon rules, the netting
basis and the PSEL are reduced to zero
on the date which the boiler
permanently ceases to burn coaL. See
OAR 340-223-0030(1)(e). Thus. as
ODEQ explained to the Environme~t~l
Quality Commission, "Any new facihtyor repowering of the existing coal-fired
boiler would be permitted as a new
facility without relying on the
reductions from the existing plant and
in compliance with all applicable state
and federal requirements, including
modern air pollution controls and air
quality impact analysis." See Regional
Haze SIP submittal, Attachment 1.1 at 9.
Comment: Multiple commenters
explained that if ODEQ decides th~t the
S02 emission limit, based on DSI, is
BART for PGE Boardman, it should
require PGE to design and install the
DSI system to achieve 90% effciency
and require that PGE opti~ize it~
effectiveness for the duration of its
operation.
Response: ODEQ established S02
BART limits for the Boardman facility
based on an estimated 35% minimal
efficiency of DSI in removing S02 from
the flue gas. A similar comment
regarding DSI effciency was made to
ODEQ during the State public comment
period. In response ODEQ stated:
Federal Register/Vol. 76, No. 128/Tuesday, July 5, 2011/Rules and Regulations 39001
"ODEQ is not aware of a DSI system, such
as proposed for the PGE Boardman Plant, to
have been installed on a similar sized unit.
DSI has been used on smaller units that also
included fabric fiters, which both contribute
to improved efficiency of the DSI system.
ODEQ's proposal relies on the existing ESP
and does not include the installation of a
fabric filter, which would cost over $100
milion. In addition. the ducts between the
air heater and the ESP are much larger at the
Boardman Plant. It is more difficult to
adequately disperse the sorbent reagent in
larger ducts and stil maintain enough
residence time for the sorbent to react with
the S02. (AJ thirty five percent efficiency is
probably a little conservative, but a BART
limit should be achievable at all times."
Regional Haze SIP submittal, Attachment 7.2
response to comment I.6.a.
EPA considers ODEQ's response
regarding the uncertainties associated
with the use of DSI to be reasonable.
Comment: One comment stated that
DSI for PGE Boardman for the shutdown
within five years of EPA approval of the
SIP may well be an appropriate cost
effective technology choice capable of
reducing S02 emissions in a manner
consistent with BART requirements.
Similarly, a commenter states that
ODEQ should require that PGE install
DSI "as expeditiously as practicable"
and contends it could be installed in a
year's time.
Response: As explained above, ODEQ
determined that DSI is a cost effective
control technology for S02. The Oregon
BART rule at OAR 340-223-0030
(l)(b)(A) requires that the Boardman
facility achieve an S02 emission limit of
0.4Ibs/mmBtu by July 1, 2014, about
two years ahead of the five-year
maximum time allowed by the CAA for
the installation of BART. As ODEQ
explains, "The proposed compliance
date (of July 1, 2014) allows PGE three
years to design the DSI system and
conduct the pilot study, which may
involve evaluation of several types of
sorbent materials and injection
locations, along with particulate matter
stack testing." See Regional Haze SIP
submittal, Attachment 7.2, response to
comment I.7. Given the uncertainties
associated with the use of DSI on a plant
such as Boardman, installng DSI in this
timeframe satisfies the requirement of
"as expeditiously as practicable" and is
within the timeframe specified in the
CAA.
ODEQ determined that the Boardman
facility need install any additional
emission controls if the Foster-Wheeler
boiler is shut down within five years of
approval of the SIP. ODEQ did not
consider DSI as a required control
technology for this scenario. See
Regional Haze SIP submittal, Appendix
D at D-142. EPA agrees with ODEQ's
conclusion that it would be
unreasonable to require the installation
of DSI for such a short period of
operation before shutting down.
Comment: One comment stated that
the capital and operating costs of DSI for
Boardman were overstated. Some
comments explained that although
ODEQ has not provided sufficient data
on the costs of DSI, it is possible that
DSI could also meet ODEQ's cost-
effectiveness threshold. even if used for
only a few years as in the case were the
Boardman facilty were to shut down
within five years of EPA final approval
of the SIP.
Response: ODEQ's analysis for
determining the capital and direct
annual costs for DSI are described on
pages D-130-131 of Appendix D ofthe
Regional Haze SIP submittaL. EPA's
Boardman BART Assessment
acknowledged that PGE's capital cost
estimates for various control
technologies are "likely at the high end
of the range for capital cost estimates,"
but as discussed above, even if the cost
estimates are at the high end,
considering the cost differential
between DSI and SDFGD, and given the
visibility improvements associated with
selecting DSI based on an early shut
down, the variation in cost estimates
was not determinative. Therefore, EPA
believes that the methods used by
ODEQ to determine effectiveness and
cost of DSI, and a determination not to
require DSI if the Boardman facility
ceases to burn coal within five years of
EPA's approval. are reasonable and
within the State's discretion. See also
the response to comment above.
Comment: One comment stated that
DSI is a technically feasible control
technology at PGE Boardman. This
comment explained that (1) the size of
the coal.fired unit is inconsequential as
to whether DSI is technically feasible,
and (2) while DSI is not in widespread
use on larger boilers like the Boardman
facility, that is most likely due to
availabilty of sorbents, costs, and S02
control effectiveness when compared to
other S02 control technologies like
semi-dry or wet scrubbers, not technical
feasibilty.
Related comments suggest that it is
improper for ODEQ to discard DSI as
technically infeasible merely because its
installation triggers addition legal
obligations under the Clean Air Act (or
State law). In the commenter's view,
ODEQ cannot conclude that DSI is
technically infeasible because it would
interfere with PGE's compliance with
state mercury reduction goals, or result
in adverse impacts to the particulate
matter air quality standards. The
comment states that as a legal matter
PGE must comply with requirements
associated with Regional Haze, and
those intended to prevent significant
deterioration of air quality and any
requirements to reduce hazardous
pollutants such as mercury. In the
commenter's view, even if DSI were
genuinely technically infeasible, PGE
would not be entitled to the de facto
exemption from BART that it requests
because the ODEQ has an obligation to
identify, and prescribe, a technically
feasible BART limit.
Response: As explained above, ODEQ
determined that DSI is technically
feasible for PGE Boardman. Although
ODEQ was not aware of a similar sized
unit with a DSI system, this control
technology has been used on smaller
units that also included fabric fiters
which contribute to improved effciency
of the DSI system. However, ODEQ's
BART determination does not require
the installation of a new fabric fiter
system, which would cost about an
additional $100 milion, but instead
relies on the use of the existing ESP at
the Boardman facilty. Furthermore,
there is additional question regarding
DSI performance because of the size of
the ducts between the air heater and the
ESP. These ducts are much larger at the
Boardman Plant than the ducts on
smaller power plants where DSI has
been demonstrated. This adds to the
uncertainty in DSI performance because
it is more difficult to adequately
disperse the sorbent reagent in larger
ducts and stil maintain enough
residence time for the sorbent to react
with the S02. Thus, there is some
uncertainty as to how well DSI wil
work on this particular facility. See
Regional Haze SIP submittal, Appendix
D at D-129, D-169 and D-170 (ODEQ's
basis for projected DSI system
effciency).
Although ODEQ concluded that DSI is
technically feasible, it also took into
consideration that DSI at this size and
type of facility may result in
unacceptable levels of PM or mercury
emissions. This could result in potential
additional costs if the levels of these
pollutants were high enough to require
additional controls. Specifically, ODEQ
recognized that a significant increase in
PM2.5 emissions was a possible
outcome of installng DSI, and that if
this occurred, the installation would be
subject to the PSD requirements. The
resulting BACT or air quality impact
analysis would require additional
controls which would increase the cost
of DSI. Regional Haze SIP submittal,
Appendix D at D-142 and D-170. Thus,
rather than avoiding other legal
requirements, ODEQ considered them in
its overall cost effectiveness evaluation
39002 Federal Register / Vol. 76, No. 128/ Tuesday, July 5, 2011/ Rules and Regulations
of the technology. ODEQ did not
exclude the technology because it might
trigger other legal obligation but
considered them in the overall
evaluation of what was the most
reasonable BART for this facility.
Comment: One commenter stated that
Oregon did not appropriately consider
the lower emission limitation of 0.3 lbl
mmBtu (DSI-2) as BART, but instead
only considered it to meet reasonable
further progress by 2018. The
commenter explained that the DSI-2
limitation was not identified as
technologically infeasible or cost
prohibitive for BART, and that ODEQ
has provided no reason why the study
of DSI-2 cannot be conducted "as
expeditiously as practicable" but no
later than five years after EPA approves
the state SIP.
Response: ODEQ determined that due
to uncertainties associated with DSI-1
performance at a large coal fired-facility
the size of Boardman without a
baghouse, the higher, more conservative
limit of 0.40 Ib/mmBtu could be
achieved with a high degree of certainty
in 2014, whereas the lower limit of 0.3
Ib/mmBtu would not be achieved with
DSI-2 until 2018, when future
refinements in the DSI system
performance could be achieved,
possibly in combination with ultra-low
sulfur coal or supplemental fuels, such
as biomass. Regional Haze SIP
submittal, Appendix D at D-169- D-
170; 76 FR 12662. See also response to
comment above.
Comment: One commenter stated that
loopholes in Oregon's Administrative
Rules (OAR 340-223-0010 though
340-223-0080) included provisions that
would inappropriately remove the
requirement for DSI. In the commenter's
view the condition under which DSI
would not be required, including a post-
BART determination of technical
infeasibility or the triggering of
additional CAA obligations should not
be allowed to preclude the installation
of BART, which is by definition
technically feasible. The commenter
also asks that in approving Oregon's SIP
submittal, EPA interpret the conditions
contained in OAR 340-223-0030(3) as
requiring EPA approval or concurrence
with ODEQ's determinations prior to
implementation of relaxed standards.
Additionally, a cornenter questions
whether the provision would require or
allow any public comment on ODEQ's
determination that DSI-1 or DSI-2 is
technologically infeasible, would inhibit
compliance with Oregon's mercury
rules, or would trigger PSD
applicabilty.
Response: As explained above, ODEQ
determined that DSI is a technically
feasible SOi control technology for PGE
Boardman and that it can achieve 0.4 lbl
mmBtu at a removal efficiency of about
35%. Regional Haze SIP submittal,
Appendix D at D-127-128. While ODEQ
determined that DSI was technically
feasible, it also acknowledged that the
technology has only been demonstrated
at smaller boilers than the one at the
Boardman facility.4 Thus, the State
determined it was appropriate to require
additional studies. The rules being
approved today provide that technical
studies to evaluate the SOi limits, and
the potential side effects of those limits,
must be conducted in accordance with
a plan that is preapproved by ODEQ.
These studies wil fully evaluate and
review the effectiveness and use of DSI
technology at this facilty. See OAR
340-223-0030(2), see also Regional
Haze SIP submittal, Attachment 7.2 at
17. The rules first establish a limit of
0.40 Ib/mmBtu by July 1, 2014 and 0.30
Ib/mmBtu by July 1, 2018. Then the
rules describe the specific conditions
under which the SOi limit of 0.40 lbl
mmBtu or 0.30 Ib/mmBtu may be
exceeded. OAR 340-223-0030(3).
Specifically, the rules provide that if
upon completion of the specified pilot
studies, the results shows that DSI is not
capable of achieving the BART limit of
0.4 Ib/mmBtu (between July1, 2014 and
June 30, 2018) or 0.30 Ib/mmBtu
(between July 1, 2018 and December 31,2020), or would prevent compliance
with specified mercury limits or cause
a significant air quality impact for PM10
or PM2.5, the SOi emission limit may be
modified up to 0.55lb/mmBtu through a
modification to the facility's Title V
permit. The rule being approved today
is clear as to what conditions must be
satisfied in order for the source to
exceed the 0.4 Ib/mmBtu or 0.3 lbl
mmBtu limits. The rule provides, that if
applicable, the study may propose a
limit that exceeds the 0.4 Ib/mmBtu or
0.3 Ib/mmBtu limits based on reduction
ofthe sulfur dioxide emission limits to
the maximum extent possible through
the use of DSI or other SOi control
system of equal or lower cost, including
but not limited to the use of low sulfur
4 EPA also recognizes some uncertainty regarding
the effectiveness of this control at the Boardman
facility. For example, EPA's "Air Pollution Control
Technology Fact Sheet" states that "S02 removal
effciencies (of DSI) are significantly lower that wet
systems, between 50% and 60% for calcium-based
sorbents. Sodium- based dry sorbent injection into
the duct can achieve up to 80% control
efficiencies." EPA--52/F-03-u34 at 5. EPA realizes
that the proposed control limit of 0.4 Ib/mmBtu is
below the range cited in this fact sheet. but given
the larger size of the Boardman boiler and the
State's desire not to overload the existing ESP PM
control system, EPA believes that the proposed
emission limit is reasonable.
coaL, provided that the proposed
emission limit may not exceed 0.551bl
mmBtu heat input as a 30-day rollng
average. The conditions and parameters
under which the 0.3lb/mmBtu or 0.41bl
mmBtu emission limits may be
exceeded, are spelled out in the rule and
were considered by EPA in its review of
the proposed rule. Those conditions and
parameters. including the alternate
upper limit of 0.55 Ib/mmBtu, are being
approved today and additional approval
by EPA is not necessary.
Regarding the commenter's concern
relating to the opportunity for public
input into this potential change in
emission limits, the rule allows for the
PGE Boardman's Title V operating
permit to be modified to include a
federally enforceable permit limit based
on the performance of DSI demonstrated
by the pilot study, as performed
according to OAR 340-223-0030(2)(c).
Thus, before the 0.4 Ib/mmBbtu or 0.3
Ib/mmBtu emission limits may be
exceeded, the source would need to
comply with the conditions in OAR
340-223-0030(3) including submitting a
complete application for a Title V
permit modification. The permit
modification would be considered a
significant permit modification under
OAR 340-218-0180 and a category 3
permit under Oregon Title V rules, See
OAR 340-218-0210(1). A category 3
permit is subject to the procedures in
OAR 340-209-0030(3)(c) which include
general public notice, opportunity for
public comment and EPA review. In
addition, the results of the pilot study,
the technical basis and the
recommended alternative limit would
be provided to the public for review and
comment during the Title V
modification process.
Comment: The commenter also asks
EPA to re-evaluate the environmental
benefits from Oregon's SIP submittal
based on the emission limit and
reductions that EPA approval ofthe SIP
would actually require: 0.55 Ib/mmBtu,
which the Oregon SIP submittal does
require to be met, regardless of the
results of the pilot studies.
Response: The visibility
improvements to Class I areas impacted
by PGE Boardman were based on the
SOi and NOx BART emission limits to
be achieved by 2014, and on furter
reasonable progress emission limits for
SOi achieved by 2018, The SOi BART
limit of 0.40 Ib/mmBtu is the applicable
limit as of July 1, 2014 unless specific
conditions are satisfied and ODEQ
approves an alternate limit. See OAR
340-223-003 O( 2)( c)(E) . Additionally,
ODEQ explains that an alternate limit
must not exceed 0.55 Ib/mmBtu in order
to achieve at least a 0.5 dv improvement
Federal Register / Vol. 76, No. 128/ Tuesday, July 5, 2011 /Rules and Regulations 39003
in visibility in Mt. Hood Wilderness
Area. See Id. and the Regional Haze sip
submittal, Appendix D "Control
Effectiveness" table at 0-168 and text
on 0-170. Thus, the State considered
the visibility improvements associated
with a 0.55 Ib/mmBtu and the
additional analysis requested by the
commenter is not necessary.
Comment: One commenter stated that
visibility improvements and potential
improvements in other non-air quality-
related impacts in the region would
occur as a result of the installation of
SCR at the Boardman facility and
should be taken into consideration in
determining BART the facility. This
commenter furter explained that NOx
emissions can contribute to excess
nitrogen in ecosystems, which can alter
the chemical balance ofthe soils and
waterbodies with serious consequences
for plant and animal life. For these
reasons, the commenter concluded,
ODEQ must require installation of SCR
and new low NOx burners with overfire
air as BART for the Boardman facility.
Response: The estimated visibility
improvements that could be achieved
over current conditions with each
combination of technically feasible
controls were taken into consideration
in determining BART for Boardman. See
76 FR 12611. More specifically, ODEQ
determined that LNB and MOF A are
BART for NOx because they are cost
effective and provided a 1.45 dv
improvement at Mt. Hood Wilderness
Area (the most impacted Class i area)
and a cumulative visibilty
improvement of8.75 dv in all 14
impacted Class i areas. ODEQ
determined that DSI is BART for S02
because it is cost effective and provides
a significant (0.96 dv) improvement at
Mt. Hood Wilderness Area and a 7.4 dv
improvement in all impacted Class i
areas by July 1, 2014. For further
comparison of visibilty improvement
associated with the various control
technologies and timeframes see the
Regional Haze SiP submittal, Appendix
D, at D-169-172. The contribution of
the facility's NOx emissions to excess
nitrogen in ecosystems. were not taken
into account in the PGE Boardman
BART analysis. However, it would be
extremely diffcult to quantify. or even
to qualitatively assess, the impacts of
added nitrogen from one source on an
ecosystem. The impacts of deposition
related effects such as nutrient
enrichment and eutrophication var
considerably across ecosystems. EPA
does not consider it unreasonable for
ODEQ to have not taken these impacts
into account in making its BART
determination.
Comment: One commenter urged the
Department to consider and maintain
the 2018 and five year closure options
for the Boardman facility. The
commenter requested that ODEQ also
look at additional cost-benefit and
technical analysis for the 2018 option.
Response: ODEQ's final Regional
Haze SiP submittal includes rules which
allow PGE Boardman to either cease
burning coal within five years of EPA's
approval of the rules or to cease burning
coal by December 31, 2020. PGE must
notify ODEQ in writing no later than
July 1, 2014 if it chooses to cease coalburning within 5 years of this action. If
it chooses that option, one set of
emission limits apply; however, if it
chooses to continue operating until
December 31, 2020, more stringent
emission limits apply. A 2018 shutdown
option was considered by ODEQ but
removed from the final SIP submittal
because PGE indicated that it intended
to operate the Boardman facility until
the end of 2020, and because ODEQ has
no authority to require a facility to shut
down by a certain date under the BART
Rule absent a commitment by the source
to do so.
Comment: A commenter stated that
the regulation should specify that if PGE
continues to operate the Boardman
facility as a coal-fired facility after its
selected closure deadline the operating
permit for the facility shall be deemed
void. The commenter also requested
that to avoid any uncertainty regarding
the availability of relief due to non.
compliance, the regulation should
explicitly state that the state, EPA and
citizens may apply for both injunctive
and civil penalty relief.
Response: A violation of a federally
enforceable state rule or permit is
subject to liability as provided in
section 113 of the CAA, 42 USC 7413,
and would be addressed as appropriate
under applicable state or federal law.
Additional language to restate the
existing authority is not necessary.
Comment: One commenter requested
that EPA correct or remove certain
factual statements that were included in
the notice of proposed rulemaking.
Specifically, the commenter requested
changes to state that PGE Boardman is
a 617 megawatt (MW) plant instead of
584 MW plant and that it commenced
construction on "December 6,1979"
instead of in "1975".
Response: EPA agrees that the PGE
Boardman coal fired power plant is
capable of producing about 617 MW of
electricity, not 584 MW. According to
ODEQ's BART report, construction on
the PGE Boardman plant began in 1975.
However, the first air contaminant
discharge permit from ODEQ to PGE for
Boardman was dated December 6,1979.
Comment: One commenter stated that
for the five-year closure option at
Boardman, ODEQ should require
additional interim controls that would
reduce emissions in the remaining five
remaining years of operation.
Response: OAR 340-223-0080
provides alternate requirements in the
event the owner elects to permanently
cease burning coal within five years of
EPA's SIP approvaL. Under this
alternative, the NOx emission limit of
0.23 Ib/mmBtu applies beginning July 1,
2011, unless the source satisfies the
requirements in OAR 430-223-
0080(2)(a) and it is demonstrated by
December 31, 2011, that the emission
limit of 0.23 Ib/mmBtu cannot be
achieved with combustion controls, in
which case the ODEQ may grant an
extension to July 1, 2013. OAR 340-
223-o80(2)(a).
Comment: One commenter requested
that the NOx, S02 and PM emission
limits for PGE Boardman include
emission limits during starup and
shutdown.
Response: The BART rules include do
starup and shutdown emission limits
for the Boardman facilty. See OAR 340-
223-0030(1)(d). These limits, which are
three-hour rolling averages, are: Sulfur
dioxide, 1.20 Ib/mmBtu, Nitrogen oxide,
0.70 Ib/mmBtu, and pariculate matter
emissions must be minimized to the
extent practicable pursuant to approved
startup and shutdown procedures in
accordance with OAR 340-214-0310.
Comment: As stated above, NPCA
incorporated into their comments a
number of comment letters that had
previously been submitted to ODEQ.
Many of the comments contained in
these letters relate to emission limits or
comments about technologies associated
with the "no closure" option provided
in prior versions of OAR 340-223-0050,
0060, and 0070, and ODEQ's BART
determination based on PGE operating
the coal-fired boiler at the Boardman
facility until 2040.
Response: The Oregon Regional Haze
Plan submitted to EPA included
revisions to the State's regional haze
rules at OAR 340-223-0010 though
340-223-0080. In this action, EPA is
taking final action to approve a revision
to the Oregon s~p which incorporates
OAR 340-223-0010 through 340-223-
0080 and specifically includes OAR
340-223-0030. As provided in OAR
340-223-0050, and as explained in the
notice of proposed rulemaking, upon
EPA's final approval of OAR 340-223-
0030, OAR 340-223-0060 and 340-223-
0070 are repealed as a matter of law. 76
FR 12662-12663. Thus, compliance
39004 Federal Register / Vol. 76, No. 128/Tuesday, July 5, 2011 /Rules and Regulations
with the "no closure option" or
operating until 2040 is no longer an
alternative. Therefore, the BART
determination associated with that
option is no longer relevant and
responses to comments regarding it are
unnecessary.
III. Final Action
EPA is approving the BART measures
in the Oregon Regional Haze plan as
meeting the requirements of section
110(a)(2)(D)(i)(II of the Clean Air Act
with respect to the 1997 8-hour ozone
and 1997 PM2.5 NAAQS. In addition,
EPA is approving portions ofthe Oregon
Regional Haze Plan, submitted on
December 20, 2010. as meeting the
requirements set forth in section 169A
of the Act and in 40 CFR 51.308(e)
regarding BART. EPA is also approving
the Oregon submittal as meeting the
requirements of 40 CFR 51.308(d)(2) and
(4)(v) regarding the calculation of
baseline and natural conditions for the
Mt. Hood Wilderness Area, Mt. Jefferson
Wilderness Area, Mt. Washington
Wilderness Area, Kalmiopsis
Wilderness Area, Mountain Lakes
Wilderness Area, Gearhart Mountain
Wilderness Area, Crater Lake National
Park, Diamond Peak Wilderness Area,
Three Sisters Wilderness Area,
Strawberry Mountain Wilderness Area,
Eagle Cap Wilderness Area, and Hells
Canyon Wilderness Area, and the
statewide inventory of emissions of
pollutants that are reasonably
anticipated to cause or contribute to
visibilty impairment in any mandatory
Class I Federal Area.
IV. Oregon Notice Provision
Oregon Revised Statute 468.126,
which remains unchanged since EPA
last approved Oregon's SIP, prohibits
ODEQ from imposing a penalty for
violation of an air, water or solid waste
permit unless the source has been
provided five days' advanced written
notice ofthe violation and has not come
into compliance or submitted a
compliance schedule within that five-
day period. By its terms, the statute does
not apply to Oregon's Title V program
or to any program if application of the
notice provision would disqualify the
program from Federal delegation.
Oregon has previously confirmed that,
because application of the notice
provision would preclude EPA approval
ofthe Oregon SIP. no advance notice is
required for violation of SIP
requirements.
V. Scope of EPA Approval
Oregon has not demonstrated
authority to implement and enforce the
Oregon Administrative rules within
"Indian Countr" as defined in 18
U.S.C. 1151. "Indian countr" is
defined under 18 U.S.C. 1151 as: (1) All
land within the limits of any Indian
reservation under the jurisdiction of the
United States Government,
notwithstanding the issuance of any
patent, and including rights-of-way
running through the reservation, (2) all
dependent Indian communities within
the borders of the United States,
whether within the original or
subsequently acquired territory thereof,
and whether within or without the
limits of a State, and (3) all Indian
allotments, the Indian titles to which
have not been extinguished, including
rights-of-way running though the same.
Under this definition, EPA treats as
reservations trust lands validly set aside
for the use of a Tribe even if the trust
lands have not been formally designated
as a reservation. Therefore, this SIP
approval does not extend to "Indian
Country" in Oregon. See CAA sections
110(a)(2)(A) (SIP shall include
enforceable emission limits),
110(a)(2)(E)(i) (State must have adequate
authority under State law to carry out
SIP), and 172(c)(6) (nonattainment SIPs
shall include enforceable emission
limits).
VI. Statutory and Executive Orders
Review
Under Executive Order 12866 (5S FR
51735, October 4,1993), this action is
not a "signifcant regulatory action" and
therefore is not subject to review by the
Offce of Management and Budget. For
this reason, this action is also not
subject to Executive Order 13211,
"Actions Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use" (66 FR 28355, May
22, 2001). This action merely approves
state law as meeting Federal
requirements and imposes no additional
requirements beyond those imposed by
state law. Accordingly, the
Administrator certifies that this rule
wil not have a signifcant economic
impact on a substantial number of small
entities under the Regulatory Flexibility
Act (5 U.S.c. 601 et seq.). Because this
rule approves pre-existing requirements
under state law and does not impose
any additional enforceable duty beyond
that required by state law, it does not
contain any unfunded mandate or
significantly or uniquely affect small
governments, as described in the
Unfunded Mandates Reform Act of 1995
(Pub. L. 104-4).In addition, this rule does not have
tribal implications as specified by
Executive Order 13175 (65 FR 67249,
November 9, 2000), because the rule
neither imposes substantial direct
compliance costs on tribal governments,
nor preempts tribal law. Therefore, the
requirements of section 5(b) and 5(c) of
the Executive Order do not apply to this
rule. Consistent with EPA policy, EPA
nonetheless provided a consultation
opportunity to Tribes in Idaho, Oregon
and Washington in letters dated January
14,2011. EPA received one request for
consultation, and we have followed-up
with that Tribe. This action also does
not have Federalism implications
because it does not have substantial
direct effects on the States, on the
relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132 (64 FR 43255,
August 10,1999). This action merely
approves a state rule implementing a
Federal standard, and does not alter the
relationship or the distribution of power
and responsibilties established in the
CAA. This rule also is not subject to
Executive Order 13045 "Protection of
Children from Environmental Health
Risks and Safety Risks" (62 FR 19885,
April 23, 1997), because it approves a
state rule implementing a Federal
standard.
In reviewing SIP submissions. EPA's
role is to approve state choices,
provided that they meet the criteria of
the CAA. In this context, in the absence
of a prior existing requirement for the
State to use voluntary consensus
standards (VCS), EPA has no authority
to disapprove a SIP submission for
failure to use VCS. It would thus be
inconsistent with applicable law for
EPA, when it reviews a SIP submission,
to use VCS in place of a SIP submission
that otherwise satisfies the provisions of
the CAA. Thus, the requirements of
section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (15 U.S.c. 272 note) do not
apply. This rule does not impose an
information collection burden under the
provisions of the Paperwork Reduction
Act of 1995 (44 U.S.C. 3501 et seq.).
The Congressional Review Act,
5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy ofthe rule, to each House of the
Congress and to the Comptroller General
ofthe United States. EPA wil submit a
report containing this rule and other
required information to the U.S. Senate,
the U.S. House of Representatives, and
the Comptroller General ofthe United
States prior to publication of the rule in
the Federal Register. A major rule
Federal Register / Vol. 76, No. 128/ Tuesday, July 5, 2011 / Rules and Regulations 39005
cannot take effect until 60 days after it
is published in the Federal Register.
This action is not a "major rule" as
defined by 5 U.S.C. 804(2).
Under section 307(b)(1) of the CAA,
petitions for judicial review of this
action must be fied in the United States
Court of Appeals for the appropriate
circuit by September 6, 2011. Filng a
petition for reconsideration by the
Administrator of this final rule does not
affect the finality of this rule for the
purposes of judicial review nor does it
extend the time within which a petition
for judicial review may be fied, and
shall not postpone the effectiveness of
such rule or action. This action may not
be challenged later in proceedings to
enforce its requirements. (See section
307(b)(2).)
List of Subjects in 40 CFR Part 52
Environmental protection, Air
pollution control, Intergovernmental
relations, Incorporation by reference,
Nitrogen dioxide, Particulate matter,
Reporting and recordkeeping
requirements, Sulfur oxides, Visibility,
and Volatile organic compounds.
Dated: June 17, 2011.
Dennis J. Mclerran,
Regional Administrator, Region 10.
Part 52, chapter I, title 40 ofthe Code
of Federal Regulations is amended as
follows:
PART 52-(AMENDEDJ
. 1. The authority citation for Part 52
continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart MM-Qregon
.2. Section 52.1970 is amended by
adding and reserving paragraph (c)(150),
and adding paragraph (c)(151) to read as
follows:
§52.1970 Identification of plan.
*****
(c) * * *
(150) (Reserved)
(151) On December 20, 2010, the
Oregon Department of Environmental
Quality submitted a SIP revision to meet
the regional haze requirements of Clean
Air Act section 169A and the interstate
transport requirements of Clean Air Act
section 110(a)(2)(D)(i)(II as it applies to
visibilty for the 1997 8-hour ozone
NAAQS and 1997 PM2.5 NAAQS.
(i) Incorporation by reference.
(A) December 10, 2010. letter from
ODEQ to the Oregon Secretary of State
requesting filing of permanent rule
amendments to OAR 340-223.
(B) December 10, 2010, filed copy ofState "Certificate and Order for Filng"
verifying the effective date of December
10, 2010, for OAR 340-223-0010, OAR
340-223-0020, OAR 340-223-0030,
OAR 340-223-0040, OAR 340-223-
0050 and OAR 340-223-0080.
(C) The following revised sections of
the Oregon Administrative Rules,
Chapter 340:
(1) 340-223-0010 Purpose of Rules.
effective December 10, 2010.
(2) 340-223-0020 Definitions,
effective December 10, 2010.
(3) 340-223-0030 BART andAdditional Regional Haze Requirements
for the Foster-Wheeler Boiler at the
Boardman Coal.Fired Power Plant
(Federal Acid Rain Program Facility
ORISPL Code 6106), effective December
10,2010.
(4) 340-223-0040 Federally
Enforceable Permit Limits, effective
December 10. 2010.
(5) 340-223-0050 AlternativeRegional Haze Requirements for the
Foster-Wheeler Boiler at the Boardman
Coal-Fired Power Plant (Federal Acid
Rain Program Facilty ORISPL Code
6106), effective December 10, 2010.
(6) 340-223-0080 Alternative
Requirements for the Foster-Wheeler
Boiler at the Boardman Coal-Fired
Power Plant (Federal Acid Rain Program
Facility ORISPL code 6106) Based Upon
Permanently Ceasing the Burning of
Coal Within Five Years of EPA
Approval of the Revision to the Oregon
Clean Air Act State Implementation
Plan Incorporating OAR Chapter 340,
Division 223, effective December 10,
2010.
(ii) Additional materiaL.
(A) The portion of the SIP revisionrelating to statewide inventory of
emissions of pollutants that are
reasonably anticipated to cause or
contribute to visibility impairment in
any mandatory Class I Federal Area and
the calculation of baseline and natural
visibility conditions in Oregon Class I
areas. and determination of current and
2018 visibility conditions in Oregon
Class I areas.
(B) (Reserved)
.3. Section 52.1973 is amended by
adding paragraph (g) to read as follows:
§ 52.1973 Approval of plans.
*****
(g) Visibility protection. (1) EPAapproves portions of a Regional Haze
SIP revision submitted by the Oregon
Department of Environmental Quality
on December 20, 2010, and adopted by
the Oregon Department of
Environmental Quality Commission on
December 9,2010, as meeting the
requirements of Clean Air Act section
169A and 40 CFR 51.308(e) regarding
Best Available Retrofit Technology. The
SIP revision also meets the requirements
of 40 CFR 51.308(d)(2) and (d)(4)(v)
regarding the calculation of baseline and
natural conditions for the Mt. Hood
Wilderness Area, Mt. Jefferson
Wilderness Area, Mt Washington
Wilderness Area, Kalmiopsis
Wilderness Area, Mountain Lakes
Wilderness Area, Gearhar Mountain
Wilderness Area, Crater Lake National
Park, Diamond Peak Wilderness Area.
Three Sisters Wilderness Area,
Strawberr Mountain Wilderness Area,
Eagle Cap Wilderness Area, and Hells
Canyon Wilderness Area, and the
statewide inventory of emissions of
pollutants that are reasonably
anticipated to cause or contribute to
visibilty impairment in any mandatory
Class I Federal Area. The SIP revision
also meets the requirements of Clean Air
Act section 110(a)(2)(D)(i)(II as it
applies to visibilty for the 1997 8-hour
ozone NAAQS and 1997 PM2.5 NAAQS.
(2) (Reserved)
.4. Section 52.1989 is amended by
adding paragraph (b) to read as follows:
§ 52.1989 Interstate Transport for the 1997
8-hour ozone NAAQS and 1997 PM2.5
NAAQS.
*****
(b) On December 20, 2010, the OregonDepartment of Environmental Quality
submitted a Regional Haze SIP revision,
adopted by the Oregon Environmental
Quality Commission on December 9,
2010. EPA approves the portion of this
submittal relating to section
110(a)(2)(D)(i)(II as it applies to
visibilty for the 1997 8-hour ozone
NAAQS and 1997 PM2.5 NAAQS. The
SIP revision also meets the requirements
of Clean Air Act section 169A and
40 CFR 51.308(e) regarding Best
Available Retrofit Technology and the
requirements of 40 CFR 51.308(d)(2) and
(d)(4)(v) regarding the calculation of
baseline and natural conditions for the
Mt. Hood Wilderness Area, Mt. Jefferson
Wilderness Area, Mt Washington
Wilderness Area, Kalmiopsis
Wilderness Area, Mountain Lakes
Wilderness Area, Gearhar Mountain
Wilderness Area. Crater Lake National
Park, Diamond Peak Wilderness Area,
Three Sisters Wilderness Area,
Strawberry Mountain Wilderness Area,
Eagle Cap Wilderness Area, and Hells
Canyon Wilderness Area, and the
statewide inventory of emissions of
pollutants that are reasonably
anticipated to cause or contribute to
visibility impairment in any mandatory
Class I Federal Area.
(FR Doc. 2011-16635 Filed 7-1-11: 8:45 aml
BILLING CODE 656D-SD-P
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-11-18
IDAHO POWER COMPANY
ATTACHMENT NO.5
Boardman: 2012 Test Year
RATE BASE
Electric Plant in Service
Intangible Plant $
Production Plant
Transmission Plant
Distribution Plant
General Plant
Total Electric Plant in Service $
Less: Accumulated Depreciation $664,138
Less: Amortization of Other Plant
Net Electric Plant in Service $(664,138)
Less: Customer Adv for Construction
Less: Accumulated Deferred Income Taxes $(468,881)
Add: Plant Held for Future Use
Add: Working Capital
Add: Conservation - Other Deferred Prog
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE $(195,257)
NET INCOME
Operating Revenues
Sales Revenues
Other Operating Revenues
Total Operating Revennues $
Operating Expenses
Operation and Maintenance Expenses
Depreciation Expenses 1,328,276
Amortization of Limited Term Plant
Taxes Other Than Income
Regulatory Debits/Credits
Provision for Deferred Income Taxes $(468,881)
Investment Tax Credit Adjustment
Current Income Taxes
Total Operating Expenses $859,394
Operating Income $(859,394)
Add: IERCO Operating Income
Consolidated Operating Income $(859,394)
Rate of Return as filed 440%
Proposed Rate of Return 8.18%
Earnings Deficiency $843,422
Net-to-Gross Tax Multiplier 1.642
Revenue Deficiency $1,384,899
Firm Jurisdictional Revenue 834,980,775
REVENUE REQUIREMENT $836,365,674
Percentage Increase Required 0.17%