Transforming UT Electricity Committee
Committee Chair--Juan Ontiveros, P.E., Executive Director of Utilities and
Energy Management
Tom Edgar, PhD, George T. and Gladys H. Abell Endowed Chair of
Engineering, Director of Energy Institute
Michael McCluskey, Executive Manager, Energy Services at LCRA
Stacey Woodard, Qualified Scheduling Entity (QSE) Operations at LCRA
Steve Kraal, PhD, Senior Associate Vice President for Campus Planning and
Facilities Management
Rick Anderson, Energy Strategies (energy purchase/sales consultant)
Declan O'Cleirigh, P.E., P.G., Principal Strategic Energy Analyst, Wholesale
Power Services
Transforming UT Electricity Committee Report
(Response to the Business Productivity Committee’s recommendations for university production and
sale of surplus electricity)
Executive Summary
Every few seconds the energy utility system at The University of Texas at Austin (UT
Austin) adjusts energy production to demand.
That means when:
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Researchers fire up the high definition screens in the Visualization Laboratory, the
system reacts and adjusts.
A worker turns off the banks of lights at Darrell K. Royal-Memorial Stadium, the
system reacts and adjusts.
The afternoon sun heats up the west side of campus buildings, the system reacts and
adjusts.
Whether it’s a science experiment where uninterrupted power is critical or
recharging a phone in an outlet in the Flawn Academic Center, UT Austin power is
reliable; reliable at 99.9998 percent for the last 40 years.
Such responsiveness and reliability is provided with the same amount of natural gas
that the university used nearly 40 years ago because of an innovative energy
management program and aggressive conservation efforts.
The university’s power system has been recognized as one of the best campus
energy systems in the United States.
Can this system provide even greater value to the university by generating more
electricity for sale to the wholesale market?
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That’s the question posed by the President’s Committee on Business Productivity,
which is trying to gauge if certain university assets can create more return to the
university.
A committee formed to explore the idea identified several issues for further
investigation to determine the feasibility of selling electricity generated by the UT
Austin power plant to the wholesale electricity market in Texas. (Attachment A
provides summaries of each committee meeting.)
The issues comprise an interconnected ecosystem of
power production method and means, market
conditions, market regulations, environmental
regulations and contractual obligations. This report
looks at these issues.
How the system works
To understand the issues, it is important to understand
how the UT Austin power plant works.
The UT Austin power plant is a combined heating and
power (CHP) system, which produces both electricity
and useable heat.
All power plants generate excess heat after burning
natural gas or coal to produce electricity. The excess
heat is generally expelled through cooling towers or into
reservoirs.
Committee Charge
The Transforming UT Electrcity
Committee was charged by Pat
Clubb, PhD, Vice President of
University Operations, and Kevin
Hegarty, Vice President and Chief
Financial Officer, to investigate in
detail the ability and potential
value of selling excess power
generated by the Carl J. Eckhardt
Heating and Power Complex to
create revenue for the university.
This ability, value and potential
revenue was to be evaluated
along with consideration for risks
to the plant Title V permit,
Electrical Reliability Council of
Texas (ERCOT) and North
American Electric Reliability
Corporation (NERC) regulations,
the existing agreement with
Austin Energy for standby power
and the General Land Office (GLO)
natural gas purchase agreement.
Commercial utilities can achieve 60 percent efficiency by burning natural gas with
the most efficient equipment. The other 40 percent is wasted.
A CHP facility, on the other hand, converts the waste heat into a useful resource for
heating buildings and providing hot water.
As the UT Austin system burns natural gas, it captures 25 percent of the waste
energy. That waste heat is distributed to the campus for heating and to produce hot
water. An additional 42 percent efficiency is gained from the method the system
uses to produce and distribute cooling from the chilled water plants to the campus
for air conditioning.
The UT Austin power plant burns natural gas with a 40 percent efficiency to
produce electricity, but, with the reuse of heat and chilled water production
technology, overall efficiency is 87 percent. (The calculation converted the
electricity, steam and chilled water produced into BTUs and divided by total
purchased fuel in BTUs on an annual basis.)
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UT Austin’s energy advantage is in the efficiencies the co-generation plant provides.
The stand-alone efficiency of the university’s electrical generation equipment is
much less, therefore the stand-alone power generation costs are much higher.
Since 1996, the university has spent $150 million on CHP equipment and processes
to increase the efficiency of the system. The resulting savings in fuel costs paid for
the improvements.
The system’s natural gas use in 2014 is 12% percent less than in 1996, despite a 22
percent increase in total campus energy demands (a total of 17,877,299 square feet
of conditioned space) for electricity, heating and chilled water.
The university also has an aggressive and active conservation program designed to
reduce power demand even as the campus grows.
New buildings and ones that have been significantly renovated in the past seven
years have been certified for energy savings by the U.S. LEED program. Older
buildings are being retrofitted with energy saving devices (automatic light shutoffs
after periods of inactivity, for example).
The cost to campus for services from the UT Austin power system have been around
$58 million since fiscal year 2009-2010.
In terms of emissions, the efficiency gains have allowed the campus to continue
growing without emitting additional carbon dioxide. Effectively all campus growth
in recent years has been carbon neutral.
The system’s newer equipment is most efficient and does most of the work. Older
equipment, which dates as far back as 1945, is used only when other equipment is
under maintenance or demand rises enough to require additional power.
The UT power plant will face higher loads when it comes time to provide service to
the Dell Medical School and the associated research and office facilities under
construction on the southeast end of the campus.
Operating Environment
The Texas Legislature deregulated the electric utility market in 2002, establishing a
market with wholesale and retail segments. The Electric Reliability Council of Texas
(ERCOT) manages the Texas electric grid.
This legislature allowed municipal utility operations to opt in or out of the
deregulated market. The City of Austin and its utility, Austin Energy, opted out, so
the city’s utility operates as a monopoly. That means if you live in the area served by
Austin Energy, you have to get your electricity from it.
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Because the UT Austin power plant is within the Austin Energy service area, it is not
permitted to sell power within that area nor can it transmit power over the Austin
Energy lines to UT Austin facilities off the main campus such as the J.J. Pickle
Research Campus.
However, Austin Energy is required to allow use of its electrical distribution system,
at a cost, for entities that wish to sell power on the wholesale market.
In the Texas market environment, UT Austin would be considered a wholesale
power producer and would sell to the wholesale market.
Issues
The committee that evaluated the possibility of regularly selling electricity to the
commercial market consisted of management and technical staff from the Lower
Colorado River Authority (LCRA) who are involved in power sales; executive staff
from UT Austin’s Campus Planning and Facilities Management; a faculty member
who is also director of the UT Austin Energy Institute; and a senior member of
Energy Strategies (a consultant actively involved in energy related matters and
energy markets).
Additionally, the committee engaged technical support from Breitling Consulting
(air permit expert), the Good Company (experts in ancillary services in the Texas
Grid) and engineering staff of the power plant.
The LCRA evaluated potential participation of the UT Austin power plant by
factoring in actual equipment performance data, current and projected campus
loads to determine surplus generation and estimated ERCOT market prices for
2014- 2017. The LCRA assessment was based on the modeling software UPLANNPM Network Power Model, which the LCRA uses to determine its ability to sell
power into the ERCOT market (see Attachment B for more information).
The committee identified the following challenges:
Contractual Obligation
UT Austin has a contract with Austin Energy that calls for the city utility to
sell power, if needed, to the campus at reasonable rates.
This agreement gives the university flexibility in operations (such as the use
of Austin Energy power during maintenance) and provides a valuable back
up resource in an emergency.
Should the university sell power to the open market, it is likely the
agreement with Austin Energy would be terminated and a new one would be
negotiated.
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It is estimated that a new contract could add at least $500,000 a year to the
UT Austin’s utility operating costs, according to an in-house analysis
performed a few years ago using feedback from Austin Energy.
Remaining issue: Austin Energy’s definitive answers as to its position on
renegotiating the standby agreement are needed.
Market Regulations
The UT Austin power plant operates as what is called a self-generator in the
Texas electrical grid. That means that because of its confined nature and that
it rarely sends or receives power, the UT power plant is not considered part
of the Texas grid. This allows UT Austin to produce power for use on the
main campus without registering with the ERCOT system.
If the university were to sell power to the Texas wholesale market, it would
have to comply with ERCOT requirements as well as those of the North
American Electric Reliability Corp. (NERC), which oversees the national grid.
The committee’s research indicated that capital costs required to bring
equipment into compliance with these requirements would be around
$500,000 and additional annual operating costs would be about $100,000.
Remaining issue: Determine the specific ERCOT requirements UT Austin would
have to meet and calculate the costs of meeting them.
Market Prices
In the current market structure, ERCOT is required to choose the provider
with the lowest cost when seeking additional power for the Texas grid.
As noted before, the UT Austin power plant is very efficient in its overall use
of power. However, its cost to generate power is higher than that of
commercial utilities.
Commercial utilities, operating at a much larger scale than UT Austin, use
more powerful generating equipment that wrings more energy out the
natural gas source fuel. This means the commercial utilities have a lower cost
to generate electricity.
Looking at the cost of producing power in the next few years, the UT Austin
power plant costs would range from $55 per MWh in 2014 to $78 per MWh
in 2017. For the UT Austin power plant to be competitive, the average market
prices would have to range from $37 per MWh to $44 per MWh for those
years.
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Remaining issue: A more detailed analysis of the UT Austin power plant’s costs
and expected cost of fuel in the coming years is needed to determine whether
UT Austin can provide electricity competitively.
Environmental Regulations
The UT Austin power plant operates under a Title V air quality permit issued
by the Texas Commission on Environmental Quality (TCEQ). The permit
classification is specific to institutions such as universities and it limits the
sale of power outside the institution.
Should UT Austin participate in the wholesale energy market and its output
exceed 33 percent of capacity over three-year period, UT Austin would have
to apply for a new permit as a utility.
The committee’s research indicated that because the UT Austin power plant
efficiencies result from operations that leverage the interconnection of
power, steam and chilled water systems, it would not be possible to sell
power without exceeding the limitations of the existing permit.
A new permit classifying the UT Austin power plant as a commercial utility
would require changes to existing equipment.
Because of UT Austin’s power plant location (in the middle of campus), its
options in making significant upgrades to equipment are severely
constrained. It is likely new equipment would be needed.
Based on the committee’s broad experience the replacement costs to upgrade
the plant to commercial viability would be significant. Moreover, it would be
challenging to phase in new equipment without affecting ongoing provision
of electricity, heating and cooling to the campus.
Remaining issue: Specific changes would be needed in order for the UT Austin
power plant to comply with more stringent requirements of a different
permitting classification and the associated costs.
Risk Management
If it sold power to the wholesale market, UT Austin would have to guarantee
that it would deliver electricity as contracted or replace it at market costs. If
UT Austin committed to a 10 MW sale for five hours, but could not deliver
because the power plant faltered, the university could be held liable for more
than $450,000 using peak power pricing assumptions.
Remaining issue: Determine the exposure UT Austin would have if it could not
meet obligations in selling power and how we mitigate that financial risk in
order to protect the university from such costs.
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Equipment
The opportunities to participate in the wholesale market may be improved
by shifting campus generation to older equipment and using newer, more
efficient equipment to generate power for sale.
This would mean higher utility costs for the campus, not only for power, but
also chilled water and steam and reduced reliability as well as capacity.
Remaining issues: An analysis of the actions and costs to implement this
approach is needed as well as identifying the risks to campus operations.
A cost estimate of putting mitigation strategies in place also would be needed
{e.g., additional back-up power, load shed strategies (prioritizing which
buildings and systems to which power could be reduced)}.The final step would
be to develop a return-on-investment calculation.
Scenarios for selling power
The LCRA evaluated the UT Austin power plant using the same process it uses to
buy and sell power in the ERCOT market and determined that UT Austin would have
limited opportunity to sell power into the ERCOT market, primarily because of
power generation efficiency issues that affect power pricing.
The ERCOT market is based solely on the efficiency of stand-alone electrical
generating equipment. UT Austin’s overall efficiency of 87% is based on the
combined effect of producing electricity, chilled water and steam in combination.
The stand-alone efficiency of our electrical generation equipment is below the
general standard for entry into the ERCOT market.
In this case, the UT Austin power generation equipment would produce electricity in
a range between $55 MWh to $78 MWh for 2014-2017. The ECROT price point
ranges from $37 MWh to $44 MWh for the same period.
As noted previously, the most effective existing power producers in the wholesale
market can produce electricity at efficiencies of about 50 percent to 60 percent
while the UT Austin power plant produces electricity only at about 40 percent.
These commercial power production plants are on a totally different scale (200 MW
or bigger or about four times the peak power need of the campus). So strictly
considering electrical production, the UT Austin power plant cannot compete on an
efficiency or cost basis.
Perhaps the most feasible scenario would be for UT Austin to offer to provide
Emergency Response Services. In this situation, the UT Austin power plant could
send electricity to the grid under emergency conditions.
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In this approach, UT Austin would not have to register with ERCOT for the
wholesale market, and additional operating and fuel costs would be minimized.
The projected revenue from this approach would be $500,000.However, it is not
clear if NERC requirements must be met, so this would require additional
investigation.
Remaining issue: An analysis of specific rewards, risks and expenses of providing
Emergency Response Services would be needed.
Long-term Option
In considering the sale of UT Austin-generated electricity, the committee identified
the state of the UT Austin power plant’s equipment.
While it performs at a very high level and more than meets the needs of the
university, the power plant is not competitive with the equipment deployed by
commercial utilities.
As the university grows and changes in the coming years, it is probable that the UT
Austin power plant would have to change as well.
It might be time to establish a long-term plan to develop the power plant for the
future. While the top priority would be to serve the students, faculty and staff of the
university, it also could be engineered with an eye to offering electricity for sale on
the wholesale market in Texas.
This would allow the university to engage in the market with competitive
equipment, it would also be an opportunity to restart with regulatory agencies to
make sure that regulations and associated costs are factored in from the beginning.
Remaining issue: Forecast future university energy needs and the equipment needed to
meet them. Projections would need to include the possibility of selling electricity to the
wholesale market.
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Attachment A
Electricity Committee Meeting Summaries and
Analysis
First Meeting
The first meeting was held on September 26, 2013.
Attendees
Committee:
Juan Ontiveros, P.E., Executive Director of Utilities and Energy Management
Tom Edgar, PhD, George T. and Gladys H. Abell Endowed Chair of Engineering, Director of Energy
Institute
Michael McCluskey, Executive Manager, Energy Services at LCRA
Stacey Woodard, Qualified Scheduling Entity (QSE) Operations at LCRA
Steve Kraal, PhD, Senior Associate Vice President for Campus Planning and Facilities
Management
Rick Anderson, Energy Strategies (energy purchase/sales consultant)
Declan O'Cleirigh, P.E., P.G., Principal Strategic Energy Analyst, Wholesale Power Services
Technical Support:
Mike Manoucheri, P.E., Associate Director of Plant Operations
Al Schuman, P.E. Associate Director of Electrical Distribution
Ryan Thompson, P.E., Maintenance Manager (air permit and plant efficiency)
Roberto DelReal, P.E., Manager of Instrumentation and Controls (network security, automation)
Attendee Roles:
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Juan Ontiveros, Chair
Steve Kraal, PhD, university executive over the Utilities and Energy Management
Department
Michael McCluskey, provide market insight and oversee an analysis of the UT plant
generation equipment in relation to financial viability, prevailing heat rates in ERCOT, and
natural gas costs projected over a five year period
Stacey Woodard, provide Qualified Scheduling Entity and ERCOT operational insight
Declan O’Cleirigh, provide expertise to interpret the plant information and hourly load data
that could be used in the model to evaluate the financial viability of the UT plant in the
ERCOT Market and actually run the model
Tom Edgar, PhD, provide insight to the committee based on knowledge gained through
various engineering student projects performed collaboratively with the UT Power Plant
Rick Anderson, provide insight based on intimate knowledge of the UT Plant gained through
assistance with fuel purchases, energy master planning and energy conservation efforts with
UT and others.
Mike Manoucheri, provide insight on the plant operation and operational data
Al Schuman, provide insight on the electrical distribution and transmissions systems on
campus
Ryan Thompson, provide insight on maintenance related issues and planning of the plant
along with the Title V air discharge permit.
Roberto DelReal, provide insight on firewall systems and instrumentation and data
acquisition of the UT Plant.
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Attachment A
Meeting Summary
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Juan Ontiveros gave a presentation describing the power plant as a background and
explained current understanding of impact to load growth for the Medical School and other
projects.
Mike Manoucheri described data provided to LCRA projecting load growth out to 2018 for
purpose of the modeling.
Michael McCluskey, Declan O'Cleirigh, Juan Ontiveros, Mike Manoucheri and Ryan Thompson
met prior to this meeting to get a better understanding of the data that would be needed to
accomplish the modeling. The data was provided prior to the meeting, with preliminary
results being presented at the next meeting in October.
Tim Mould, Accenture, provided a synopsis of the information provided to the Committee on
Business Productivity. The complete presentation was provided electronically to the
Committee on Energy Sales. He agreed that a deeper dive into the information provided by
the campus on the plant operations and financial viability as they relate to the ERCOT
market was a prudent next step. The recommendation provided by the Committee on
Business Productivity to the campus was a much higher level investigation on the issue of
power sales.
Second Meeting
The second meeting was held on October 17, 2013.
Attendees
Attendees included those at the first meeting except Rick Anderson. Additional attendees:
Karin Schweitzer, Manager, NERC Compliance at LCRA, (NERC and ERCOT regulatory compliance)
Amanda Breitling, Breitling Consulting, LLC, air permit consultant
Meeting Summary
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Ms. Breitling explained that if, over a three-year period, average electrical sales exceed onethird of the nameplate capacity of the electric generating equipment, operations would
become categorized as “utility electrical generation.” As such, they would be subject to more
stringent air quality regulations. Compliance with lower emissions standards and increased
monitoring requirements would result in extensive and costly capital improvements.
She further explained that without formally contacting the Texas Commission on
Environmental Quality (TCEQ) for a specific answer, her interpretation was that the 1/3
threshold applies on a per unit basis to units that are rated at ≥25MW. The 1/3 refers to
aggregate generating hours over a three year period. That is, export at full capacity is
allowed, provided that the total three year average of exported power does not exceed 1/3
of three years of full capacity.
Based on the understanding of the current plant configuration, the university would have
three sources of electricity to track: Turbine 8, Turbine 10, and Turbine 7/9.
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If Turbine 8 were to exceed the 1/3 threshold, then it would only trigger the utility
electrical generation air quality requirements for Turbine 8.
Likewise, if Turbine 10 were to exceed the 1/3 threshold, then it would only trigger
the air quality requirements for Turbine 10.
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Attachment A
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Due to the common steam configuration for Turbine 7 and Turbine 9, the threshold
of 1/3 the capacity of a single unit (73,000 MWh) would have to be applied to the
electrical sales from both units.
If Turbine 7/9 were to exceed the 1/3 threshold, that would trigger the air quality
requirements for Boilers 1, 2, 3, 7, 8, and 10 unless steam was isolated in some way.
Attendees discussed the Austin Energy Standby Agreement and deemed it to be typical of the
industry in Texas that allows for the utility to remain non-deregulated. Selling power to the
Texas Grid could potentially void the agreement with a new interconnect agreement likely
being required.
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This would increase the uncertainty of the value of the sale of excess power since a new
agreement with Austin Energy is likely to be significantly more expensive than the current
agreement.
Mr. O’Cleirigh provided a preliminary analysis of a UPLAN model run. The revenues were
lower than anticipated due to market conditions currently experienced in the Texas Grid,
with low power pricing created by low natural gas prices. The analysis excluded operational
expenses and Title V permit interpretations.
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Ms. Woodard provided an explanation of the market participation process for the committee.
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Mr. DelReal presented the condition of the effort to improve cyber security for the plants.
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Ms. Schweitzer explained that she believed the UT Plants would not have to meet NERC
Critical Infrastructure Protection (CIP) requirements under NERC CIP version 4 because it
only applies to critical plants. (*See note, page 7.) NERC Operations and Planning Standards
(also referred to as FERC Order 693 Standards) for Generator Owners would apply. In
addition, significant ERCOT rules would become requirements should the decision be made
to sell power.
Supporting NERC and ERCOT compliance activities would require a substantial
administrative organization. UT Plants would also have to obtain certain equipment
certifications that currently do not exist to meet all of the ERCOT requirements. Should the
decision be made to sell power, administrative issues will need to be investigated in detail
and arrangements made to set up an organization to accomplish this. These increased
administrative tasks will carry cost that would be an offset to any economic gains realized
through the sale of excess power.
* Note: On November 22, 2013, the Federal Energy Regulatory Commission (FERC) approved NERC
CIP Version 5 Standards and elected to bypass Version 4 of the Standards. Under Version 5, all
generation must comply with the requirements as either a Low, Medium or High asset as identified
within Attachment 1 of CIP-002-5.1.
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Attachment A
Third Meeting
The third meeting was held November 15, 2013.
Attendees
In attendance were all but Dr. Kraal and Rick Anderson.
Additional attendees:
Amanda Breitling, Breitling Consulting
Mr. Robert King and Ms. Suzi McClellan, of Good Company Associates (Emergency Response Program
description)
Jongsuk Kim and Kody Powell, graduate students working with Dr. Edgar.
Meeting Summary
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Mr. Thompson worked in detail with Dr. Edgar and the two graduate students to develop a
theoretical model of the campus power plant to analyze the economics of buying/selling
power into the Texas Electric Market. Mr. Thompson presented the findings of the various
scenarios analyzed by the students.
o In general the model reflected very accurately how the plant operates in actuality.
o One finding of the analysis, which was based on a narrow window of time less than
a year, was that significant savings (21.4% reduction in costs) could be realized by
both buying and selling power at opportune times. However, because Austin
Energy has opted out of deregulation the campus cannot purchase power from the
wholesale market.
o 14.6% in operational savings could be realized by selling power opportunistically
because market power costs are higher than generation costs.
o 1.7% savings could be realized by operating the plant more optimally.
o The savings in the narrow window of time ranged from $27,000 to $3.42 million.
Mr. King and Ms. McClellan described the opportunity available by participating in the
ERCOT Emergency Response Program.
o Participation in the program is obtained by first making a formal application to
ERCOT and then bidding in during windows of opportunity open at various times
during the year.
o Payment for being on emergency stand-by is provided even if not dispatched
during emergency periods. If called, emergency response service dispatch is
required within 30 minutes.
o If dispatch is prevented due to equipment problems in the plant, the only penalty is
a forced non-participation during the next window of opportunity.
o Normal ERCOT compliance rules are waived.
o It is unknown if NERC compliance rules would apply, so a legal opinion is
recommended before proceeding.
Mr. O’Cleirigh presented the final results of the UPLAN model runs, described in the
following section.
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Attachment B
UPLAN-NPM Network Power Model
How UPLAN Works
 Simulates a day-ahead market and optimizes the commitment of resources for energy and
ancillary services.
 Commitment and dispatch algorithms incorporate both optimal power flow and resource
scheduling.
 Characterizes generators’ market participation based on opportunity or marginal cost-based
bidding.
Key model inputs (in addition to the above):
 Five-year annual transmission topography (provided by ERCOT)
 ERCOT Load Forecast
 Generator data (500+), fuel prices, environmental constraints
 Fuel cost
 ERCOT Capacity, Additions/Retirements
 Environmental costs
 Current and projected market pricing opportunities
 Typical variable maintenance costs
o No Operations & Maintenance (O&M) costs
o No debt or capital expenditure
Assumptions:
 ERCOT and UT Load
o ERCOT Base Case Load for 2014 – 2017. UT Load is not added to the ERCOT Load
(<3% of Austin Energy Load Zone) for this analysis.
o UT Load is escalated at 1.5% per year through 2014 and from 2016 – 2022;
additional building load added in 2015 (Medical School).
 Gas Price
o NYMEX for 2014 and 2015 transitioning to third party forecast services for 2016
through 2022
 Coal Price
o Third party forecasting services (Texas uses a significant amount of coal based
generation.)
 ERCOT Generation Additions/Retirements
o Based on ERCOT Capacity, Demand and Reserve Report and third party data
services
 Environmental Emission Costs
o CO2 compliance cost not forecasted to be in play before 2021/2023
o Mercury and Air Toxics Standards (MATS) are not seen to have a major impact in
ERCOT (coal based generation requirements).
 ERCOT Market
o Resource Adequacy Market Adjustments
 Recent changes to the System Wide Offer Cap (SWOC) are included in the
model. The SWOC currently is at $5,000/MWh, rising to $7,000/MWh on
June 1, 2014 and to $9,000/MWh on June 1, 2015.
 The Operating Reserve Demand Curve (ORDC) market modifications are
not included.
 Potential Capacity Market benefits are not included.
 UT Grid Connection
o The Harris Bus (Node) is used to determine UT generation values.
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Attachment B
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Operational and Maintenance Costs (O&M)
o Variable and fixed O&M costs are based on industry values for combined cycle and
combustion turbine generating plants.
o Variable O&M cost are included as a model input for each generator
o The rate of O&M expenditure has not been increased to reflect the expected
additional wear and tear on the UT assets as asset use is increased or maximized.
o An attempt was made to differentiate between expected O&M and additional O&M
costs that would likely be incurred.
No additional capital costs (O&M projects) included in analysis. (For comparison purposes,
UT’s FY10/11 O&M Line Item expense of $5m falls within 6% of expected industry average
O&M costs.)
Modeling Process
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Base Case: Modeled to match current UT operations
o Jan 1 – Apr 14: GT 10 + ST 9 in combined cycle mode with GT 8 modeled as
standalone unit (peaker)
o Apr 15 – Sept 15: GT 8 + ST 9 in combined cycle mode with GT 10 modeled as
standalone unit
o Sept 16 – Dec 31: GT 10 + ST 9 in combined cycle mode with GT 8 modeled as
standalone unit
Case 1: Modeled to match current UT operations, plus economic dispatch of second GT
o Jan 1 – Apr 14: GT 10 + ST 9 in combined cycle mode with GT 8 modeled as
standalone unit (peaker)
o Apr 15 – Sept 15: GT 8 + ST 9 in combined cycle mode with GT 10 modeled as
standalone unit
o Sept 16 – Dec 31: GT 10 + ST 9 in combined cycle mode with GT 8 modeled as
standalone unit
Case 2: Generators modeled to maximize generation.
o Both GTs and both STs are assumed available for power production.
o No change to planned outage schedule.
o ST 7 capacity increased to 37 MW for modeling purposes to represent ST 4 and ST 5
capabilities.
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Attachment B
Model Results
The following figures show results of modeling as described above: current UT operations (Base
Case), current operations plus dispatch of the second gas turbine (Case1), and maximized generators
(Case2).
Figure 2: Current UT operations
The increase in O&M costs, as detailed in Figures 3 and 4 reflects the proportional increase in
variable O&M costs associated with the increased generation (but at the same O&M rate as current
operations).
Figure 3: Current UT operations, plus dispatch of 2nd Gas Turbine
Figure 4: Modeled to maximize generation
Other Considerations
In addition to the modeling results, the Committee on Energy Sales identified these additional
considerations that must be addressed or investigated further:
 Exposure to replacement power costs if plant trips offline while selling
 Additional Operations & Maintenance Project costs required to maintain UT asset availability
(increased outage costs, etc.)
 Limitations in current GLO fuel contract
 ERCOT related costs
o Establishing and operating a Compliance Department
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Attachment B
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o Certifying generation equipment, which will require investment
NERC compliance costs
Air Permit impact
Electrical market changes
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