20180911Teply Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
AUTHORIZATION TO CHANGE
DERECIATION RATES APPLICABLE TO
ELECTRIC PROPERTY
ROCI(Y MOUNTAIN POWER
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CASE NO. PAC-E-18-08
DIRECT TESTIMONY
OF CHAD A. TEPLY
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CASE NO. PAC.E.18.O8
SEPTEMBER 11,2018
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Please state your name, business address, and present position.
My name is Chad A. Teply. My business address is 1407 West North Temple, Suite 310,
Salt Lake City, Utah. My position is Senior Vice President of Strategy and
Development for Rocky Mountain Power (the "Comp&fly"), a division of PacifiCorp.
QUALIFICATIONS
Briefly describe your education and professional experience.
I have a Bachelor of Science Degree in Mechanical Engineering from South Dakota
State University. I joined MidAmerican Energy Company (a Berkshire Hathaway
Energy affiliate company) in November 1999, and held positions of increasing
responsibility within the generation organization. In April 2008, I moved to Northern
Natural Gas Company (a Berkshire Hathaway Energy affiliate company) as Senior
Director of Engineering Ijoined PacifiCorp in February 2009.In my current role as
Senior Mce President of Strategy and Development, my responsibilities encompass
strategic planning, regulatory support, stakeholder engagement, development and
execution of major generation resource additions, major environmental compliance
projects, and major transmission projects.
Please explain the responsibilities of the resource development staff within your
organization.
My resource development staff is responsible for developing generation resource
options that the Company can potentially implement, if determined to be least cost on
a risk-adjusted basis. Resource development staff is also responsible for developing
and providing performance and cost information related to supply side resource options
used in the Company's integrated resource planning process, and maintaining data on
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existing resource capacities, performance, and costs. Resource development staff also
maintains cost and performance information on current and emerging environmental
regulations that may affect the operation of the Company's thermal generating assets.
PURPOSE OF TESTIMONY
What is the purpose of your testimony?
My testimony:
. Describes the process used by the Company to develop estimated economic lives
for the thermal generation resources that are incorporated into the Company's new
depreciation study submitted with Mr. John J. Spanos's testimony as Exhibit No. 2
(the "Depreciation Study") in this filing.
. Provides an overview of the recommended changes to the depreciable lives of the
Company's thermal generation resources based on the Company's assessment of
major factors and changes since the 2013 depreciation study.
. Presents the Company's recommendations on decommissioning costs, which were
developed from updated studies and applied on a plant-by-plant basis.
DEVELOPMENT OF DEPRECIABLE PLANT LIFE
Why is it necessary to estimate the economic life of a generation asset to develop
depreciation rates?
One component of the Company's cost of service is the recovery of capital investment.
This recovery is accomplished through depreciation expense over the life of each
resource. Because depreciation rates spread a certain amount of cost over a certain
period of time, it is necessary to have a reasonable estimate of the economic life of a
resource at the time it is placed into service to properly calculate its depreciation
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I I expense. The estimated plant economic life of a generation asset is the period of time
that begins when the asset is placed in service and starts generating electricity and ends
when the asset is removed from service. In other words, it is the period of time during
which customers benefit from the asset.
Is a plant's estimated economic life permanently set when the plant is placed into
service?
No. For depreciation purposes, all generation assets economic lives are estimates that
may be adjusted over time as circumstances warrant. The Company reevaluates its
economic life estimates each time it perfiorms a depreciation study. In this case, the
Company provided estimated generation plant depreciable lives information to Mr.
Spanos for his use in preparing the Depreciation Study.
Are you also providing the Company's estimated thermal generation plant
economic lives information for this docket?
Yes. ExhibitNo. 5 accompanying my testimony contains a complete list of PacifiCorp's
thermal generation plants and their recommended depreciable lives.
DEPRECIABLE LIVES FOR THERMAL GENERATION RESOURCES
Please describe the process the Company used to assess the depreciable lives of its
thermal generation resources.
The Company began with the estimated retirement years from the 2013 depreciation
study. The Company then considered capital expenditures, impacts to ongoing
operating and maintenance expenses, and the potential for accelerated timelines for
resource planning decisions. These factors were considered in the following context:
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1 (1) major equipment condition; (2) fuel cost and availability; (3) environmental
compliance obligations; and (4) policy and market drivers.
Based on the unique circumstances that affect individual units at a given plant,
the Company also modified its current practice of using a single retirement year for a
plant, and instead proposes changes in this study to reflect the depreciable lives of the
individual coal-fired generation units at each plant.
Please explain how major equipment condition can affect the depreciable life of a
thermal generation resource.
Major equipment condition is influenced by the planned outage schedule. Thermal
resources, including the coal-fired, gas-fired, and geothermal resources involving the
production and transport of steam, normally undergo overhauls on four-year cycles,
eight-year cycles or l2-year cycles. The Company establishes outage schedules for
coal-fired resources based on its industry operating experience. It establishes overhaul
schedules for gas-fired combustion turbine-based resouices based on the number of
operating hours and starts of the units and the recommendations of the original
equipment manufacturer. Major equipment or component replacements, such as
replacing cooling towers, condenser re-tubing, replacing turbine components, re-
winding generators, or replacing steam generator components, may be required at these
overhaul milestones. These periodic milestone replacements are important to the
ongoing operation of the resource, and if capital investment is required, the resource
may no longer be economic to operate, depending on the level of investment and
expected remaining life.
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Please explain how fuel cost and availability can affect the depreciable life of a
thermal generation resource.
Fuel cost, availability and, to an extent, fuel quality can influence the economic life of
a thermal generation resource. Significant changes in the cost, availability, or quality
of the resource's fuel supply can drive major capital expenditures or result in increased
run-rate costs that could make the resource uneconomic to operate. Issues at captive
mines that serve the Company's resources are likely to have more direct impacts,
depending upon the availability of alternative competitive market suppliers. Switching
to a different fuel source, and procuring and delivery of this alternate fuel, could require
major capital expenditures, or result in increased run-rate fuel costs, which can also
drive economic life decisions for individual resources.
Please explain how environmental regulations can affect the depreciable life of a
thermal generation asset.
Existing, evolving, and emerging air emissions standards, water intake and efiluent
discharge standards, and solid waste regulations may have impacts on the economics
of operating an asset. New regulations or changes to existing air, water or solid waste
regulations influence the timing of capital expenditures for compliance and the
subsequent operating and maintenance costs. Capital expenditures include air pollution
controls, water intake infrastructure modifications, discharge constraints, cooling
system changes, and new or upgraded coal combustion waste infrastructure to transport
and store bottom ash, fly ash, and scrubber waste. Capital expenditures, once made,
must be recovered over the remaining life of the asset. If a major capital investment is
required to meet a new environmental standard and the investment is not feasible or
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economic over the remaining life of the asset, this could result in the early retirement
ofthe resource.
Have any significant new environmental regulations or compliance obligations
been implemented since the Company's last depreciation study that could affect
thermal generation resource depreciable lives?
Yes. Several environmental regulations and compliance obligations have been
implemented since the Company's 2013 depreciation study. First, the United States
Environmental Protection Agency ("EPA") and the states of Arizona, Colorado, Utah,
and Wyoming have continued to implement their Regional Haze state and federal
implementation plans. Since 2013, the Company has taken steps to install emissions
control equipment, negotiate alternative compliance outcomes for certain unitsl, and is
currently supporting ongoing requests for reconsideration and, in some instances
litigation, of other implementation plan requirements2. These efforts and outcomes
affect several of the Company's wholly-owned or partially-owned generation
resources. The Company generally assesses its compliance obligations and alternatives
as part of its regular integrated resource plan ("IRP") filings, the most recent of which
are the 2017 IRP and the 2017 IRP Update, which are available on the Company's
website. Detailed discussion of the Company's completed compliance projects and
A.
I In 2014, installation of new lorv_NOx bumers, a scrubber upgrade, and nerv baghouse at Hunter Unit I . In
2015, installation of selective catalytic reduction C'SCR") systems at Jim Bridger Unit 3 and Hayden Unit l. In
2016, installation of SCR systems at Jim Bridger Unit 4 and Hayden Unit 2. Also in 2016, an SCR alternative
for Dave Johnston Unit 3 rvas approved by EPA. In 2017, an SCR system was installed at Craig Unit 2 and an
SCR altemative for Cholla Unit 4 was approved by EPA. In 2018, an SCR alternative for Craig Unit 1 was
approved by EPA. The Company is in discussions with the Wyoming Department of Envirorunental Quality and
the EPA regarding an SCR alternative for Jim Bridger Units I arfr2.
2 The EPA is currently in the process of reconsideration of Utah Regional Haze compliance requirements and
litigation of EPAs Regional Haze federal implementation plan requirements for Hunter Units 1 and 2 and
Huntinglon Units I and 2. Litigation of EPAs Regional Haze federal implementation plan requirements for
Wyodak and Naughton Units I and 2 is also still on-going.
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upcoming compliance decisions is included in the referenced IRPs and reflected in the
proposed depreciable lives for individual units discussed further in this filing.
Second, since 2013 the EPA has initially proposed, partially litigated, rescinded,
and now proposed replacement of the Clean Power Plan focused on reduction of carbon
dioxide ("COz") emissions from the United States energy sector. While no specific
greenhouse gas compliance expenditures were pursued in response to the Clean Power
Plan, the Company's IRP continues to incorporate assumptions and sensitivities
regarding potential greenhouse gas policy outcomes.
Finally, since 2013 the EPA has proposed, partially litigated, and modified its
Coal Combustion Residual regulations as part of the Resource Conservation and
Reclamation Act, as well as its Effluent Limitation Guidelines as part of the Clean
Water Act. These regulations require utilities with coal-fired generation facilities to
meet certain compliance obligations for ash and coal residue handling, infrastructure,
and storage facilities, as well as their process wastewater streams. PacifiCorp's
depreciation study recommendations consider these environmental regulations as well,
but are not significantly impacted at this time by anticipated compliance obligations in
these areas.
Was extending thermal generation resources lives the basis for the Company's
capital expenditures for environmental compliance?
No. While the Company has made capital additions since 2013 on a number of its coal-
fueled generation assets to comply with environmental regulations, the Company's
analysis and justification of these investments assumed that the plant lives would not
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be extended, rather the compliance expenditures would allow the individual unit to
operate through their respective currently approved depreciable lives.
Please explain how emerging policy and market drivers affect the estimated
depreciable lives of generation resources.
Since the Company's 2013 depreciation study, policymakers in the Company's service
territory have continued to propose, consider, and promulgate state-specific policies
affecting the Company's generation resource planning. The Company's long-term
resource planning and estimated depreciable lives of thermal generation resources are
influenced by a variety of policy and market drivers including wholesale power and
natural gas prices, public policy and regulatory initiatives and events and trends
affecting the economy.
One notable public policy example is Oregon Senate Bill 1547-8, which was
signed into law by the governor of Oregon on March 8,2016. Senate Bill 1547-8, the
Clean Electricity and Coal Transition Plan, extends and expands the Oregon Renewable
Portfolio Standard requirement to 50 percent of electricity from renewable resources
by 2040 and requires that coal-fueled resources are eliminated from Oregon's allocation
of electricity by January 1,2030.
This and other planning environment drivers are discussed in detail in Chapter
3 of the Company' s 2017 IRP which is publicly available.
Based on these considerations, what major changes does the Company propose to
the depreciable lives of its thermal generation resources?
The Company is proposing several changes to its thermal generation depreciable lives
based on its analysis of the various factors described earlier in my testimony.
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1 First, the Company recommends accelerating the depreciable life of Cholla Unit
4 from 2042 to 2025 to align with the unit's approved Regional Haze Rule compliance
obligation timeline. This compliance date was established in settlement discussions
between the facility joint owners, state and federal agencies, and stakeholders in 2015
and2016; approvals were received through subsequent state and federal agency public
processes rn2017 and 2018. ChollaUnit4will be 44years old in 2025.
The second recommended change is to accelerate the depreciable lives of Jim
Bridger Units 1 and 2 from 2037 to 2028 and 2032, respectively, to align with the
Company' s 2017 IRP preferred portfolio . The 2017 IRP preferred portfolio reflects the
Company's analysis of potential alternate Regional Haze Rule compliance outcomes
for Units 1 and 2 that result in a least-cost, least-risk outcome for customers when
compared to installation of major emissions control equipment retrofits rn 2021 and
2022, as currently required in the Wyoming Regional Haze state implementation plan,
as approved by EPA. Approval of these accelerated depreciation dates facilitate
alternate Regional Haze compliance decision-making for Units I and2.. The Company
has not yet received state or federal agency approvals of this alternate Regional Haze
compliance outcome for Jim Bridger Units 7 and 2, but has engaged the agencies in
discussions regarding potential alternative compliance Jim Bridger Unit 1 will be 54
years old rn 2028, and Jim Bridger Unit 2 will be 57 years old in 2032.
The third recommended change is to accelerate the depreciable life of Craig
Unit 1 from 2034 to 2025 to align with its approved Regional Haze Rule compliance
obligation timeline. This compliance date was established in settlement discussions
between the facility joint owners, state and federal agencies, and stakeholders in2015
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and2016; approvals were received through subsequent state and federal agency public
processes in2017 and 2018. CraigUnit 1 will be 45 years old in 2025.
The fourth recommended change is to accelerate the depreciable life of Craig
Unit 2 from 2034 to 2026 to facilitate least-cost, least-risk analysis, decision making,
and planning as Craig Unit I approaches retirement in2025, as currently expected, and
CraigUnit 2 economics and joint owner business planning decisions are made in the
interim. The Craig Unit2joint owners and stakeholders have not approved accelerated
retirement of the unit, nor has formal engagement on that potential outcome been
initiated. Craig Unit2 will be 47 years old in 2026.
The fifth recommended change is to accelerate the depreciable life of Colstrip
Units 3 and 4 from 2046 to 2027 to facilitate least-cost, least-risk analysis, decision
making, and planning as announced retirements of Colstrip Units 1 and 2 (non-
Company resources) in2022 approach, and Colstrip Units 3 and 4 economics and joint
owner business planning decisions are made in the interim. The Colstrip Units 3 and 4
joint owners and stakeholders have not approved accelerated retirement of those units,
nor has formal engagement on that potential outcome been initiated. Howeveq certain
joint owners (Avista - 15 percent and Puget Sound Energy - 25 percent) have reached
agreements with their respective regulators to establish 2027 as the new depreciable
life for the units. Colstrip Units 3 and 4 will be 43 years old and 41 years old,
respectively, in 2027 .
For the Company's remaining thermal generation resources, I recommend to
maintain the current depreciable lives consistent with the most recent IRP analysis and
prior depreciation studies.
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Has the Company changed the depreciable lives for its natural gas-fired simple
cycle combustion turbine resources?
No. The Company is not recommending any change to the depreciable lives of its
simple cycle natural gas combustion turbines. The simple cycle combustion turbines in
the Company's fleet are aero-derivative combustion turbines and operate when
economic andlor when required for system reliability purposes. Operating profiles and
assumptions pertaining to outage schedules and equipment longevity for these units
have not materially changed. Moreover, fuel availability for the simple cycle gas
combustion turbine units has not changed. The original equipment manufacturer's 30-
year useful life recommendation has not changed and remains consistent with the 2013
depreciation study.
Has the Company changed the depreciable lives for its natural gas-fired combined
cycle combustion turbine resources?
No. The Company is not recommending any change to the depreciable lives of its
combined cycle gas combustion turbines. These plants operate when economic andlor
when required for system reliability purposes. Since the 2013 study, the operating
profiles and assumptions pertaining to outage schedules and equipment longevity for
these units have not materially changed. Moreover, fuel availability for the combined
cycle gas combustion turbine resources has not changed. The original equipment
manufacturer's 40-year useful life recommendation has not changed and remains
consistent with the 2013 depreciation study. However, it is feasible with continued
maintenance investment and technology advancements that these facilities could
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1 operate economically beyond the original equipment manufacturer's 40-year useful life
recommendation.
DECOMMIS SIONING/DEMOLITION CO STS
Is the Company proposing changes to decommissioning costs in the Depreciation
Study for the Company's thermal generation resources?
Yes. The Company performed updated decommissioning cost studies in the 2014 to
2016 timeframe on a selection of its thermal generation resources considered
reasonable proxy resources for extrapolation across the fleet. These studies were used
as the primary basis for the decommissioning costs in this filing, with certain updates
made to reflect plant specific attributes and updated commodity and scrap market costs.
As such, the Company proposes to replace the previously approved decommissioning
cost of S40 per kilowatt for all coal-fueled plants with the plant-by-plant
decommissioning costs provided in Exhibit No. 6. The Company also proposes to
replace the previously approved decommissioning cost of $15 per kilowatt for all
natural gas-fueled plants with an updated decommissioning cost estimate of $10 per
kilowatt.
The Company hired a third-party engineering firm to complete the baseline
decommissioning studies. The decommissioning costs in Exhibit No. 6, include plant
demolition, ash pile and ash pond abatement and closure, asbestos and other hazardous
materials abatement and remediation, and final site cleanup and restoration as
applicable to each plant.
Does this conclude your direct testimony?
Yes.
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