20211203Application.pdf

DONOVAN WALKER
Lead Counsel
[e-mail]
December 3, 2021
VIA ELECTRONIC FILING
Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-21-41
In The Matter Of Idaho Power Company’s Application For Authority to
Proceed with Resource Procurements to Meet Identified Capacity
Deficiencies in 2023, 2024, and 2025 to Ensure Adequate, Reliable, and
Fair-Priced Service to its Customers
Dear Ms. Noriyuki:
Enclosed for electronic filing, please find Idaho Power Company’s Application for
Authority to Proceed with Resource Procurements in the above matter. Please feel free to
contact me directly with any questions you might have about this filing.
Very truly yours,
Donovan E. Walker
DEW:cld
Enclosures
RECEIVED
2021 DEC -3 PM 4:36
IDAHO PUBLIC
UTILITIES COMMISSION
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 1
DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]

Attorney for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
AUTHORITY TO PROCEED WITH
RESOURCE PROCUREMENTS TO MEET
IDENTIFIED CAPACITY DEFICIENCIES IN
2023, 2024, AND 2025 TO ENSURE
ADEQUATE, RELIABLE, AND FAIR-PRICED
SERVICE TO ITS CUSTOMERS.
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CASE NO. IPC-E-21-41

APPLICATION FOR AUTHORITY
TO PROCEED WITH
RESOURCE PROCUREMENTS

Idaho Power Company (“Idaho Power” or “Company”), in accordance with Idaho
Code §§ 61-501, 61-502, 61-503, 61-508, 61-526; as well as RP 52, and 112, hereby
respectfully makes application to the Idaho Public Utilities Commission (“Commission” or
“IPUC”) for an order authorizing the Company to move forward with the procurement of
capacity resources needed to provide adequate, reliable, and fair-priced service to
customers. Idaho Power requests that the Commission issue an order: (1) eliminating
the IPUC requirement to comply with the Public Utility Commission of Oregon (“OPUC”)
resource procurement rules in favor of a competitive, but expedited process; (2)
authorizing Idaho Power to move forward expeditiously with resource procurements to
meet identified generation resource needs in 2023, 2024, and 2025; and (3) affirming
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 2
support and the continuation of the state of Idaho’s system of public utility regulation under
which the interests of customers are best served by a vertically integrated electric utility
maintaining ownership of the necessary generation, transmission and distribution utility
functions, with limited exceptions.
I. INTRODUCTION AND SUMMARY - A DYNAMIC
ENERGY LANDSCAPE

Idaho Power has not added a supply-side, dispatchable resource since the
Langley Gulch combined-cycle, natural gas combustion turbine, which was granted a
Certificate of Public Convenience and Necessity (“CPCN” or “Certificate”) in 2009.1 Idaho
Power’s most recent Integrated Resource Plan (“IRP”), the Second Amended 2019 IRP,
acknowledged by the Commission on March 16, 20212, does not show a first capacity
deficit until the summer of 2028. However, during the preparation of the 2021 IRP that
Idaho Power anticipates filing before the end of this year, an updated Load and Resource
(“L&R”) balance analysis in May 2021 identified a first capacity deficit of 78 megawatts
(“MW”) in June of 2023, growing each year through 2026, when the Boardman to
Hemingway (“B2H”) 500 kilovolt transmission line is expected to be operational. This
rapid change in deficit position was caused by several dynamic and evolving factors
including: third-party transmission constraints and changes to the assumptions in the
L&R balance regarding available transmission capacity following the retirement of coal
plants; the unavailability of import transmission capacity on the market; planning margin
adjustments associated with incorporating Loss of Load Expectation (“LOLE”) and
Effective Load Carrying Capability (“ELCC”) planning methodologies; increasing
population and associated emergent demands on the Company’s system; and the

1 Case No. IPC-E-09-03, Order No. 30892
2 Case No. IPC-E-19-19, Order No. 34959.
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 3
diminishing demand response (“DR”) resource effectiveness and low solar generation
effectiveness during critical demand hours. These factors and the dynamic energy
landscape in which the Company is operating are discussed further in this Application.
Under Idaho law, Idaho Power has an obligation to provide adequate, efficient,
just, and reasonable service on a nondiscriminatory basis to all those that request it within
its certificated service area.3 In order to meet its obligations to reliably serve customer
load, and given the extremely short turn-around to construct a resource to meet a summer
2023 deficit, particularly in the midst of supply chain disruption,4 ongoing COVID-19
impacts, and constraints in the industry and in ancillary industries, the Company is
currently conducting a competitive solicitation through a Request for Proposals (“RFP”)
seeking to acquire up to 80 MW of company-owned resources to meet the 2023 capacity
deficit - seeking projects to be online by June of 2023. The RFP contemplated wind,
solar, energy storage, some combination of the forementioned resources, or other options
to meet critical demand hours. Idaho Power is also, in parallel, investigating different
configurations of Company owned and constructed battery storage systems, possible
modifications to existing DR programs5, and pursuing other short-term market solutions
in attempts to meet the forecasted capacity deficits. However, this will not be enough to
meet the rapidly evolving and dynamic forecasted capacity deficits.
In 2010, the Commission initiated a case6 seeking to establish competitive bidding
guidelines for the RFP process used to acquire supply-side resources by Idaho Power.

3 Idaho Code §§ 61-302, 61-315, 61-507.
4 Idaho Power has seen the general supply chain disruption in its own supply chain which has increased timelines
across the board. The Notice of Force Majeure received by Idaho Power from Jackpot Holdings is based upon and
also evidences the wide-spread nature and uncertainty in the current environment regarding third parties’ ability to
deal with such issues even when needed to meet their firm contractual commitments. See generally, How the Supply
Chain Broke, and Why It Won’t Be Fixed Anytime Soon, Peter S. Goodman, New York Times, Oct. 31, 2021.
Supply Chain Shortages: Your Questions Answered - The New York Times (nytimes.com)
5 IPC-E-21-32
6 Case No. IPC-E-10-03.
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 4
In 2013, the Commission closed this case without establishing Idaho-specific resource
procurement guidelines, but rather directed Idaho Power to follow the RFP guidelines
applicable in its Oregon service area. The Oregon RFP guidelines to which the
Commission referred were later codified into the administrative rules of the OPUC. OAR
860-089-0010 et. seq. (“OPUC Resource Procurement Rules”). The OPUC Resource
Procurement Rules impose competitive bidding requirements upon an electric utility for
the “acquisition of a resource or a contract for more than an aggregate of 80 megawatts
and five years in length,” among other requirements. OAR 860-089-0100(1)(a). There
are certain exceptions to the applicability of the OPUC Resource Procurement Rules,
including the exception used for executing the Jackpot Solar power purchase contract:7
“There is a time-limited opportunity to acquire a resource of unique value to the electric
company’s customers.” OAR 860-089-0100(3)(b). The OPUC Resource Procurement
Rules also contain an exception to their applicability based upon the OPUC
acknowledging an alternative acquisition method in the utility’s IRP. OAR 860-089-
0100(3)(c). What the OPUC Resource Procurement Rules do not contain, however, is
an exception or exemption from the lengthy procurement process for when a utility
identifies a critical and time-sensitive need to obtain capacity resource to reliably serve
load.
While the 80 MW RFP could be addressed through a procurement process that
was not subject to the OPUC Resource Procurement Rules due to the size-based
exception, additional capacity deficits recently identified for 2023, 2024, and 2025 will
require incremental generating capacity that exceeds the 80 MW applicability threshold
for the OPUC Resource Procurement Rules. Applying the OPUC Resource Procurement

7 IPC-E-19-14
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 5
Rules to the procurement processes needed to meet the currently identified capacity
deficits in 2023, 2024, and 2025 would be extremely detrimental to the Company and its
customers from both a timing and a methodology standpoint.
The proposed acquisitions, as described in this Application, are necessary and
required in a dynamic energy landscape in order to continue to provide reliable and
adequate electric service to Idaho Power’s customers starting in the summer of 2023 and
into the future. To timely meet its resource needs and continue to provide reliable service,
the Company requests that it be relieved of the IPUC’s requirement to follow the OPUC
Resource Procurement Rules and that it be authorized to move forward with capacity
resource procurements under RFP guidelines outlined below to meet the identified
deficits in 2023, 2024, and 2025. As required by Idaho law, the Company would
subsequently bring Certificate of Public Convenience and Necessity filings to the
Commission for any supply-side resources identified through the procurement processes,
with the Commission’s attendant review of the resource need and expected costs for the
procurement. Ultimately, a review of the prudence of costs incurred would occur in a
general rate case or other revenue requirement proceeding prior to authorization of cost
recovery through customer rates.
II. SEVERAL FACTORS HAVE RESULTED IN AN URGENT
CAPACITY RESOURCE NEED

As noted above, Idaho Power has been generally resource-sufficient since the
addition of the Langley Gulch natural gas-fired power plant almost a decade ago but has
rapidly moved from an expected resource-sufficient position, through 2028, to a near-
term capacity deficiency starting in 2023, since the acknowledgement of the 2019 IRP in
March of this year. Idaho Power’s most current L&R balance analysis as of November
2021 identifies capacity deficits beginning in 2023 and growing each year until 2026,
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when the B2H 500 kilovolt transmission line is expected to be operational. In addition to
load growth, several factors have contributed to the notable change in the L&R balance,
including significant current third-party transmission constraints limiting wholesale market
import purchases at peak, the ability of DR programs to meet peak load, planning margins
and methodology modernization, and environmental regulatory uncertainty and
economics for fossil fuel-fired power plants and the related timing of ceasing operations
at those resources.
In May 2021, the Company identified the 2023 deficit as approximately 78 MW at
the time Idaho Power issued the currently pending RFP to acquire up to 80 MW of
dispatchable capacity resource. The following Table 1 details the projected capacity
deficits for the years 2023 through 2025, updated to include the most current data from
the preparation of the 2021 IRP.8 As shown below in Table 1, the Company’s projected
capacity deficits have grown to 101 MW in 2023, 186 MW in 2024, and 311 MW in 2025.

Table 1: Peak-Hour Load and Resource Balance
2023 2024 2025
23-Jul 24-Jul 25-Jul
Surplus / Deficit (MW) -101 -186 -311

Changes in L&R Since the 2019 IRP: Idaho Power filed its Second Amended
2019 IRP on October 2, 2020. The goal of the IRP is to ensure: (1) Idaho Power’s system
has sufficient resources to reliably serve customer demand and flexible capacity needs
over a 20-year planning period; (2) the selected resource portfolio balances cost, risk,

8 As of November 30, 2021, the developer of the Jackpot Solar project indicated that a delay is likely. If Jackpot
Solar is not in-service by summer 2023 then Idaho Power will need approximately 40 MW of additional summer
peak capacity to meet projected customer demands.
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 7
and environmental concerns; (3) balanced treatment is given to both supply-side
resources and demand-side measures; and (4) the public is involved in the planning
process in a meaningful way. Historically, the Company developed portfolios to eliminate
resource deficiencies identified in a 20-year L&R balance. The L&R balance from the
Second Amended 2019 did not show a capacity deficiency occurring until the summer of
2028. However, the Company’s L&R balance analysis has since been updated a number
of times as circumstances and conditions have changed significantly in the interim, with
each iteration showing capacity deficits as early as 2023.
Following development of the Second Amended 2019 IRP, the Company
conducted focused system reliability and economic analyses to assess the appropriate
timing of a Valmy Unit 2 exit between 2022 and 2025. The result of the reliability and
economic evaluations demonstrated that coal-fired operations of Valmy Unit 2 through
the end of 2025 is the most reliable and economic path forward.
The analysis that led to this conclusion started with adjustment of the L&R balance
analysis used in the Second Amended 2019 IRP as part of the Valmy Unit 2 reliability and
economic impact analyses completed in May 2021. Development of the 2021 IRP was
occurring simultaneously, and the Company updated the L&R balance to include
modifications to existing resource availability, as is standard when developing the L&R
balance as part of the IRP process. First, the Company identified changes to its market
purchase assumptions due to third party transmission constraints. Additionally, the
existing resource availability was revised to include updated thermal capacity and
reduced DR capacity determined through the refinement of the planning margin
calculation. The net change between the Second Amended 2019 IRP and the updated
L&R balance is a reduction of over 500 MW in available capacity each July during the
2022 through 2025 time period. As a result of these changes to the L&R balance in May
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2021, the Company anticipated a capacity deficit of approximately 78 MW in 2023,
assuming Valmy Unit 2 operations continue through 2025.
As can be seen on Table 1, the final L&R balance used for the 2021 IRP indicates
the 2023 capacity deficit of 78 MW, as calculated in May 2021, has grown to 101 MW.
While all the same factors that influenced the changes in the May 2021 L&R balance still
exist, the latest L&R balance includes a revised load forecast with greater load growth
projections.
Transmission Market Shifts and Constraints: In the Second Amended 2019
IRP, the Company assumed Valmy Unit 2 could be replaced with capacity purchases from
the south. However, market conditions have changed dramatically because of ripple
effects stemming from the August 2020 energy emergency event in California. During
this event, the West experienced a heat wave, increasing the demand for energy and
causing several balancing authorities across the Western Interconnection to declare
energy emergencies. Generation was not able to meet demand in California and
transmission capacity was strained, limiting the ability to import energy. As a result, the
California Independent System Operator was required to shed firm load to maintain the
reliability and security of the bulk power system. Ultimately, this also impacted Idaho
Power’s ability to use third party transmission to import energy and meet load deficits.
Understanding the importance of transmission availability during times of high
electricity demand, third-party marketing firms began reserving unprecedented amounts
of firm transmission capacity just outside the Company’s border, significantly limiting
Idaho Power’s access to market hubs. Soon after the event, Idaho Power’s own
transmission service queue was flooded with multi-year requests totaling 1,293 MW, as
of April 2021, looking to move energy from the Mid-C hub across Idaho Power’s
transmission system to the south.
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While the Company is able to reserve its own transmission for usage by the
Company’s customers, the transmission service requests just outside of Idaho Power’s
borders have added constraints to an already constrained market limiting the Company’s
access to capacity at Mid-C. Idaho Power tested the market availability with an RFP
issued April 26, 2021, which ultimately validated the existence of these transmission
system constraints. The RFP requested a market purchase with delivery at Idaho
Power’s border; however, no bids were received at any price-point, further emphasizing
the difficulty of importing energy under a constrained transmission system.
As a result of these recent and significant market changes, for the years 2023
through 2025, Idaho Power has reduced the transmission availability within the L&R
balance from approximately 900 MW in the 2019 IRP to approximately 700 MW in the
2021 IRP during the peak load month of July.
Planning Margin Adjustments: The Company’s planning margin is intended to
provide a sufficient reliability margin to prevent the need to curtail customer demand more
than one time in 20 years. The planning margin is intended to cover (1) Idaho Power’s
contingency reserve obligation, (2) severe weather events, consisting of both extreme
heat and extreme cold, (3) poor water conditions, and (4) planned and unplanned
resource and transmission outages. In the Second Amended 2019 IRP, Idaho Power
established a 15 percent planning margin, which was calculated as 15 percent of the
Company’s average (50th percentile) peak demand forecast for each month. For
example, if Idaho Power had a peak-hour-load of 3,500 MW, the Company would add the
planning margin and target 4,025 MW of resource capacity (3,500 multiplied by 1.15).
Following the development of the Second Amended 2019 IRP, the Company
looked to refine its planning margin in accordance with best practices to ensure
consideration of issues specific to Idaho Power’s system. The 15 percent planning
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margin utilized in the Second Amended 2019 IRP is essentially a rule of thumb. Individual
utilities can experience different frequencies of demand extremes, varying forced outage
rates among resources, and resource size compared to load size, all of which should be
considered when determining the planning margin. Rather than continue to utilize a
planning margin based on a rule of thumb, the Company modernized its approach and is
using probabilistic methods in the 2021 IRP to determine system needs to ensure
reliability for all hours of the day on the Company’s system, which is the “LOLE method.”
The LOLE approach allows for a comparison of load to generation on an hourly
basis over a specified period. Given feedback from the IRP Advisory Council, and the
increased frequency of extreme events, the Company aligned with the Northwest Power
and Conservation Council standard of no more than one loss of load event per 20 years,
or an LOLE of 0.05 days per year. The Company believes the LOLE method’s hourly
approach fully considers the reliability value of renewable resources over time compared
to the previous method.
In addition to taking a more granular hourly approach, the LOLE method evaluates
the capability of existing resources to meet peak demand through the determination of
the ELCC. Use of the ELCC resulted in a change to the peak-serving capability of Idaho
Power’s existing resources, most notably the peak capacity contribution of DR. When
analyzing the Company’s system on an hour-by-hour basis, the results indicate the ability
of DR programs to meet peak load under the changing dynamics of Idaho Power’s system
is significantly lower than previously assumed. This is primarily the result of increased
solar resources on the Company’s system pushing net peak load hours outside the
current DR program window. Therefore, the Company has filed a request for
modifications to its DR programs that, while making the programs more effective at
meeting system needs, may result in lower DR participation.
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Current Load Forecast Increases: While the change in peak load expectations
for 2023 through 2025 between the Second Amended 2019 IRP and the May 2021 L&R
analysis was relatively immaterial, based on updates the Company currently expects
2023 through 2025 peak load to be greater than anticipated in those prior analyses.
Migration into the Company’s service area exceeded prior forecasts, both during and after
the recession, as customer additions into the service area were approximately 30% higher
than prior expectations. In addition, there have been several industrial customers, both
existing and new, that have made a sufficient and significant binding investment and/or
interest indicating a commitment of locating or expanding operations in the Company’s
service area. These drivers predict that the Company’s peak capacity by 2023 will grow
faster than forecasted expectations used in both the second amended 2019 IRP and the
May 2021 L&R analysis.
Current L&R Balance Analysis: Since the Valmy study was completed in June
2021, the Company has continued to update the L&R balance analysis for the 2021 IRP
using the most currently available resource and load inputs. On the resource side, Idaho
Power has applied the adjusted transmission assumptions, as well as the LOLE and
ELCC methods described above. On the load side, Idaho Power has also included higher
load growth expectations. The resulting capacity deficiency of approximately 101 MW in
2023, 186 MW in 2024, and 311 MW in 2025 as presented in Table 1, clearly
demonstrates the need for the new capacity resource to meet those capacity deficits prior
to the addition of the Boardman to Hemingway transmission line in 2026.
While these estimates reflect Idaho Power’s best available information at the time
of this filing, the Company wishes to make the Commission aware of a recent
development that could ultimately increase the forecast capacity deficit beginning in 2023.
Idaho Power had previously contracted with Jackpot Solar, LLC (“Jackpot Solar”) for 120
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 12
MW of solar generation to become commercially operational by December 2022. The
energy contract with Jackpot Solar was reviewed and approved by the Commission by
Order No. 34515 issued in December 2019.9 On November 9, 2021, Jackpot Solar
informed Idaho Power that that global supply chain disruptions have raised concerns
regarding Jackpot Solar’s ability to achieve commercial opperation by the dates identified
in the approved agreement. Specifically, Jackpot Solar alleges that current global supply
chain disruptions brought on by the COVID 19 pandemic represents a force majeure
event as defined in the energy sales agreement, as its solar modual supplier will not meet
the supply provisions of the modual supply agreement. Idaho Power is currently in
discussions with Jackpot Solar, and it is unknown to the Company when, or if, the
associated 120 MW of solar generation will begin commercial operations. If the Jackpot
Solar project is delayed beyond summer 2023, or not built, Idaho Power will need
approximately 40 MW of incremental peak capacity to meet projected customer demands.
III. THE OREGON RESOURCE PROCUREMENT RULES ARE UNABLE TO TIMELY
ADDRESS DYNAMIC CIRCUMSTANCES

On February 9, 2010, the Commission initiated Case No. IPC-E-10-03 to establish
competitive bidding guidelines for the RFP process used when supply-side resources are
acquired by Idaho Power. On February 12, 2013, the Commission issued Order No.
32745 closing the case without establishing Idaho-specific resource procurement
guidelines, but rather directed Idaho Power to comply with RFP guidelines applicable in
its Oregon service area. According to Order No. 32745, the Company is required to
adhere the Oregon Competitive Bidding Guidelines should it commence an RFP process
for a new supply-side resource prior to the development of Idaho-specific RFP guidelines.
The referred to Oregon RFP Guidelines were later codified into the administrative rules

9 Case No. IPC-E-19-14.
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of the OPUC. OAR 860-089-0010 et. seq.. The OPUC Resource Procurement Rules
impose Competitive Bidding Requirements upon an electric utility for the “acquisition of a
resource or a contract for more than an aggregate of 80 megawatts and five years in
length,” among other requirements. OAR 860-089-0100(1)(a). There are certain
exceptions to the applicability of the OPUC Resource Procurement Rules, including the
one used for the Jackpot Solar contract: “There is a time-limited opportunity to acquire a
resource of unique value to the electric company’s customers.” OAR 860-089-0100(3)(b).
The OPUC Resource Procurement Rules also contain an exception to their applicability
based upon the OPUC acknowledging an alternative acquisition method in the utility’s
IRP. OAR 860-089-0100(3)(c).
Idaho Power asks that the Commission relieve Idaho Power of the IPUC’s
requirement to follow the OPUC Resource Procurement Rules in the state of Idaho. A
procurement process that complies with all requirements set forth by the OPUC Resource
Procurement Rules would not timely address the Company’s near-term resource needs
and would be unnecessarily costly. By Idaho Power’s estimates based upon the required
timelines from the OPUC Resource Procurement Rules, it could take a minimum of more
than 18 months from the initial stages of selection of the required independent evaluator
until the final step of the process where the OPUC approves the short list of bidders. See,
Attachment 1 hereto, incorporated herein by this reference. In fact, PacifiCorp’s 2017
wind resource RFP took nearly a year from PacifiCorp’s first filing to the OPUC’s decision
on the short list of bidders. See In the Matter of PacifiCorp, dba PacifiCorp Power,2017R
Request for Proposals, OPUC Docket No. UM 1845, Order No. 18-178 (May 23, 2018).
And even though it took nearly a year just to identify the short list of bidders, the RFP
process was considered “expedited” and the OPUC referred to it as “fast-moving.” Id. at
8, 10.
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PacifiCorp’s 2020 all-source RFP has taken even longer. PacifiCorp initiated the
RFP with an OPUC filing in February 2020 and now—over 20 months later—the OPUC
has yet to rule on the short list of bidders. See In the Matter of PacifiCorp d/b/a Pacific
Power Application for Approval of 2020 All-Source Request for Proposals, OPUC Docket
No. UM 2059. This timeframe does not take into account the time to actually engineer
and construct the generation resources, which can take up to another two years to
complete.
PacifiCorp also recently submitted its initial OPUC filing for its 2022 all source RFP.
See In the Matter of PacifiCorp d/b/a Pacific Power Application for Approval of 2022 All-
Source Request for Proposals, OPUC Docket No. UM 2159. PacifiCorp’s initially
proposed schedule called for submission of its final shortlist by May 2022, eight months
after the initial filing. OPUC Staff referred to the proposed schedule as “aggressive” and
claimed that the schedule did not comply with the OPUC’s rules. See In the Matter of
PacifiCorp d/b/a Pacific Power Application for Approval of 2022 All-Source Request for
Proposals, OPUC Docket No. UM 2159, Order No. 21-351, App’x A at 5 (Oct. 25, 2021).
In response, PacifiCorp modified the schedule to include 80 more days on the front end
before the RFP may be approved by the OPUC and over 200 more days for bidders to
prepare their bids. Under the now extended schedule, PacifiCorp will not even issue the
RFP until April 1, 2022—seven months after the initial filing—and the RFP process will
not conclude until May 2023—more than 19 months after PacifiCorp’s initial OPUC filing.
Portland General Electric Company (PGE) also recently initiated the OPUC RFP
process with a filing in April 2021. In the Matter of Portland General Electric Company
Application for Approval of Independent Evaluator for 2021 All Source RFP, OPUC
Docket No. UM 2166. Under the approved schedule, PGE anticipates issuing the RFP in
December 2021—more than seven months after initiating the OPUC process—and PGE
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anticipates submitting its final shortlist in June 2022—more than a year after initiating the
OPUC process. In the Matter of Portland General Electric Company Application for
Approval of Independent Evaluator for 2021 All Source RFP, OPUC Docket No. UM 2166,
Schedule for Post IE Selection (August 3, 2021).
An RFP process that takes over 12-18 months, in addition to the time to go from
an approved RFP shortlist through negotiations, engineering, and construction, is clearly
not practical in the current dynamic, rapidly changing environment, as evidenced by the
changes in the transmission market conditions, customer growth, and corresponding
resource needs between the 2019 and 2021 IRPs. The resource needs of the Company
and its customers emerge with such urgency, such as the present capacity deficits
identified in 2023, 2024, and 2025, that the Oregon Resource Procurement Rules and
process is not viable if the Company is to reliably serve customers. Concurrent with this
Application, Idaho Power will file a request with the OPUC to waive the applicability of the
OPUC Resource Procurement Rules to Idaho Power in its Oregon jurisdiction for the
required resource acquisitions discussed herein for 2023, 2024, and 2025.
Idaho Power is also concerned that the OPUC Resource Procurement Rules do
not align with the state of Idaho’s system of public utility regulation. In fact, Idaho Power
objected to the adoption of the Competitive Bidding Guidelines, the precursor to the
OPUC Resource Procurement Rules. Under the state of Idaho’s chosen system of public
utility regulation, customers benefit in the long-term when the utility is responsible for the
obligation to reliably serve customers within its certificated service area, subject to IPUC
oversight over, among other things, capacity resource acquisition. Additionally, Idaho
Power believes the OPUC Resource Procurement Rules are very inflexible, unrealistic as
to timing, and introduce a bias against the acquisition of utility-owned resources into
generation resource procurements, favoring the standalone per-MWh price of a fixed term
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contract (typically well short of the useful life of the asset) over reliability, long-term
customer impacts, and the financial viability of the utility. The OPUC Resource
Procurement Rules are designed to favor least cost PPA resources that are not the
optimal resources operationally or for a utility such as Idaho Power that already holds a
proportionately large amount of PPAs. By contrast, a procurement process for resources
that takes into account not only price, but also reliability, system operation, long-term
operation and maintenance of facilities, financial viability of the utility, economic dispatch,
environmental policies, real-time needs and load growth, and other attributes, is one that
benefits customers, developers, and the utility.
IV. IDAHO POWER’S RFP PROCESS, AND THE MANDATORY CPCN, CREATE AN
IDEAL PROCESS AND PROTECTIONS

Idaho Power seeks authority to proceed with supply-side resource procurements
designed to meet the identified capacity deficits in 2023, 2024, and 2025 - prior to the
time that the B2H transmission line is expected to be operational - in much the same
manner that all prior supply-side resources have been procured and approved by the
IPUC for Idaho Power. For all of those resource acquisitions, the Company will conduct
an RFP to obtain competitive pricing and identify the best resource to ensure adequate,
reliable, and fair-priced service to its customers, and will then bring that resource to the
IPUC for its independent evaluation and determination as to whether acquisition of that
resource is consistent with the Public Convenience and Necessity under applicable
standards. Idaho Code § 61-526.10
As previously stated, Idaho Power has initiated an RFP for a dispatchable capacity
resource up to 80 MW in order to meet the initially identified 78 MW capacity deficit in

10 Notably, the state of Oregon does not have a corresponding requirement for the issuance of a CPCN for supply-
side or generation resources like Idaho.
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2023.11 In the Spring of 2021, recognizing the urgency of the capacity deficit, the
Company assembled an interdisciplinary team to develop and process an RFP for 2023
peak capacity resources (“RFP evaluation team”). The Company also retained a
consultant, Black & Veatch Management Consulting, LLC, to assist the RFP evaluation
team with development of the RFP and to provide guidance and evaluation support of the
Company’s RFP process. The RFP evaluation team developed detailed criteria and a
methodology for evaluating both price and qualitative attributes of a proposed resource.
On June 30, 2021, the RFP evaluation team issued a formal request for competitive
proposals for up to 80 MW of electric generating capacity. The RFP document is attached
hereto as Attachment 2 and incorporated herein by this reference. The RFP document
sets forth the process and procedure utilized to solicit and evaluate the proposals as to
meeting the Company’s and its customers’ present needs.
A public Notice of Intent was released on May 20, 2021, to industry developers
and media outlets and was posted to Idaho Power’s website noticing Idaho Power’s intent
to release the RFP. Interested developers responded with an Intent to Bid by June 11,
2021. The “2021 All Source Request for Proposals for Peak Capacity Resources” was
solicited directly to 38 Developers. The RFP solicitation identified the purpose, key
product specifications, proposal format, qualitative and quantitative evaluation criteria,
template draft form term sheet (“Build Transfer Agreement” or “BTA”), technical
specifications, and additional requirements necessary to submit a qualifying proposal.
The RFP solicitation also focused on the importance of having a project in-service by
June 2023. Thirteen proposals were submitted by third-party developers on August 11,
2021. The RFP evaluation process assesses both price and non-price attributes. Price

11 The Oregon Procurement Rules do not apply to resources below 80 MW.
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 18
attributes were weighted at 60 percent of the total valuation and non-price attributes were
given a 40 percent weighting.
Once a winning bidder is selected and contractual documents are executed, the
Company, as it has done in the past, will bring the proposed generation acquisition to the
Commission for is review in a CPCN proceeding to establish both the need and expected
cost of the procurement. The required CPCN process as well as the subsequent rate
making proceedings will provide considerable oversight of the procurement process, and
ensure low cost, reliable resource acquisitions for customers - as it has done for the
Company’s more than 100-year history.
V. UTILITY OWNERSHIP OF SUPPLY-SIDE CAPACITY RESOURES
IS BENEFICIAL TO CUSTOMERS, THE UTILITY, AND IDAHO’S
REGULATED UTIILITY MODEL
Idaho’s Regulatory Mandate and Model: Idaho Power has an obligation to
provide adequate, efficient, just, and reasonable service on a nondiscriminatory basis to
all those that request it within its certificated service area. Idaho Code §§ 61-302, 61-
315, 61-507. As part of the regulatory compact, Idaho Power must serve all customers
in the service aera, in exchange for its exclusive right to provide retail electric service
within the service area. The compact provides Idaho Power the opportunity to earn a
reasonable return by investing capital into the resources and systems necessary to
perform its service obligation. At the same time, the Commission has oversight of the
provision of that service and must assure that the rates Idaho Power charges its
customers and that the rules and regulations by which it provides service are just,
reasonable, nondiscriminatory, and non-preferential. Idaho Code §§ 61-501, 61-502, 61-
503, 61-507, 61-508.
The Company must at times acquire additional resources to meet the identified
capacity deficits on its system, regardless of when those deficits occur and with whatever
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 19
urgency they arise, in order to comply with its continuing obligation to serve customers.
While the IRP provides insight into resource procurement, it is a biennial process, and
circumstances change in the interim that can make resource procurement for reliable
load-service more urgent, as is the present case. Additionally, those resource
acquisitions must take into account the benefits of utility ownership and operation of
resources, and not be premised solely on short-term/least-cost, which can have
catastrophic outcomes for electric service and the public. The Commission has oversight
of those procurements, to ensure the company is prudently investing its capital. With only
limited exception, these resources should be Company-owned, as Idaho Power must
satisfy its obligation to provide its customers with reliable service and at the same time
maintain its financial health to remain a viable, going-concern, regulated entity in the state
of Idaho’s chosen and mandated system of regulated public utility service.
The Commission has the express authority to order a utility to build new structures,
or to upgrade and/or improve existing plant and structures, in order to secure adequate
service or facilities. Idaho’s applicable statute states:
Whenever the commission, after a hearing had upon its own
motion or upon complaint, shall find that additions,
extensions, repairs or improvements to or changes in the
existing plant, scales, equipment, apparatus, facilities or other
physical property of any public utility . . . ought reasonably to
be made, or that a new structure or structures should be
erected, to promote the security or convenience of its
employees or the public, or in any other way to secure
adequate service or facilities, the commission shall make and
serve an order directing such additions, extensions, repairs,
improvements, or changes be made or such structure or
structures be erected in the manner and within the time
specified in said order.

Idaho Code § 61-508.

A Certificate of Public Convenience and Necessity represents the exercise by the
Commission of foundational authority and principles that are necessary in Idaho’s system
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 20
of permitting regulated, vertically integrated public utilities to exist and to provide
necessary services to the public. Certificates have been utilized in various ways from the
time that Idaho’s statutory system of public utility regulation was enacted by the
Legislature in 1913, Idaho Code § 61-101, et seq., to the present time. After over 100
years of legislative enactments, Commission orders, and Idaho Supreme Court reviews,
the Certificate remains the embodiment of the Commission’s fundamental power and
authority to, at the most basic level, authorize and direct a public utility to serve in the
public interest. See Idaho Power & Light Co. v. Bloomquist et al., 26 Idaho 222, 141
P.1083 (1914); Idaho Op. Atty. Gen. No. 87-2, 1987 WL 247587 (Idaho A.G.).
In the broadest sense, a Certificate allows a company that meets the definition of
a “public utility” pursuant to Idaho Code § 61-129 to exclusively provide its service to the
public in a specified geographic region, its service area. It is a codified part of the
“regulatory compact” whereby the utility takes on the exclusive obligation/right to serve
all those requesting service within its service area and, correspondingly, submits itself to
the rate and service quality regulation of the Commission. In a more literal sense, a
Certificate from the Commission is required for the construction or extension of a line,
plant, or system by any street railroad, gas, electrical, telephone, or water corporation.
Idaho Code § 61-526. § 61-526 also provides that “if public convenience and necessity
does not require or will require such construction or extension [of a line, plant, or system]
the commission . . . may, after hearing, make such order and prescribe such terms and
conditions for the locating or type of line, plant or system affected as to it may seem just
and reasonable . . . .” A CPCN is required for the utility to construct a new generation
resource or plant but is not required to increase the capacity of existing generating
facilities. Id. The required CPCN provides a broad mechanism for considerable
regulatory oversight into the procurement process for a generation or supply-side
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 21
resource - one that is fundamental to our system of regulation and has historically in Idaho
been exercised for the benefit of both the utility customers and the utility.
Idaho’s system of regulation is based upon the core concept that state regulation
of a single service provider in the public interest is better than, and preferrable to, an
environment of competition and competitive service providers. See Idaho Power & Light
Co. v. Bloomquist et al., 26 Idaho 222, 141 P.1083 (1914) (“Bloomquist”). The positive
virtues of this system of regulation have been repeatedly confirmed. Idaho’s public utility
laws were enacted in 1913. A seminal case, Bloomquist, in 1914 considered the
constitutionality of the state’s public utility laws and held that they were consistent with
both the state and federal constitutions. Bloomquist, 26 Idaho 222, 141 P. at 1097. In its
decision upholding the enactment of the public utility laws in the state of Idaho as
constitutional, the Idaho Supreme Court stated,
There is nothing in the Constitution that prohibits the
Legislature from enacting laws prohibiting competition
between public utility corporations, and the Legislature of this
state no doubt concluded that a business like that of
transmitting electricity through the streets of the city and
furnishing light and power to the people must be transacted
by a regulated monopoly, and that free competition between
as many companies or as many persons as might desire to
put up wires in the streets is impracticable and not for the best
interests of the people.

Bloomquist, 26 Idaho 222, 141 P. at 1088. The Court analyzes and discusses the
regulation of a single service provider, as a monopoly, by a state commission as a lawful,
valid, and preferred substitution for the control of public utilities by competition. The Court
in its discussion refers to several quotes citing the benefits of a regulated monopoly
environment over a competitive environment, stating “In our opinion, the government,
which properly assumes to prescribe reasonable rates and compel adequate service by
public utilities, should also protect such utilities and the public from unwise and useless
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 22
competition, and the wasteful investment of capital in the unnecessary duplication of
plants.” Bloomquist, 26 Idaho 222, 141 P. at 1089 (quoting Forty-First Report of the
Georgia Railroad Commission). The Court stated,
The regulating of rates and compelling proper service is for
the purpose of obtaining rates and service as nearly equitable
as possible to both the consumer and the utility corporation,
and competition can have no other effect than to destroy the
very groundwork of regulation, and therefore competition may
be regulated by a commission under laws enacted by the
Legislature.

Bloomquist, 26 Idaho 22, 141 P. at 1089. In addressing Idaho’s public utility laws in
particular the Court stated,
Under the act in question, the commission is given power to
fix the rate absolutely, and neither of the competing
companies can charge more or less than the rate fixed. Under
those conditions competition can amount to nothing, and the
only reason for having two corporations covering the same
field is to secure satisfactory service. But, under our utilities
act, the commission is the arbitrator in regard to all matter of
service. If the utility corporation is not giving satisfactory
service, the commission has absolute power to compel it to
do so. If its facilities are such that the cost of operation is
unnecessarily high, the commission can enforce the
installation of proper machinery and facilities and a
correspondingly proper charge for the commodity furnished.
The commission may force the public utility to keep abreast of
the times in the employment of proper machinery and
appliances in their plants and in the economic conduct of its
business. If wasteful methods are indulged in, the public utility
must bear the loss, and not the consumer. Thus the reason
for competition is entirely taken away.

Bloomquist, 26 Idaho 222, 141 P. at 1089.
The state of Idaho and Idaho Power’s customers are better served by the
traditional, rate-based, vertically integrated single service provider model, as discussed
and held lawful in Bloomquist, than the various incarnations of competition and eroded
monopolies subjected to undue competition by modern forces. By design, Idaho’s chosen
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 23
system of regulation is set up to protect the utility service provider from competition in its
certificated service area, whilst subject to Commission oversight, and not to promote
competitive forces against the utility such that the utility eventually erodes and ceases to
be viable. Instead, Idaho’s long-standing, successful, and lawful system of utility
regulation relies upon and needs financially healthy utilities that are able to rate base
investment that is used and useful in the public service and have an opportunity to earn
a return on that investment at a regulated rate.
The modern tools used in attempts to force deregulation onto state jurisdictions
that have chosen to retain the traditional vertically integrated, state regulated service
providers, such as the Public Utility Regulatory Policies Act of 1978 (“PURPA”) and its
unbounded mandatory purchase Power Purchase Agreements (“PPAs”), the Federal
Energy Regulatory Commission’s (“FERC”) promotion of Regional Transmission
Organizations (“RTO”) and Independent System Operator (“ISO”) operational
environments, anticompetitive tax credit policy for renewable energy procurement, and
competitive procurement rules and regulations specifically designed to “remove the
utility’s competitive advantage” (or in other words to give competitive advantage to non-
utility, third-party generation or PPAs with incentives mis-aligned with customer benefit).
While some aspects of these policies can, and have, resulted in positive outcomes for
utilities and the customers they serve, certain policy aspects, if not properly implemented,
have the potential to create an environment that erodes the financial health and viability
of the regulated utility, and the ability of a utility to reliably serve customers, and in turn
can erode the state’s ability to protect customers through its regulation of the public utility.
These tools of deregulation, promoting a proliferation of third-party, PPA
generation resources creates an environment where the public utility is no longer
protected from competition in its certificated service area, but must still be subjected to
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 24
the economic regulation of the state and face disadvantages in the marketplace. In
essence, the model gravitates toward defaulting the utility and its customers into less
useful, more expensive, and operationally difficult PPA arrangements that undermine the
regulatory environment while allowing non-utility, third party generators - who have no
obligation to customers and mis-aligned incentives - to walk away with profits and to
consider their own bottom line, as opposed to reliable service to electric utility customers.
Non-utility generation or plant such as PPA or similar arrangements may have a
viable and lawful place amongst a public utility’s diverse portfolio of resources as a
seemingly low-cost dump of energy onto the system. However, PPAs are of very limited
value to meet capacity deficits when the generation generally cannot be controlled,
dispatched, curtailed, available, or economically managed for the benefit of customers
and the company in the same manner as utility-owned generation. PPAs may have an
initial appearance of being a lower-cost generation resource alternative, but this can be
false in the context of full utility operations. If one looks beyond just the price per MW in
the written contract and looks at how useful the PPAs generation is to the system and the
entirety of the financial costs to customers in the long run, their appeal diminishes rapidly
in many contexts. As the amount of PPA generation resources in a public utility’s portfolio
increases, a number of issues arise: integration of the power becomes more difficult and
costly; the utility loses maintenance and control over the facility and its condition; the utility
typically loses the generation resource at a specified contract date short of the useful life
of the plant; the utility is relegated to the terms of the contract; curtailment of the facility
is non-existent, expensive, or fraught with potential legal challenges; and cyber and
physical security oversight of the facility is diminished. Further, it starts to undermine the
regulated service provider model, and acts in effect as a tool for deregulation.
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 25
During the early 1990’s, many states, including Idaho, considered the enactment
of legislation to deregulate the electric utility industry. Deregulation was considered and
rejected in Idaho primarily based upon the success of the vertically integrated, state-
regulated service provider system of regulation, the corresponding regulatory compact,
and the state commission-based system of regulation that has resulted in Idaho electric
customers consistently enjoying some of the lowest cost and most reliable electric service
in the nation. This is bolstered by the additional security and customer protection afforded
by the regulator maintaining oversight of the utility, as opposed to the unregulated, third-
party who is not concerned with, nor answers to, customers or the regulator and is only
concerned with profits.
In fact, many jurisdictions that went down the road of enacting deregulation
legislation, particularly in the east, employed initial price caps to protect customers from
inflated electric rates as part of the package. However, as time would tell, once those
initial price caps expired those jurisdictions experienced very large price increases to
customers, in many cases far exceeding those in regulated jurisdictions and with no
recourse to the regulators. More recently, it was reported that since 2004 deregulated
Texas electricity residential customers paid $28 billion more for their power than they
would have paid at the rates charged to the customers of the state’s traditional utilities.12
From 2004 through 2019 that the annual rate for electricity from Texas’s traditional utilities
was 8 percent lower, on average, than the nationwide average rate, while at the same
time the rates of de-regulated retail providers averaged 13 percent higher than the
nationwide rate.13

12 Texas Electric Bills Were $28 Billion Higher Under Deregulation, Tim McGinty and Scott Patterson, Wall Street
Journal, Feb. 24, 2021.
13 Id.
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 26
The Texas Model is a Cautionary Tale: Recent system reliability events in Texas
offer a cautionary tale regarding the risks associated with a restructured electric
generation sector.14 In 1996, the Electric Reliability Council of Texas (“ERCOT”) was
established as the Independent System Operator (“ISO”) in the state of Texas
(approximately 10% of Texas is not served by ERCOT), as provided for in Senate Bill
373. Subsequently in 2002, vertically integrated electric utilities were required to
restructure by separating their generation, transmission, and distribution functions into
separate entities. One of the goals of this restructuring was to create competition in the
wholesale electric energy market. While restructuring has certainly accomplished that
goal, it has also changed the financial and regulatory model that drives investment in
generation resources in the state. Under the vertically integrated utility model that existed
in Texas prior to 2002, investor -owned utilities had a financial incentive to invest in and
maintain generation resources to meet their obligation to provide safe and reliable service
to customers. In exchange for that obligation to serve, investor-owned utilities were
provided an opportunity to earn a reasonable financial return for shareowners. Ultimately,
the state regulator, the Public Utility Commission of Texas (“PUCT”), determined the
prudence of those investments. Under a restructured market, independent generation
operators do not have the same regulatory oversight or financial incentives, which may
have led to underinvestment in the Texas generation fleet, and thereby compromising
system reliability.
In February 2021, much of the ERCOT system was being impacted by extreme
cold weather associated with Winter Storm Uri, which resulted in prolonged power

14 Source information for this section: The Timeline and Events of the February 2021 Texas Electric Grid Blackouts
A report by a committee of faculty and staff at The University of Texas at Austin July 2021, attached hereto as
Attachment 3, and incorporated herein by this reference.

APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 27
outages during the week of February 14. More than 4.5 million homes and business lost
power during this event, and at least 210 people died as a direct result of those outages.
The outages occurred despite ERCOT’s best efforts in the days prior to deploy operating
reserves, load shedding, and other conservation measures.
By February 15, 2021, ERCOT experienced generation outages of over 50,000
MW, or approximately 40 percent of total ERCOT nameplate generating capacity. Of
those outages, approximately 30,000 MW, representing 167 generating units,
experienced weather-related outages. These weather-related issues included, but were
not limited to, wind turbine icing, frozen water intakes, and freezing of other general
equipment.
The financial fallout from this event was also severe. The financial pain caused by
these events impacted all categories of market participants, including wholesale energy
suppliers, retail energy suppliers, and retail customers. Wholesale energy prices reached
$9,000/MWh. Extremely high prices led to unpaid power payments within ERCOT of
nearly $3 billion by May 2021. Retail providers experienced negative financial impacts in
the billions of dollars, with several bankruptcies occurring in the aftermath.
It is important to note, all of the operational and financial chaos brought on by this
extreme weather event occurred with relatively little transparency or oversight by the
PUCT, even though Texas law requires the PUCT to analyze and report on the
preparedness of generating units to operate during extreme weather events. The last
such report was filed with the legislature in 2012. The reduced regulatory oversight and
changed business model that exists in Texas is a clear reminder of the risks that exist in
deregulated electric markets. Deregulated power generators serving ERCOT did not
have the incentive to invest in systems to address extreme weather events, as
presumably they were single-mindedly focused on maximizing profits instead of providing
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 28
reliable service to customers in Texas. These tragic events demonstrate the that “invisible
hand” of the free market doesn’t work well in extreme situations because the economic
signals don’t last long enough to incent the investments that are necessary to ensure
reliability during those events.
Third Party-Owned Assets Have an Imputed Debt Cost to the Utility and
Ultimately to Customers: A PPA brings added costs beyond the direct contract costs
for the purchased energy in the form of imputed debt adjustments made by credit rating
agencies. When Idaho Power enters into a PPA for third-party supply of energy, credit
ratings agencies like Standard and Poor’s (S&P), Fitch, and Moody’s view such
agreements as creating fixed debt-like obligations given the lengthy stream of payment
obligations by the utility. In light of this view, credit agencies make what are called
“imputed debt adjustments” to Idaho Power’s credit metrics to reflect the credit exposure
that exists with PPAs. Ultimately, these imputed debt adjustments amount to real costs
that are passed on to Idaho Power’s customers through the rate-making process over
time, but not visible in the PPA.15
Imputed debt adjustment calculations can vary depending upon the level of
perceived credit exposure associated with a PPA, typically as apportioned between Idaho
Power and its customers based on the certainty of rate recovery provided for by applicable
law or regulatory assurances. The adjustment process begins with a calculation of the
net present value (“NPV”) of the outstanding contract payments over the remaining life of
a PPA. The NPV value is then adjusted for the level of perceived credit exposure
associated with a PPA. Depending on the perceived credit exposure of a PPA, the credit

15 Standard & Poor's Methodology For Imputing Debt For U.S. Utilities' Power Purchase Agreements Primary
Credit Analyst: David Bodek, Secondary Credit Analysts: Richard W Cortright, Jr. and Solomon B Samson, May 7,
2007, attached hereto as Attachment 4 and incorporated herein by this reference.

APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 29
rating agency may apply risk factors that typically range from 0 to 50 percent – but can
be as high as 100 percent.16
Ultimately, the result of the imputed debt applied by the rating agencies will be
downgrades in credit ratings unless there is some type of mitigation to offset the imputed
debt, such as additional equity. For example, in June 2021 Moody’s put Idaho Power on
negative watch, which is the first step towards a down grade in Moody’s credit ratings for
the company. There are many factors that impact credit ratings, and the imputed debt is
one of those factors.
In comparing the cost of a PPA to utility ownership it is important to consider these
imputed debt adjustments and their resulting cost. To illustrate the financial impact of the
imputed debt adjustment, the Company has prepared the following illustrative example
using the following financial input assumptions:
• Current authorized return on equity = 10%
• Incremental Cost of debt = 4%
• Incremental composite tax rate 25.74%
Any PPA will cause rating agencies to impute debt on Idaho Power’s balance sheet
based on the estimated present value of the PPA resource payments discounted at the
incremental cost of debt and adjusted by a risk factor. In order to maintain an assumed
50/50 capitalization structure, the imputed debt will require an equal amount of equity to
be issued to maintain the current debt equity ratio.
Assume the Company signs a PPA that would result in imputed debt of $100 million
on the Company’s balance sheet based on the estimated payments and the incremental
debt rate and risk factor. In order to maintain a 50/50 debt/equity ratio, the company must

16 Id.

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issue $100 million of equity. The company would use the $100 million proceeds of the
equity issuance for ongoing capital projects.
As a result, Idaho Power customers would now pay the monthly/annual cost of the
PPA plus the cost of the equity issuance due to the PPA ($100 million*10%) = $10 million
plus a gross up for tax ($10 million* (1/(1-0.2574))) = $13.466 million.
As mentioned earlier, the Company would use the funds from the equity issuance
to cover the cost for the on-going capital projects needed to reliably serve Idaho Power
customers. However, had the Company financed those same capital projects with a
blend of 50% debt and 50% equity, the cost to customers would be $100 million *
(4%*50%+10%*50%) = $7 million plus a gross up for tax ($7 million *(1/(1-0.2574))) =
$9.426 million.
Therefore, in this example, customers would be paying an additional $4.04 million
($13.4662M - $9.426M) per year beyond the PPA price due to the imputed debt
adjustment. Consequently, because of imputed debt, when evaluating the relative cost
of a PPA, regulatory bodies should consider the less-visible added annual customer cost
of $40.4 for every $1,000 of imputed debt related to the PPA.
PPAs May Bring Other Hidden Harms to Customers: Most PPAs are much
shorter in duration than the physical and economic life of the underlying asset and
generally start with a low and attractive cost in the first year but increase every year
thereafter. At the end of the PPA Idaho Power must procure a new resource to cover the
expiring PPA or renew the PPA at the then current market prices, which may be much
higher. The owner of the PPA has the physical asset that hedges the likely increases in
market prices and then passes along to customers the higher market-based costs. When
Idaho Power owns an asset, customers benefit from locking in the fixed costs over the
full life of the underlying asset, and as market prices go up, customers pay less on a non-
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 31
levelized basis than they did the first year the resources was in service due to
depreciation. Customers also benefit by the assurance that Idaho Power will diligently
maintain the asset, potentially extending the use on behalf of customers beyond the
expected physical life.
Idaho Power recently performed an analysis using information from our current
RFP for an 80 MW resource which compared the lowest PPA cost for solar from the
bidders including the renewing of the PPA to match the life of the asset of 35 years as
well as adding the impact of imputed debt compared to an ownership option, the company
could save customers over $175 million over the 35-year life of the asset and over $30
million customer savings on a net present value basis. See Attachment 5 hereto,
incorporated herein by this reference.
Risk of the PPA Failing to Produce or the Resource Not Being Built: Another
cost to customers is when a contracted PPA does not actually show up due to
circumstances that the Company cannot control, as appears to be the case with Jackpot
Solar and its PPA for 120 MW of solar scheduled to be online by December 2022 prior to
the currently identified capacity deficits. When the Company relies on a PPA and includes
it in its IRPs for a number of years, the cost to replace such a resource without the
advantage of the time that the developer had to build-out the resource, can be much more
costly and it can create significant operational risks and constraints.
Idaho Power’s Request Benefits the Utility and Customers: Once again, we
are at a crossroads where the regulatory compact is being challenged , only this time it is
not in the form of proposed legislation - it is in the form of non-utility ownership of
generation assets, promoted by mechanisms such as PURPA, disproportionate tax
incentives and practices, and state-mandated resource procurement rules designed to
advantage non-utility generation that act to erode the financial viability of vertically
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 32
integrated utilities. Ultimately this impacts customers through higher long-term costs and
the potential erosion of system reliability. As the Company rapidly transitions from being
resource sufficient to the identified capacity deficits in 2023, 2024, and 2025, Idaho Power
asks the Commission to recognize and uphold the long-standing and successful
regulatory policy of this state as originally set forth in Bloomquist, acknowledging the
required protection of both the utility and customers from the destructive forces of this
emerging form of deregulation , and setting forth regulatory policy acknowledging the
customer benefits of utility ownership of supply-side capacity resources under the
regulated utility business model.
VI. COMMUNICATIONS AND SERVICE OF PLEADINGS
Communications and service of pleadings with reference to this Application should
be sent to the following:
Donovan E. Walker Tim Tatum
Lead Counsel Vice President, Regulatory Affairs
Idaho Power Company Idaho Power Company
1221 West Idaho Street (83702) 1221 West Idaho Street (83702)
P.O. Box 70 P.O. Box 70
Boise, Idaho 83707 Boise, Idaho 83707
[e-mail] [e-mail]
[e-mail]

VII. CONCLUSION
Idaho Power has been in a resource sufficient position for almost a decade since
the addition of the Langley Gulch combined-cycle, natural gas-fired power plant, in 2012.
Over the course of approximately two months - from the March 2021 acknowledgement
of the 2019 IRP to the revised Load and Resource Balance in May of 2021 - Idaho Power
rapidly identified near term capacity deficiencies starting in summer 2023 and growing
through 2024 and 2025 until the B2H 500 kilovolt transmission line is expected to be
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 33
operational in 2026. These rapidly emerging capacity deficits are driven by an increasing
population and associated emergent demands in the Company’s service area; third-party
transmission constraints; changes to the assumptions in the L&R balance regarding
available transmission capacity following the retirement of coal plants; the unavailability
of import transmission capacity on the market; planning margin adjustments associated
with incorporating LOLE and ELCC planning methodologies; and the potential diminishing
demand response resource and solar effectiveness during peak and critical times.
Idaho Power must meet its obligation to reliably serve customers and must meet
those capacity deficits to prevent wide-spread outages in its service area. The Company
must do this in a rapidly changing and dynamic environment, with an already short turn-
around time to meet deficits in 2023 exacerbated by an environment of global supply
chain disruption and issues preventing the timely construction of new resources as well
as previously contracted PPA generation from coming online in a timely manner.
Idaho has a long, successful history of state commission regulation of public utility
service providers, focused on the public interest and Commission oversight. The
Commission’s regulation, particularly through the required CPCN and rate-making
processes, provides sufficient protection and has benefit for both customers and the
Company, and has served Idaho customers and Idaho Power very well for over 100 years.
For the reasons cited above in this Application, Idaho Power asks the Commission for
authority to move forward expeditiously with the procurement of capacity resources
needed to provide adequate, reliable, and fair-priced service to customers to meet the
identified capacity deficits in 2023, 2024, and 2025.
VIII. REQUEST FOR RELIEF
Idaho Power respectfully requests that the Commission issue an order authorizing
the Company to move forward with the procurement of dispatchable resources needed
APPLICATION FOR AUTHORITY TO PROCEED WITH RESOURCE PROCUREMENTS - 34
to secure adequate, reliable, and fair-priced service to customers. More specifically,
Idaho Power requests that the Commission issue an order: (1) eliminating the IPUC
requirement to comply with OPUC Resource Procurement Rules; (2) authorizing Idaho
Power to move forward expeditiously with resource procurements to meet identified
generation resource needs in 2023, 2024, and 2025; and (3) affirming support and the
continuation of the state of Idaho’s system of public utility regulation under which the
interests of customers are best served by a vertically integrated electric utility maintaining
ownership of the necessary generation, transmission and distribution utility functions, with
limited exceptions.
Idaho Power requests that the Commission issue Notice of this Application, set an
intervention deadline, and convene a prehearing conference in this matter at its earliest
convenience to establish a proper procedure to expedite the orderly conduct and
disposition of this proceeding. RP 211.
DATED at Boise, Idaho this 3rd day of December 2021.

DONOVAN E. WALKER
Attorney for Idaho Power Company

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-41

IDAHO POWER COMPANY

ATTACHMENT 1

Timeline for Oregon Competitive Bidding Rules
https://secure.sos.state.or.us/oard/displayDivisionRules.action?selectedDivision=4519

Notes:
• This estimate is based on PGE experience for utility process/evaluation in conjunction with the
Final Rules.
• Scenarios assume additional 60 days to work with stakeholder’s pre-issuance of IE RFP
• Work with IE assumes 30 days
• Regulatory RFP process begins with issuing the draft RFP, rules allow for a 30-day extension
• RFP Process is from issuance through final short list acknowledgement, at which point
negotiations could begin

Notes:
OAR 860-089-200(1) - Prior to issuing an RFP, an electric company must engage the services of an IE to
oversee the competitive bidding process. The electric company must notify all parties to the electric
company’s most recent general rate case, RFP, and IRP dockets of its need for an IE, and solicit input
from these parties and interested persons regarding potential IE candidates.

Notes:
• OAR 860-089-250(1) - initial draft provided to all parties and interested persons in the electric
company's most recent general rate case, RFP, IE selection, and IRP dockets.
• OAR 860-089-250(6) - The Commission will generally issue a decision approving or disapproving
the draft RFP within 80 days after the draft RFP is filed. An electric company may request an
alternative review period when it files the draft RFP for approval including a request for
expedited review upon a showing of good cause. Any person may request an extension of the
review period of up to 30 days upon a showing of good cause.

Notes:
OAR 860-089-350(1) Prior to the opening of bidding on an approved RFP, the electric company must file
with the Commission and submit to the IE, for review and comment, a detailed score for any benchmark
resource with supporting cost information, any transmission arrangements, and all other information
necessary to score the benchmark resource. The electric company must apply the same assumptions
and bid scoring and evaluation criteria to the benchmark bid that are used to score other bids.

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-41

IDAHO POWER COMPANY

ATTACHMENT 2

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-41

IDAHO POWER COMPANY

ATTACHMENT 3

[Type here]

The Timeline and
Events of the February
2021 Texas Electric
Grid Blackouts
July 2021

1

COMMITTEE CHAIRS
Carey W. King, Research Scientist, Assistant Director, Energy Institute
Josh D. Rhodes, Research Associate, Department of Mechanical Engineering
Jay Zarnikau, Research Fellow, Department of Economics

COMMITTEE MEMBERS
Contributing Authors
Ning Lin, Chief Economist, Bureau of Economic Geology

Additional Members
Erhan Kutanoglu, Associate Professor, Operations Research and Industrial Engineering,
Department of Mechanical Engineering
Benjamin Leibowicz, Assistant Professor, Operations Research and Industrial Engineering,
Department of Mechanical Engineering
Dev Niyogi, Professor, Department of Geological Sciences; Professor, Department of Civil,
Architectural, and Environmental Engineering
Varun Rai, Professor, LBJ School of Public Affairs; Director, Energy Institute
Surya Santoso, Professor, Department of Electrical and Computer Engineering
David Spence, Baker Botts Chair in Law, School of Law; Professor, Department of
Business, Government, and Society
Stathis Tompaidis, Professor, Department of Information, Risk and Operations
Management, and by courtesy, Department of Finance
Hao Zhu, Assistant Professor, Department of Electrical and Computer Engineering

OTHER CONTRIBUTORS
Erik Funkhouser, Director for Research Coordination and Partnerships, Energy Institute
Brent Austgen, Graduate Research Assistant, Operations Research and Industrial
Engineering Program, Department of Mechanical Engineering
The Timeline and Events of
the February 2021 Texas
Electric Grid Blackouts
A report by a committee of faculty and staff at The
University of Texas at Austin
July 2021

2
Table of Contents
Executive Summary .......................................................................................... 7
1. Introduction ............................................................................................. 12
1.1 Objective ................................................................................................................ 12
1.2. Energy in Texas ..................................................................................................... 13
2. Timeline of Events Related to February 2021 ERCOT Blackouts . 15
2.1. ERCOT’s Winter 2020/2021 SARA report ............................................................. 15
2.2. The Week Before Winter Storm Uri ...................................................................... 18
2.2.1. Weather and Load Forecasts and Alerts ................................................... 18
2.2.2. Recall of Power Plant Outages for Maintenance ...................................... 24
2.3. The Week of Winter Storm Uri (February 13-20, 2021) ....................................... 25
2.4. Generation Outages (Timeline) ............................................................................ 28
2.4.1. Generator Temperature Ratings Relative to Experienced Temperatures . 34
2.5. Load Curtailment, Requested and Achieved ........................................................ 36
2.5.1. Involuntary Load Shed .............................................................................. 36
2.5.2. Response to High Prices ........................................................................... 37
2.5.3. Deployment of Load Resources ................................................................ 38
2.5.4. ERS Program ............................................................................................. 38
2.5.5. Automated Load Shedding via Under-frequency Relays .......................... 39
2.5.6. Deployment of Various Demand Response (DR) Programs by Load-
Serving Entities ................................................................................................... 40
2.5.7. Aggregate Levels of Demand Response ................................................... 41
2.6. Natural Gas and Operations during February 2021 .............................................. 41
2.6.1. Natural Gas Production ............................................................................ 41
2.6.2. Storage ...................................................................................................... 45
2.6.3. Natural Gas Demand ................................................................................ 48
2.6.4. Exports By Pipeline and Liquified Natural Gas (LNG) ............................... 52
2.6.5. Texas Pipeline Exports .............................................................................. 53
2.6.6. Texas LNG exports ..................................................................................... 55
2.6.7. Natural Gas Infrastructure Participation in Load Curtailment .................. 56
3. Electricity and Natural Gas Financial Flows and Prices ................. 57
3.1. Energy Prices ......................................................................................................... 57
3.2. Ancillary Service Prices.......................................................................................... 59
3.3. PUCT Orders During February Blackout ................................................................ 59
3.3.1. Electricity Market Price Changes/Corrections During the Event .............. 60
3.4. Financial Fallout .................................................................................................... 64

3
4. A Comparison to Winter Events in 2011 and 1989 ......................... 70
4.1. December 1989 Winter Event .............................................................................. 70
4.2. February 2011 Winter Event ................................................................................. 71
4.3. Comparison of the Three Events .......................................................................... 73
5. Summary ................................................................................................. 76
Acknowledgements ........................................................................................ 77
Conflict of Interest Statements .................................................................. 78
References ....................................................................................................... 79
Appendix A. Short History of Texas Electric Grid and ERCOT: From the
Beginning to 2021 .......................................................................................... 82
A.1. Why Does Texas Have Its Own Grid? .................................................................... 82
A.2. Wholesale Market Restructuring (Deregulation) and Adjustment Timeline ....... 84
A.3. Why isn’t ERCOT Connected to Other Grids? ....................................................... 87
A.4. Today’s ERCOT Wholesale Market ....................................................................... 88
A.5. Characteristics of the ERCOT Retail market ......................................................... 88
A.6. Summary: ERCOT History and Current Status ...................................................... 90
Appendix B. Internal ERCOT Meteorological Discussions Before the
Storm ................................................................................................................ 92
Appendix C. Generator Outages Relative to Time Reaching Freezing
Temperature .................................................................................................... 94
Appendix D. Texas Natural Gas Balance .................................................... 97
Appendix E. Other (non-energy) Infrastructures Impacted from Storm:
Water and Housing ....................................................................................... 100

4
List of Figures
Chapter One
Figure 1.a ................................................................................................................................................ 13

Chapter Two
Figure 2.a ................................................................................................................................................ 16
Figure 2.b ................................................................................................................................................ 17
Figure 2.c ................................................................................................................................................ 18
Figure 2.d ............................................................................................................................................... 19
Figure 2.e. .............................................................................................................................................. 22
Figure 2.f ................................................................................................................................................ 22
Figure 2.g ............................................................................................................................................... 24
Figure 2.h ............................................................................................................................................... 24
Figure 2.i ................................................................................................................................................. 25
Figure 2.j.. ............................................................................................................................................... 27
Figure 2.k................................................................................................................................................ 28
Figure 2.l ................................................................................................................................................. 29
Figure 2.m. ............................................................................................................................................ 30
Figure 2.n .............................................................................................................................................. 33
Figure 2.o. ............................................................................................................................................. 34
Figure 2.p .............................................................................................................................................. 35
Figure 2.q. .............................................................................................................................................. 42
Figure 2.r ............................................................................................................................................... 43
Figure 2.s ............................................................................................................................................... 43
Figure 2.t ............................................................................................................................................... 44
Figure 2.u. ............................................................................................................................................. 46
Figure 2.v ............................................................................................................................................... 46
Figure 2.w .............................................................................................................................................. 47
Figure 2.x. ............................................................................................................................................... 47
Figure 2.y. .............................................................................................................................................. 48
Figure 2.z ............................................................................................................................................... 49
Figure 2.aa ............................................................................................................................................ 49
Figure 2.bb. ........................................................................................................................................... 51
Figure 2.cc ............................................................................................................................................. 51
Figure 2.dd ............................................................................................................................................ 52
Figure 2.ee ........................................................................................................................................... 53
Figure 2.ff. ............................................................................................................................................. 54
Figure 2.gg ........................................................................................................................................... 54
Figure 2.hh ........................................................................................................................................... 55
Figure 2.ii ............................................................................................................................................... 56

5
Chapter Three
Figure 3.a .............................................................................................................................................. 58
Figure 3.b .............................................................................................................................................. 59
Figure 3.c. .............................................................................................................................................. 61
Figure 3.d .............................................................................................................................................. 63
Figure 3.e .............................................................................................................................................. 64

Appendix A
Figure A.1 .............................................................................................................................................. 89
Figure A.2 ............................................................................................................................................... 91

Appendix C
Figure C.1 .............................................................................................................................................. 95

Appendix D
Figure D.1 ............................................................................................................................................... 97
Figure D.2 .............................................................................................................................................. 99
Figure D.3 ............................................................................................................................................. 99

6
List of Tables
Chapter Two
Table 2.a. ................................................................................................................................................ 27
Table 2.b. ............................................................................................................................................... 39

Chapter Three
Table 3.a ................................................................................................................................................ 63

Chapter Four
Table 4.a. ................................................................................................................................................ 74

Appendix A
Table A.1.. .............................................................................................................................................. 85

7
Executive Summary
Objective
This report recounts the factors contributing to disruptions in electricity and natural
gas service in Texas during Winter Storm Uri, with a particular focus on blackouts on
the Electric Reliability Council of Texas (ERCOT) grid during the period from February
15-18, 2021. Our goal is to create a common basis of fact to educate the debate over
strategies to avoid similar problems in the future. We specifically limited the scope
of this report to the events during February 2021, a comparison of the February 2021
event to the previous energy system disruptions in 1989 and 2011 during winter
storms, and the economic consequences of the event in February 2021. An appendix
describes the long-term evolution of the ERCOT electricity market and provides
historical context.
This report is not intended to comprehensively address all issues stemming from
such a complex event, but may inform subsequent assessments. This report does
not recommend policies or solutions.
Data
To perform the analysis presented in this report, we reviewed a variety of public
information sources, analyses conducted by the staff of ERCOT, testimony before
state legislative committees, and public data archives provided by ERCOT. In
addition, and through an agreement with the Public Utility Commission of Texas
(PUCT), select members of our project team were provided access to certain
confidential data collected by the PUCT and ERCOT pertaining to the performance of
specific electric generating units, enrollment of energy consumers in ERCOT’s
Emergency Response Service program, communications regarding the winter storm,
and other relevant information.1 We also used a proprietary source of data to
explore the performance of the natural gas industry during the event. We further
considered and analyzed meteorological and other technical data that groups within
the University of Texas at Austin (UT) have acquired for other research purposes.
Findings
The failure of the electricity and natural gas systems serving Texas before and during
Winter Storm Uri in February 2021 had no single cause. While the 2021 storm did
not set records for the lowest recorded temperatures in many parts of the state, it
caused generation outages and a loss of electricity service to Texas customers several
times more severe than winter events leading to electric service disruptions in
December 1989 and February 2011. The 2021 event exceeded prior events with
respect to both the number and capacity of generation unit outages, the maximum

1 Josh Rhodes and Carey King of the project team were provided access to the confidential data.

8
load shed (power demand reduction) and number of customers affected, the lowest
experienced grid frequency (indicating a high level of grid instability), the amount of
natural gas generation experiencing fuel shortages, and the duration of electric grid
operations under emergency conditions associated with load shed and blackout for
customers. The financial ramifications of the 2021 event are in the billions of dollars,
likely orders of magnitude larger than the financial impacts of the 1989 and 2011
blackouts.
Factors contributing to the electricity blackouts of February 15-18, 2021 include the
following:
 All types of generation technologies failed. All types of power plants were
impacted by the winter storm. Certain power plants within each category of
technologies (natural gas-fired power plants, coal power plants, nuclear
reactors, wind generation, and solar generation facilities) failed to operate at
their expected electricity generation output levels.
 Demand forecasts for severe winter storms were too low. ERCOT’s most
extreme winter scenario underestimated demand relative to what actually
happened by about 9,600 MW, about 14%.
 Weather forecasts failed to appreciate the severity of the storm. Weather
models were unable to accurately forecast the timing (within one to two
days) and severity of extreme cold weather, including that from a polar
vortex.
 Planned generator outages were high, but not much higher than assumed in
planning scenarios. Total planned outage capacity was about 4,930 MW, or
about 900 MW higher than in ERCOT’s “Forecasted Season Peak Load”
scenario.
 Grid conditions deteriorated rapidly early in February 15 leading to blackouts.
So much power plant capacity was lost relative to the record electricity
demand that ERCOT was forced to shed load to avoid a catastrophic failure.
From noon on February 14 to noon on February 15, the amount of offline
wind capacity increased from 14,600 MW to 18,300 MW (+3,700 MW).2
Offline natural gas capacity increased from 12,000 MW to 25,000 MW
(+13,000 MW). Offline coal capacity increased from 1,500 MW to 4,500 MW
(+3,000 MW). Offline nuclear capacity increased from 0 MW to 1,300 MW,
and offline solar capacity increased from 500 MW to 1100 MW (+600 MW),
for a total loss of 24,600 MW in a single 24-hour period.

2 For wind and solar electricity generation, nameplate capacity is not a meaningful measure of the amount of
power generation expected when the unit is not experencing an outage, though nameplate capacity provides a
meaningful metric for the thermal fleet of power plants (e.g., coal, nuclear, and natural gas-fired generating
units). Using backcasted values of the available wind and solar radiation, available wind capacity outages actually
decreased from 9,070 MW to 5,020 MW (-4,050) over the same time period and solar outages increased less,
from 108 MW to 545 MW (+437 MW).

9
 Power plants listed a wide variety of reasons for going offline throughout the
event. 3 Reasons for power plant failures include “weather-related” issues
(30,000 MW, ~167 units), “equipment issues” (5,600 MW, 146 units), “fuel
limitations” (6,700 MW, 131 units), “transmission and substation outages”
(1,900 MW, 18 units), and “frequency issues” (1,800 MW, 8 units). 4
 Some power generators were inadequately weatherized; they reported a level
of winter preparedness that turned out to be inadequate to the actual
conditions experienced. The outage, or derating, of several power plants
occurred at temperatures above their stated minimum temperature ratings.
 Failures within the natural gas system exacerbated electricity problems.
Natural gas production, storage, and distribution facilities failed to provide
the full amount of fuel demanded by natural gas power plants. Failures
included direct freezing of natural gas equipment and failing to inform their
electric utilities of critical electrically-driven components. Dry gas production
dropped 85% from early February to February 16, with up to 2/3 of
processing plants in the Permian Basin experiencing an outage.5
 Failures within the natural gas system began prior to electrical outages. Days
before ERCOT called for blackouts, natural gas was already being curtailed to
some natural gas consumers, including power plants.
 Some critical natural gas infrastructure was enrolled in ERCOT’s emergency
response program. Data from market participants indicates that 67 locations
(meters) were in both the generator fuel supply chain and enrolled in
ERCOT’s voluntary Emergency Response Service program (ERS), which would
have cut power to them when those programs were called upon on February
15. At least five locations that later identified themselves to the electric
utility as critical natural gas infrastructure were enrolled in the ERS program.
 Natural gas in storage was limited. Underground natural gas storage
facilities were operating at maximum withdrawal rates and reached
unprecedently-low levels of working gas, indicating that the storage system
was pushed to its maximum capability.

The ERCOT system operator managed to avoid a catastrophic failure of the electric
grid despite the loss of almost half of its generation capacity, including some black
start units that would have been needed to jump-start the grid had it gone into a
complete collapse.

3 Some power plants experienced multiple outages and may be included in more than one category.
4 The maximum values during the event are presented here for both capacity and numbers of units. Different
categories may have experienced peak outage rates at different times.
5 Based on our data sample of 27 natural gas processing plants.

10
Had one or more of the problems listed above not occurred, outages might still have
occurred, but their duration and severity would likely have been lower. The
magnitude of the failures caused unprecedented impacts:
 Rolling blackouts turned into persistent days-long electrical outages affecting
millions of Texans connected to the ERCOT grid and leading to loss of life.
 The financial impacts were tremendous. According to PUCT data, natural gas
prices, normally much less than $10/MMBTU, spiked to over $400/MMBTU
at Texas trading hubs. Natural gas providers that were able to produce and
transport gas reported windfall profits. Many financial sector firms that
operate in the ERCOT energy market also reported large profits.
 The price of electricity spiked to $9,000 per MWh and stayed there by orders
of the PUCT, which suspended some market price setting rules during the
electricity blackouts. The PUCT stated that high prices were intended to
ensure that generating units would participate in the market and that price-
sensitive energy consumers would minimize their demand for electricity from
the market. The PUCT also stated that the suspension of the rules was due to
two reasons. First, to account for load that had been removed due to forced
outages from the calculation of prices. Second, to avoid potentially even
higher electricity prices that would result from the high price of natural gas.6
 The financial losers included power generators whose equipment failed,
generators dependent upon natural gas that were unable to obtain the fuel
or were unhedged to high natural gas prices, and load serving-entities (retail
electric providers, municipal utility systems, and rural electric cooperatives)
who were inadequately hedged.
 Many market participants defaulted on their payment obligations to ERCOT,
which serves as a central counter-party in the markets for electrical energy
and ancillary services that it administers. These defaults may translate into
increased costs for electricity consumers in Texas for many years to come.
Disclaimers
This report was funded in part by the PUCT via an Interagency Agreement with the
University of Texas at Austin (UT). Beyond funding, the Interagency Agreement
between the PUCT and UT provided certain members of the research team, under a
confidentiality agreement, with access to electricity market participant data and
other confidential information collected by the PUCT and ERCOT. The PUCT reviewed
a draft of this report to ensure that no confidential information was inadvertently
disclosed. The committee had full discretion as to the content and presentation of
material in the report.

6 PUC Project No. 51617: Order Directing ERCOT to Take Action and Granting Exception to Commission Rules.
February 15, 2021. https://interchange.puc.texas.gov/Documents/51617_3_1111656.PDF.

11
Any opinions or positions expressed in this report are those of the authors alone and
do not reflect any official positions of the PUCT, ERCOT, the University of Texas at
Austin, or the Board of Regents of the University of Texas.

12
1. Introduction

1.1 Objective
This report recounts the factors contributing to the disruptions in electricity and
natural gas service in Texas during Winter Storm Uri, with a particular focus on the
outages in electrical service in the Electric Reliability Council of Texas (ERCOT) power
region during the period from February 15-18, 2021. In pursuing this report’s
objective, the Energy Institute at the University of Texas at Austin assembled a team
of faculty and researchers to identify and review credible sources of data in an
attempt to provide a factual account of what happened and what went wrong during
the winter storm.
Our goal is not to provide recommendations, but to create a common basis of fact to
educate the debate over policy changes under consideration as a response to the
winter storm. We specifically limited the scope of this report to the events and
economic impacts of February 2021, including a comparison to previous winter
storm blackouts of 1989 and 2011. To provide additional historical context, we
include an appendix that describes the long-term evolution of the ERCOT electricity
market. This report is not intended to comprehensively address all issues stemming
from such a complex event, but can inform future assessments.7
This report was funded in part by the Public Utility Commission of Texas (PUCT).
Beyond funding, the Interagency Agreement between the PUCT and the University of
Texas at Austin (UT) provided the research team with access to confidential
electricity market information under a confidentiality agreement. The PUCT
reviewed a draft of this report to ensure that no confidential information was
inadvertently disclosed, but any views expressed are solely those of the authors and
supporting committee members. The authors had full discretion as to the content
and presentation of material in the report.
Various participants in the state’s natural gas and electricity markets fund research at
UT, and some contributors to this report have performed such funded research or
provide consulting assistance to companies or organizations involved in the energy
industry. Disclosures of any relationships that might be perceived to introduce a
conflict of interest are available via the UT Energy Institute and at:
https://energy.utexas.edu/ercot-blackout-2021.

7 Other reports might include a more-comprehensive or focused analyses that might later be developed by the
Federal Energy Regulatory Commissions (FERC), the North American Electric Reliability Corporation (NERC), the
PUCT, or other government bodies.

13
1.2. Energy in Texas
Texas is the nation’s leading state in electricity and natural gas in both production
and consumption. Electricity is provided to the majority of the state’s consumers
through an intra-state grid, managed by ERCOT as an independent system operator,
with limited interconnection to the other two main electrical grids serving the U.S.
and Canada, as noted in Figure 1.a. Limited federal regulatory jurisdiction within the
ERCOT power region has permitted the development of a unique electricity system
involving competition among generators of electricity in the wholesale sector and
“customer choice” or retail competition in some areas of the state which were
served by vertically-integrated investor-owned utilities prior to 2001.

Figure 1.a. ERCOT in relation to the other two grid interconnections in the U.S. and Canada.8

Natural gas has long been the leading fuel for the generation of electricity in Texas,
although the state has become a leader in the generation of electricity from
renewable energy sources in recent years. Despite the interdependence of the
state’s natural gas and electricity industries, different state agencies have regulatory
oversight over the two industries. While the PUCT oversees electricity services (and
has regulatory oversight over certain aspects of water and telecommunications
services), the natural gas sector is regulated by Texas Railroad Commission (RRC).
The PUCT’s oversight over the electricity industry includes responsibility for
overseeing the operations of the electric grid operator, ERCOT. Appendix A provides

8 ERCOT: http://www.ercot.com/news/mediakit/maps,
http://www.ercot.com/content/wcm/landing_pages/89373/ERCOT-Internconnection_Branded.jpg

14
additional information and historical context pertaining to the development and
operation of ERCOT.

The following Chapter 2 reviews the physical aspects of the February 2021 event,
examining conditions of the electricity and natural gas industries in the days prior
and during the winter storm. Both the demand and supply sides of energy markets
are discussed. Chapter 3 examines prices in electricity and natural gas markets, and
the impact of the price spikes upon market participants in these industries. Chapter
4 contrasts the February 2021 event to previous winter events in 1989 and 2011 that
prompted electrical outages. Chapter 5 provides a brief summary of this report.

15
2. Timeline of Events Related to
February 2021 ERCOT Blackouts
We begin this chapter by recounting the electricity generating capacity anticipated in
advance of the event, as suggested by winter resource adequacy analyses conducted
by the ERCOT staff and updated information available to the market in the days prior
to the event. Electric load forecasts and their underlying weather forecasts and
assumptions are reviewed. Operational activities on the electric side are then
discussed, including efforts by the grid operator, transmission and distribution
providers, and others to constrain the demand for electricity. We conclude this
chapter with a focus on natural gas operations before and during the event.

2.1. ERCOT’s Winter 2020/2021 SARA report
ERCOT develops a Seasonal Assessment of Resource Adequacy (SARA)9 report for
each of the fall, winter, spring, and summer seasons that “focuses on the availability
of sufficient operating reserves to avoid emergency actions such as the deployment
of voluntary load reduction resources.” Each SARA report is released one to two
months before the season under study. In a SARA report, ERCOT assumes a set of
hours at which the peak electricity demand will occur. For the winter, ERCOT
assumes peak demand will occur between 7 am and 10 am. The winter 2020/2021
SARA report,10 released on November 5, 2020, indicated that ERCOT’s “Forecasted
Season Peak Load” scenario expected that about 74,000 MW of net resource
capacity11 would be available to meet a winter peak of 57,699 MW. This includes an
assumed “… unit outage forecast of 8,616 MW during the winter months, which is
based on historical winter outage data compiled since 2017” (Figure 2.a). A quantity
of Positive Reserves12 (far right, green bar of Figure 2.a) above a few thousand
megawatts indicates that, under this scenario, the chance of load shed (blackouts)
was low. The report also noted that the previous (to 2021) all-time winter peak was
65,915 MW and occurred on January 17, 2018.

9 See: http://www.ercot.com/gridinfo/resource.
10 SARA-FinalWinter2020-2021: http://www.ercot.com/content/wcm/lists/197378/SARA-FinalWinter2020-
2021.xlsx
11 Total Resources – Maintenance Outages – Forced Outages (82,513 MW – 4074 MW – 4542 MW = ~74,000
MW)
12 Positive reserves refers to “Capacity Available for Operating Reserves.”

16

Figure 2.a. Waterfall chart of the ERCOT “Forecasted Season Peak Load” Winter 2020/2021 SARA scenario
showing the total amount of Resources assumed for ERCOT as well as expected plant outages and peak demand.
This scenario indicated that ERCOT would have over 16,000 MW of reserves, sufficient capacity to match supply
and demand.

ERCOT’s Winter 2020/2021 SARA scenario indicated the scenario that resulted in the
least amount of reserve capacity was the “Extreme Peak Load / Extreme Generation
Outages During Extreme Peak Load” scenario (Figure 2.b). This scenario assumed
67,208 MW load and 13,953 MW of thermal power plant outages, such that there
would be only 1,352 MW of operating reserves. This level of reserves is below 2,300
MW, a level that ERCOT indicates is at risk of Energy Emergency Alert actions.13 This
“extreme” scenario did not assume any downward adjustments for low wind output,
but ERCOT’s “Extreme Low Wind Output” SARA scenario does assume a downward
adjustment of 5,279 MW.

13 http://www.ercot.com/content/wcm/lists/164134/EEA_OnePager_FINAL.PDF
82,513
-4,074 -4,542
-57,699
16,198
Total
Resources
Maintenance
Outages
Forced
Outages
Peak
Demand
Reserves
Resources Available to the Grid (MW)
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
Forecasted Typical ERCOT Winter Scenario (MW)

17

Figure 2.b. Waterfall chart of the ERCOT “Extreme Peak Load / Extreme Generation Outages During Extreme Peak
Load” Winter 2020/2021 SARA scenario. This scenario indicated that ERCOT would have only 1,352 MW of
reserves, insufficient capacity to prevent an Energy Emergency Alert.

Figure 2.c shows the shortfall of generation during the hour of the week of February
14, 2021 with the highest deficit in reserves. There were over 26,200 MW of forced
thermal (i.e., natural gas, coal, nuclear, biomass) power plant outages, over 2.5 times
the assumed worst case in any SARA report scenario.

18

Figure 2.c. Waterfall chart of the actual resource availability at the time of peak demand (February 16, 2021 at 9
am) indicating a shortage of 28,345 MW in capacity due to lower than forecasted wind output, a higher capacity
offline for maintenance, and over 26,000 MW of capacity triggered offline as instigated by the weather
conditions.14

2.2. The Week Before Winter Storm Uri
2.2.1. Weather and Load Forecasts and Alerts
At the end of January, internal discussions between ERCOT’s meteorologist and
various planning groups began about a potential February cold weather event.15
However, it wasn’t until February 8 that the weather models used by the ERCOT staff
began to show a worrisome event for the ERCOT service region. There is inherent
uncertainty in the ability of weather models to forecast the timing and severity of
extreme cold weather events, such as a polar vortex – even when it is known to be
present in North America. As late as February 13, weather models used by ERCOT
still disagreed on forecasted morning cold temperatures in Texas cities by as much as
10°F.
The discussion from the National Weather Service Houston/Galveston office provides
a summary of the widespread nature of the winter storm.16 The meteorological
events unfolded as follows: A cold front moved in February 10, followed by a winter

14 The terms “Low Wind,” “Thermal Maintenance Outages,” and “Thermal Forced Outage” relate to those used in
the Winter 2020/2021 ERCOT SARA report.
15 We summarize these internal ERCOT weather-related communications in the Appendix.
16 Available at https://www.weather.gov/hgx/2021ValentineStorm

19
weather advisory (WWA) on February 11, followed by a Winter Storm Watch (WSW)
on February 12. From February 13 in the night through February 14, the weather
worsened further and the entire state was under a WSW and a Hard Freeze Warning.

Figure 2.d. Timeline of weather conditions during event

The cold weather experienced was a result of a polar vortex that was impacting
temperatures across the U.S. The Dallas/Ft. Worth National Weather Service
reported:
The record cold spell and extended period of wintry weather was caused by
the upper-level polar vortex dropping south from the north pole and then
lingering over South Central Canada for more than a week. This allowed cold
arctic air to gradually spill southward into Texas. At the same time, several
upper-level disturbances riding the jet stream moved through the area
providing lift and moisture for winter precipitation. These disturbances show
up as waves or dips in the lines that move in from the west. Ahead of each
wave, upper-level lift increases and moisture is drawn up from the south.
Since it was already so cold, this precipitation fell as snow, sleet, and freezing
rain.17
Since the event was due to an evolving vortex situation, the meteorological
community could provide warnings related to unusually cold temperatures towards
the end of January. For example, on February 3, CNN’s headline was "Every US State

17 https://www.weather.gov/fwd/Feb-2021-WinterEvent.

20
will see below freezing temperatures over the next week," and mentioned "It's about
to get so cold that boiling water will flash freeze, frostbite could occur within 30
minutes and it will become a shock to the system for even those who are used to the
toughest winters."18
This nature of advance warning (from 7 to 14 days ahead of the event) is unusual.
However, the southward migration of the polar vortex was being monitored and
predicted by different weather forecast modeling systems in early January. The
Washington Post had a report on January 5 titled "The polar vortex is splitting in two,
which may lead to weeks of wild winter weather.”19
In hindsight, while it is apparent that concerns regarding unusually cold winter
events were flashing, it is important to note that the system inherently is difficult to
predict. The same article highlights that: "The United States is slightly more of a
winter wild card for now, experts say, with individual winter storms tough to predict
beyond a few days in advance."
ERCOT’s first Operating Conditions Notice20 mentioning the approaching winter
storm was on February 8, 2021 – a week before the first of the blackouts began. The
notice asked generators to update their ability to provide power and review fuel
supplies:
At 18:53 [February 8, 2021], ERCOT is issuing an OCN for an extreme cold
weather system approaching Thursday, February 11, 2021 through Monday,
February 15, 2021 with temperatures anticipated to remain 32°F or below.
QSEs are instructed to: Update COPs and HSLs when conditions change as
soon [as] practicable, Review fuel supplies, prepare to preserve fuel to best
serve peak load, and notify ERCOT of any known or anticipated fuel
restrictions, Review Planned Resource outages and consider delaying
maintenance or returning from outage early, Review and implement
winterization procedures. Notify ERCOT of any changes or conditions that
could affect system reliability.21
ERCOT subsequently issued both an extreme cold weather event advisory and a
watch on February 10 and 11, respectively. On February 12, the Texas Governor
declared a state of emergency due to the severity of the winter storm.22

18 https://www.cnn.com/2021/02/02/weather/polar-vortex-forecast-freezing-cold/index.html
19 https://www.washingtonpost.com/weather/2021/01/05/polar-vortex-split-cold-snow/
20 http://www.ercot.com/services/comm/mkt_notices/opsmessages/2021/02
21 See ERCOT glossary: http://www.ercot.com/glossary. QSE: Qualified Scheduling Entity. COP: Current Operating
Plan. HSL: High Sustainable Limit. OCN: Operating Condition Notice
22 https://gov.texas.gov/uploads/files/press/DISASTER_severe_weather_FINAL_02-12-2021.pdf

21
On February 10th, as cold temperatures entered the ERCOT region, the total amount
of offline power plant capacity increased from 14,400 MW to 25,850 MW, or about
12% to 21% of the total 123,050 MW of installed nameplate capacity in ERCOT. The
term nameplate capacity refers to the maximum rated output of a generator, prime
mover, or other electric power production equipment under specific conditions
designated by the manufacturer. Installed generator nameplate capacity is commonly
expressed in megawatts (MW) and is usually indicated on a nameplate physically
attached to the generator.23 Nameplate capacity is different than the power output
one expects from any given generation unit on average or at any given time when it
operates in concert with all generation units in an electric grid.
Wind turbines suffered some of the earliest outages and derates as freezing
precipitation and fog resulted in ice accumulation on blades and – eventually, as
temperatures dropped further – in the gearboxes and nacelles. Unit-specific data
indicate that other types of generators – mostly those fueled with natural gas – were
facing pre-blackout fuel supply issues, and were starting to go offline or derate
capacity as early as February 10 due to fuel delivery curtailments.
Because load projections are based on weather forecasts, uncertainty about the
weather meant that ERCOT’s load forecasts did not fully anticipate the spike in
electricity demand that would result from the winter storm. As the winter event
drew closer and its magnitude became clearer, forecast accuracy improved
considerably.24
Figure 2.e depicts the hourly forecasts released to the market on February 8, 10, 12,
and 14 for the ensuing seven days. For example, the forecast released at 8:30 a.m.
on February 8 projected total system demand of 58,728 MW for 8 a.m. on February
15. ERCOT estimated that the actual demand would have been 75,573 MW had
there been no load shed during that hour.25 The forecast released on February 14
was considerably more accurate, though it remained 3,540 MW too low.
Figure 2.f shows the forecast error using ERCOT’s estimate of the load had there
been no load shed minus the forecasts released to the market at 8:30 a.m. on
February 11, 12, 13, and 14 – a measure of how well ERCOT’s load forecasts
predicted the coming demand on the system. Forecasted electrical demands for the
late night/early morning hours were the least accurate.

23 Energy Information Adminstration glossary definition of nameplate capacity:
https://www.eia.gov/tools/glossary/index.php?id=G#gen_nameplate.
24 Recent load forecasts are available at: www.ercot.com/gridinfo. An archive of past load forecasts was
provided by ERCOT for the purpose of this analysis.
25http://www.ercot.com/content/wcm/lists/227689/Available_Generation_and_Estimated_Load_without_Load_
Shed_Data.xlsx

22

Figure 2.e. ERCOT 7-day (hourly resolution) load forecasts for February 8, 10, 12, and 14.

Figure 2.f. The error in ERCOT 7-day (hourly resolution) load forecasts made on February 11, 12, 13, and 14
compared to actual demand on the days of February 15-18, 2021.26

26 Positive values represent the errors (in MW) of forecasts that were lower than actual demand.

23
The load forecasting error can be at least partially explained by errors in the weather
forecasts upon which the electricity demand forecasts were based. Figure 2.g and
Figure 2.h depict hourly temperature forecasts, for two of eight ERCOT weather
zones, upon which the demand projections in Figure 2.e were presumably based.27
The North Central zone includes Dallas and Fort Worth, while the South Central zone
includes San Antonio and Austin.28
The forecast available to ERCOT on February 8 anticipated a low in North Central
Texas of 20.5ᴼF at 4:00 a.m. on February 14, for the entire week of the winter event.
The February 12 forecast was updated, and it was expected that the region would
experience a low 20 degrees colder at just 0.5ᴼF at 6:00 a.m. on February 16.
The data for South Central Texas show a similar pattern. The February 8 forecast
showed a low of 26ᴼF at 4:00 a.m. on February 14, for the entire week of the winter
event. By February 12, a low of 9ᴼF was expected in the region at 5:00 a.m. on
February 16.

27 Temperature data are available in the Market Information page on www.ercot.com. An archive of the
“Weather Assumptions” file was obtained from ERCOT for this analysis.
28 Note that ERCOT uses data from 29 weather stations. Each zone includes two or three weather stations. Thus,
the temperature data discussed here do not correspond with a single weather station.

24

Figure 2.g. Temperature forecasts, as used by ERCOT, for the North Central Texas load region as of the mornings
of February 8, 10, 12, and 14. Also shown are the ERCOT staff’s calculations of the actual temperatures in the
region.

Figure 2.h. Temperature forecasts, as used by ERCOT, for the South-Central Texas load region as of the mornings
of February 8, 10, 12, and 14 along with actual temperatures. Also shown are the ERCOT staff’s calculations of
the actual temperatures in the region.

2.2.2. Recall of Power Plant Outages for Maintenance
At the time (February 8) of ERCOT’s first Operating Condition Notice, approximately
6,630 MW of thermal generation were offline for planned maintenance,

25
corresponding to 2,550 MW above the level assumed in SARA scenario “Forecasted
Season Peak Load.” By the end of Sunday, February 14, about 1,700 MW of
generation had been brought back online from either finished or cancelled
maintenance, bringing the total planned outage value to 4,930 MW, about 900 MW
higher than in the “Forecasted Season Peak Load” SARA scenario (Figure 2.a).

2.3. The Week of Winter Storm Uri (February 13-20, 2021)
On Saturday, February 13 ERCOT began to deploy Responsive Reserves29 and issued
an Emergency Notice for the extreme cold weather event impacting the region.
February 13 was also the first day that large generators began to unexpectedly go
offline. On Sunday, February 14, ERCOT issued a public appeal for energy
conservation and issued multiple watches regarding power supply shortages (Figure
2.i).

Figure 2.i. ERCOT communications and triggers of Energy Emergency Alerts in the hours leading up to the major
load shedding events of the night of February 14 and early morning of February 15, 2021 (ERCOT, 2021).

During the late hours of February 14, electricity load, or demand, was approaching
available generation. As generation could not sufficiently increase to meet demand,

29 Responsive Reserves are an Ancillary Service that provides operating reserves that is intended to: 1) arrest
frequency decay within the first few seconds of a significant frequency deviation on the ERCOT Transmission Grid
using Primary Frequency Response and interruptible Load; 2) after the first few seconds of a significant frequency
deviation, help restore frequency to its scheduled value to return the system to normal; 3) provide energy or
continued interruption of load during the implementation of the EEA; and 4) provide backup regulation.

26
the frequency of the grid began to decline.30,31 In such circumstances, ERCOT begins
various contingency plans such as calling on reserves and shedding load, and at low
enough frequencies, automated load shed can occur.32,33
On Monday, February 15 at 00:15 CST, ERCOT declared an Energy Emergency Alert
Level 1 (EEA 1), at 01:07 CST ERCOT moved to EEA 2,34 and at 01:20 CST, ERCOT
declared an EEA 3 event and began “firm load shed” or “blackouts.”35 ERCOT did not
return to normal operations until 10:36 CST Friday, February 19. The ERCOT system
frequency reached a low of 59.302 Hz at roughly 1:55am on February 15, 2021.
It is important to note that ERCOT protocols allow generators to automatically “trip”
offline, or automatically shut down and disconnect from the grid, if the grid
frequency drops to 59.4 Hz or below for more than 9 minutes (Table 2.a). This
automatic shutdown lowers the risk of exposure to harmful vibrations and heat that
can damage generation equipment if operating at low frequency for too long.36 The
ERCOT system frequency dropped below 59.4 Hz for 4 minutes and 23 seconds
(Figure 2.j) on the morning of February 15. Consequently, the grid was within
minutes of a much more serious and potentially complete blackout on the morning
of February 15.

30 Electric grids operate using the principle known as alternating current, or AC. North American grids, including
ERCOT, are designed for current and voltage to oscillate at a frequency of 60 cycles per second, or 60 Hz.
31 If grid frequency falls below 59.9 Hz, this generally indicates that load is large relative to demand.
32 ERCOT Nodal Operating guide, June 15, 2019 Section
(http://www.ercot.com/content/wcm/libraries/182971/June_15__2019_Nodal_Operating_Guides.pdf) Section
2.6 Requirements for Under-Frequency and Over-Frequency Relaying, 2.6.1 Automatic Firm Load Shedding,
paragraph (1)
33 Importantly, ERCOT makes other non-automated (by engineering devices) decisions to trigger actions to
stabilize the grid before grid frequency reaches 59.3 Hz (e.g., call on responsive reserve and non-spinning reserve
capacity).
34 See ERCOT glossary: http://www.ercot.com/glossary. EEA: Energy Emergency Alert
35 http://www.ercot.com/services/comm/mkt_notices/opsmessages/2021/02
36 About 1,800 MW of (mostly coal and natural gas) generators listed frequency issues as the reason for tripping
offline during the winter event, even though, according to ERCOT protocols (Table 2.a of this report), the
frequency deviation shouldn’t have tripped any under-frequency relays that are designed to automatically
disconnect the power plant from the grid to physically protect itself. However, at some power plants, rapid
increases in exhaust and boiler pressures occurred from equipment responding to grid frequency changes. Those
fluctuating power plant conditions in turn tripped other safety mechanisms that took generators offline. Some
large thermal generation units require days to fully cool off before they can be restarted.

27
Table 2.a. Table from Section 2.6.2 of ERCOT Nodal Protocols indicating the allowed settings for under-frequency
relays installed on Generation Resources.37

Figure 2.j. The ERCOT grid frequency during the critical time of load shedding and generation capacity outages on
the morning of February 15, 2021 (ERCOT, 2021).

Figure 2.k shows the high level status of the grid from February 12 to February 20,
including what load would have been absent blackouts, the actual served load, total
renewable and thermal (nameplate) outages, as well as the level of load shed
(blackouts).

37 Note that we are presenting certain figures that were created by the ERCOT staff in this document, in
situations where have been able to review and confirm the underlying data used in the creation of those figures.

28

Figure 2.k. Hourly time sequence of forecasted load, actual load, and power plant capacity offline from Feb 11-
19, 2021.38
Absent load shed, ERCOT back casted demand to peak at roughly 76,800 MW,39
about 19,120 MW higher than the value expected under normal winter weather
(57,699 MW) and more than 9,500 MW higher than ERCOT’s “Extreme Peak Load”
SARA scenario.40 However, not only was demand underestimated, but supply was
overestimated, as discussed in the following section.

2.4. Generation Outages (Timeline)
ERCOT has publicly released data regarding which power plants went offline and
when41 and also aggregated capacity that was offline by cause of outage as
categorized (largely) by power plant operators.42

38 Data from ERCOT’s hourly load data archives as well as various public reports and datasets provided by ERCOT.
See http://www.ercot.com/news/february2021.
39http://www.ercot.com/content/wcm/lists/227689/Available_Generation_and_Estimated_Load_without_Load_
Shed_Data.xlsx
40 http://www.ercot.com/content/wcm/lists/197378/SARA-FinalWinter2020-2021.xlsx
41 http://www.ercot.com/content/wcm/lists/226521/Unit_Outage_Data_20210312.xlsx.
42http://www.ercot.com/content/wcm/lists/226521/ERCOT_Winter_Storm_Generator_Outages_By_Cause_Upd
ated_Report_4.27.21.pdf.

29
Going into the early morning of February 15, generation outages (nameplate) were
already high at roughly 30,000 MW. By 9:00 a.m., total outages and derates43
increased to over 50,000 MW, or roughly 40% of the total installed nameplate
capacity in ERCOT. Levels of outages and derates would change over the event, but
would not return to pre-blackout levels until the afternoon of February 19. Figure 2.l
shows outages and derates of power plants by cause (as reported to ERCOT by
generators, with some possible interpretation by ERCOT), based on nameplate
capacity.

Figure 2.l. Net capacity outages and derates by category of failure mode, when considering the rated nameplate
capacity of all power plants. Figure by ERCOT.44
As the extreme cold weather settled over the entire state, the outages increased.
From noon on February 14 to noon on February 15, the offline renewable capacity
increased from 15,100 MW to 19,400 MW (+4,300 MW) and the total outages of
thermal generators increased from 13,700 MW to 31,100 MW (+17,400).45
Figure 2.m shows the spatial temperature and generation outages across Texasduring
the critical hour when grid frequency was declining on the early morning of February
15, and the time of peak generation capacity outages on February 16.46 As the

43 A derated power plant is one that is able to produce some level of power output, but it not able to produce at
its full potential. For example, some natural gas power plants weren’t able to get enough gas to run at 100%
output, but were still able to produce some power at a lower level, thus the power plant was derated.
44http://www.ercot.com/content/wcm/lists/226521/ERCOT_Winter_Storm_Generator_Outages_By_Cause_Upd
ated_Report_4.27.21.pdf
45 Values rounded to nearest 100 MW.
46 Temperature data come from the National Atmospheric and Space Administration (NASA) Modern-Era
Retrospective Analysis for Research and Applications, Version 2 (MERRA-2):
https://goldsmr4.gesdisc.eosdis.nasa.gov/data/MERRA2/.

30
colder temperatures moved further south into Texas, so did generation outages.
Moreover, the types of outages changed.

(a) Temperature, February 15, 1:45 am

(b) Capacity offline, February 15, 1:45 am

(c) Temperature, February 16, 8:00 am

(d) Capacity offline, February 16, 8:00 am
Figure 2.m. The temperature across Texas and reported loss of (nameplate) capacity by ERCOT for the critical
time period of February 15, 1:45 am (a and b) and the time of peak generation outage on February 16, 8:00 am (c
and d).47
Generator outage data, as reported to and summarized by ERCOT, suggest that the
largest share of outages was weather-related. The capacity that went offline due to
weather-related48 causes doubled from 15,000 MW at noon on February 14 to

47 Each circle in subfigures (a) and (c) indicates the location of power generation units that are offline or derated,
and its color corresponds to the capacity in subfigures (b) and (d). Temperature data come from the MERRA2
reanalysis data set.
48 ERCOT defines outages which are weather-related in the following manner: “This includes but is not limited to
frozen equipment—including frozen sensing lines, frozen water lines, and frozen valves—ice accumulation on
wind turbine blades, ice/snow cover on solar panels, exceedances of low temperature limits for wind turbines,
and flooded equipment due to ice/snow melt.”

31
30,000 MW at noon on February 15. In total, about 167 units listed their outages as
weather-related during the event. Beyond wind turbine icing, outages between
February 14 and 15 were mainly the result of frozen water intakes and sensing lines
and the freezing of other general equipment. As freezing weather persisted further,
other problems arose — for example, there were issues around control and
condensate systems that caused more capacity to go offline. At least two black start-
rated units reported outages or derates for weather-related reasons. 49
The second largest reported category of offline capacity was existing outages,
including scheduled and planned outages, mothballed units, and forced outages that
started before the February 8 OCN. At noon on February 14 approximately 8,400
MW of capacity was offline due to existing outages. The majority of this capacity
(7,700 MW) was from coal and natural gas power plants. The total amount of these
pre-existing outages steadily declined to 7,300 MW by the end of the event.
“Equipment issues” accounted for the third highest amount of power plant outages
and derates. Equipment issues were the cause of 1,900 MW of outages at noon on
February 14, rising to 5,600 MW by noon on February 15. In total, equipment issues
were listed as the reason for outages at about 146 units. A survey of unit-specific
outage data indicates that these power plants went offline because of equipment
failures that were not directly associated with the weather, for example clogged
sensing lines and stuck valves due to normal wear and tear.50 At least six black start-
rated units reported outages or derates based on equipment failures.
Fuel limitations account for the fourth-most capacity outage and derating, with 131
units listing this reason for their outage.51 Fuel limitations mostly affected natural
gas plants and coal plants. Fuel issues for natural gas existed before the blackouts
began (3,500 MW at noon on February 14) and increased as the event continued
(6,700 MW at 10:00 a.m. on February 17). While there were no fuel-related outages
associated with coal on February 14, issues appeared on February 15 and caused the
outage of a maximum of 2,100 MW at 4:00 p.m. on February 16. Lack of fuel, low
fuel pressure,52 and fuel contamination were the major listed reasons for fuel-related
outages for natural gas-fired generation units. Detailed, unit-specific, power plant
outage information indicates that power plants with both “firm” and “non-firm” fuel

49 Black start generation units are those able to start generation on their own, without support of the ERCOT
transmission grid, as if there was absolutely no electricity generation on the grid (i.e., the grid is off, or “black”
with no lights).
50 Equipment failures such as these also happen in the summer when older power plants that don’t run often are
pressed into service to meet peak demand.
51 Fuel limitation issues later matched or exceeded equipment issues by February 16.
52 Some power plants were able to derate with lower fuel pressures, but others had to turn off completely.

32
supply contracts experienced fuel supply/curtailment issues. Also, at least five black-
start-rated units reported outages or derates based on fuel supply issues.
Generator reports to ERCOT indicate that natural gas fuel shortages preceded the
firm load shed directives from ERCOT, occurring as early as February 10. These fuel
limitations affected more generation capacity as the cold weather event continued.
At least as early as February 8, ERCOT began notifying QSEs of potential weather
issues and instructed them to notify ERCOT of any known or anticipated fuel
restrictions. ERCOT has an arrangement with at least one natural gas supplier to
provide e-mail notifications when gas supply restrictions are issued to its natural gas-
fired electric generation facilities. ERCOT received such notices as early as February 9
for supply restrictions starting the morning of February 10. Additionally, ERCOT
received a notice on February 10 of supply restrictions for parts of Texas that would
completely cut off power plants from fuel delivery and would start on February 12.
Additional natural gas outages are potentially due to the loss of electricity affecting
the ability of the natural gas infrastructure to operate and thus deliver fuel, but we
did not have data to evaluate the magnitude of this interdependence, or determine
causality. Public testimony from Oncor’s CEO indicated that not all infrastructure
that was critical to the natural gas supply chain was registered with them as critical
load not to be turned off.53 He stated that Oncor started the event with 35 pieces of
critical natural gas infrastructure on their “do not turn off” list, but added 168 more
by the end of the event. This presumably indicates that some delivery of natural gas
may have been interrupted due to power outages because the operators of the
critical natural gas infrastructure failed to alert the transmission and/or distribution
providers (TDSPs)54 that they were critical loads.
The detailed outage data also suggest that transmission and substation outages led
to generation outages reaching 1,900 MW of wind and solar on February 16. No
coal, natural gas, or nuclear generation units listed transmission outage as a reason
for an outage or derate. In all, 18 solar and wind units listed transmission losses as
their reason for outage or derating. Additional data from ERCOT indicate that on
February 9 the grid operator identified 28 existing transmission outages that could be
cancelled or withdrawn by February 12, and all outages planned to begin between
February 12-17 were moved, cancelled, or withdrawn. While it is likely that the grid
could have operated in a more stable manner with fewer planned transmission
outages, it is unknown how much worse, if at all, the situation would have been had
these outages been allowed to proceed.

53 https://www.texastribune.org/2021/03/18/texas-winter-storm-blackouts-paperwork/.
54 Section 2 of ERCOT protocols defines Transmission and/or Distribution Service Provider as: “An
Entity that is a TSP, a DSP or both, or an Entity that has been selected to own and operate
Transmission Facilities and has a PUCT approved code of conduct in accordance with P.U.C. SUBST. R.
25.272, Code of Conduct for Electric Utilities and Their Affiliates.” DSP = distribution service provider.

33
Grid frequency deviations were reported to be responsible for up to 1,800 MW of
outages (8 total units), mostly coal, at 2 a.m. on February 15.
Figure 2.n aggregates all the causes of outages and shows the total amount of
outages by fuel, based on nameplate capacity. From noon on February 14 to noon
on February 15, the amount of offline wind capacity increased from 14,600 MW to
18,300 MW (+3,700 MW).55 Offline natural gas capacity increased from 12,000 MW
to 25,000 MW (+13,000 MW). Offline coal capacity increased from 1,500 MW to
4,500 MW (+3,000 MW). Offline nuclear capacity increased from 0 MW to 1,300
MW, and offline solar capacity increased from 500 MW to 1100 MW (+600 MW).

Figure 2.n. Net capacity outages and derates by fuel type, relative to the rated nameplate capacity of all power
plants. Figure by ERCOT.56
Since rated nameplate capacities of wind and solar plants refer to the maximum
amount of generation possible, derates based on these capacities overstate the
amount of lost power generation due to the winter storm. Figure 2.o accounts for
this by showing the same information as Figure 2.n based on the wind and solar
capacities that would have been available based on back casted modeling that uses
actual wind speed and solar radiation data to estimate what would have been

55 Nameplate capacity for wind and solar is not representative of the amount of power generation expected
when the unit is not expierencing an outage, but is much closer for the thermal fleet. When accounting for
backcasted values of the available wind and solar radiation, available wind capacity outages actually decreased
from 9,070 MW to 5,020 MW (-4,050) over the same time period and solar outages increased less from 108 MW
to 545 MW (+437 MW).
56http://www.ercot.com/content/wcm/lists/226521/ERCOT_Winter_Storm_Generator_Outages_By_Cause_Upd
ated_Report_4.27.21.pdf.

34
produced had all of the available wind and solar capacity been online.

Figure 2.o. Net capacity outages and derates by fuel type, relative to expected contribution from wind and solar.
Since wind and solar are not expected to generate at their nameplate capacity rating, the value derating shown
here is less than that for wind and solar in Figure 2.n. Figure by ERCOT.57
Prior to the event, the Department of Energy and the Texas Commission on
Environmental Quality issued directives to ERCOT that allowed the grid operator to
dispatch certain power plants even if they would exceed pollution limits. The grid
operator calculated that these directives enabled additional generation units to
contribute an additional 1,400 MW of capacity, subject to outages and derates.

2.4.1. Generator Temperature Ratings Relative to Experienced Temperatures
This section combines data from ERCOT’s public file of generator outages released on
March 12, 2021 with weather data and confidential temperature ratings of power
plants.58 The purpose is to provide a high level view of whether some power plants
failed above or below their low temperature ratings (see Figure 2.p). This section is
not meant to provide a fully rigorous analysis of power plant failures as we only
compare temperatures and not, for example, the enhanced cooling effects of wind,

57http://www.ercot.com/content/wcm/lists/226521/ERCOT_Winter_Storm_Generator_Outages_By_Cause_Upd
ated_Report_4.27.21.pdf.
58 For power plants that experienced an outage during the event, ERCOT sent Requests for
Information (RFIs) to assess their causes. These RFIs included the question: “What is the minimum
ambient operating temperature that the unit can start and continue to run without a unit trip or
derate?” Some generators responded with “Unspecified” or “Unknown”, but some were able to
provide the minimum operating temperature, by unit, which were used here for comparison.

35
humidity, or ice. Also, we only plot data for a subset of the power plants listed in
ERCOT’s public file of generator outages.
The weather data are from the National Atmospheric and Space Administration (NASA)
Modern-Era Retrospective Analysis for Research and Applications, Version 2 (MERRA-
2) database. The MERRA-2 reanalysis weather database consists of atmospheric
reanalysis data based on multiple types of historical observations. The data has an
hourly time resolution and the reanalysis spans 1980-present. To relate a given power
plant to a temperature in the MERRA-2 database, we assume the experienced power
plant temperature is the same as the closest MERRA-2 temperature (example
temperature distributions by grid cell are in Figure 2.m).59

Figure 2.p. Plots of the estimated temperature experienced at outage for a subset of thermal power plants that
experienced an outage or derate versus the lowest rated (design) temperature of power generation units (as
reported by generation operators to ERCOT and FERC) for the winter event of February 10-20, 2021. We present
the data in two charts: (a) generation units experiencing outages for any reason, (b) generation units
experiencing outages summarized as “weather related” by ERCOT. Electric generation units were chosen at
random.
Each dot in Figure 2.p represents a single generation unit listed in ERCOT’s public data
file of power plant failures. We include two charts in Figure 2.p, all the power plants
that we compared (a) and the subset that reported their outage as being “Weather
Related.” The red line represents the boundary where the power plant design
temperature equals experienced temperature. A data point above the red line means
that a generation unit experienced an outage or derating at a temperature above its
minimum temperature rating. A data point below the red line means that a
generation unit experienced an outage or derating while experiencing a temperature
below its minimum design temperature rating. Thus, in this simple analysis, data

59 More precisely, the temperature is associated with the centroid of the MERRA-2 0.5° × 0.625° grid
with the shortest Euclidean distance to the latitude and longitude of the power plant.

36
points above the red line indicate that some generation units might not have met their
temperature design criteria. 60

2.5. Load Curtailment, Requested and Achieved
As the freezing temperatures increased demand for electricity-based heating of
homes and other buildings, ERCOT, the TDSPs, load-serving entities, and customers
undertook a variety of actions to reduce demand on the system during the winter
event, including:
 Involuntary load reduction due to selective outages of distribution circuits or
substation loads chosen by the TDSPs and directed by Transmission Operators
(TO)61 when ERCOT issues load shed orders.
 Customer response to high market prices by customers exposed to wholesale
electricity prices or natural gas prices.
 Deployment of load resources.
 Deployment of ERCOT’s Emergency Response Service (ERS) program.
 Automated load shed triggered by under-frequency relays.
 Deployment of various demand response (DR) programs by load-serving
entities.

2.5.1. Involuntary Load Shed
Per its Protocols, ERCOT declares an EEA Level 3 if operating reserves cannot be
maintained above 1,375 MW. If conditions do not improve, continue to deteriorate,
or operating reserves drop below 1,000 MW and are not expected to recover within
30 minutes, ERCOT orders transmission providers to reduce demand on the system.62
The TDSPs are charged with making the final decision on which circuits to turn off to
achieve the demand reduction. Each Transmision Operator (TO) is responsible for a
predetermined percentage of the total load shed that ERCOT calls for in its “ERCOT

60 We note a few important caveats for interpreting this figure. The figure does not indicate the
minimum temperature actually experienced by any given power plant, which is likely lower than the
temperature displayed, but its minimum design temperature and the temperature at which it
experienced an outage. Also, the figure has no information about precipitation (rain, ice, snow, fog)
which could have been a crucial factor in any given power plant outage or derating. Also, only
natural gas, coal, and nuclear generation units are shown in this figure. In particular, most wind
power outages related to ice accumulation which was a combination of subfreezing temperatures and
precipitation or fog.
61 A Transmission Operator (TO) is defined in Section 2 of ERCOT protocols as “A Transmission and/or
Distribution Service Provider (TDSP) designated by itself or another TDSP for purposes of
communicating with ERCOT and taking action to preserve reliability of a particular portion of the
ERCOT System, as provided in the ERCOT Protocols or Other Binding Documents.”
62 http://www.ercot.com/content/wcm/lists/200198/EEA_OnePager_updated_9-4-20.pdf

37
Load Shed Table.”63 Each TO instructs its respective TDSPs to achieve its load shed
obligation. The percentage of load reduction for each TO is based on the previous
year’s peak Loads for its respective Transmission Service Providers (TSP), as reported
to ERCOT and modified annually.
EEA Level 3 with Firm Load Shed was called on February 15 at 1:25 CST.64 Load shed
orders increased to 20,000 MW by 19:00 on the February 15. An analysis of load
data appears to confirm compliance with the involuntary load reduction
instructions.65

2.5.2. Response to High Prices
ERCOT conducts surveys of load-serving entities to discern the number of energy
consumers under price-sensitive electricity plans. Such plans might include real-time
pricing (to directly expose a consumer to wholesale market prices), peak rebate
proms (providing a rebate to consumers who reduce demand below baseline
amounts at the request of the load-serving entity), or block and index pricing (where
consumption in excess of a contractual amount is exposed to market prices, while
consumption below that amount results in a credit based on prevailing market
prices).
In 2020, over 100,000 accounts were under a real-time pricing or block and index
pricing plan. The number of accounts under a peak rebate plan was over 94,000.66
In recent summer periods with overall high system peak demand and high electricity
prices, ERCOT has estimated demand response based on these accounts to be in
excess of 4,000 MW.67 The amount of demand reduction due to high prices during
this winter event is difficult to determine, since many customers lost service due to
involuntary outages and for other reasons.

63 This ERCOT Load Shed Table is in Section “4.5.3.4, Load Shed Obligation” of the ERCOT Operating
Guide. During February 2021, the language of Section 4.5.3.4 stated: “Obligation for Load shed is by
DSP. Load shedding obligations need to be represented by an Entity with 24x7 operations and Hotline
communications with ERCOT and control over breakers. Percentages for Level 3 Load shedding will
be based on the previous year’s TSP peak Loads, as reported to ERCOT, and will be reviewed by
ERCOT and modified annually.” As of July 1, the language of Section 4.5.3.4 has been amended.
64 www.ercot.com/services/comm/mkt_notices/notices/2021/02
65 See slides 4 and 5:
http://www.ercot.com/content/wcm/key_documents_lists/218735/DSWG_May_28_2021_February_Winter_Ev
ent_Analysis_Raish.pptx.
66http://www.ercot.com/content/wcm/key_documents_lists/214087/15._RMS_2020_4CP__Retail_DR_Analysis_
Raish.v3.pptx.
67http://www.ercot.com/content/wcm/key_documents_lists/218751/DSWG_2020_4CP__Retail_DR_Analysis_Ra
ish.pptx, slide 5.

38
2.5.3. Deployment of Load Resources
Large industrial energy consumers with the ability to curtail their demand on the
ERCOT system are permitted to provide ancillary services. Roughly half of ERCOT’s
requirements for Responsive Reserve Services (RRS)68 are met by load resources
equipped with under-frequency relays that instantaneously curtail load when the
frequency drops to 59.7 Hz. Resources providing this service must also be able to
respond to verbal dispatch instructions. In February 2021, the amounts of RRS
provided by loads averaged 1,259 MW, which is lower than the 1,548 MW resource
provided in January 2021.69 Some load resources are also eligible to provide
Regulation Up,70 Regulation Down,71 and Non-Spinning Reserves,72 though the
amount that these services provided in February 2021 was small.73
An analysis of load data suggests that maximum load reductions from load resources
were over 1,400 MW on February 15, 16, and 17, and just under that level on
February 19.74

2.5.4. ERS Program
The ERS program was activated during the winter event to reduce demand on the
system.75 Customers enrolled in the program reduce their purchases from the grid
by reducing load or by starting backup generators. These emergency resources are
contracted to provide this service to ERCOT through four-month contracts, and have
response times of 30 minutes or 10 minutes. Different amounts are procured in each
of eight time periods (or hour blocks) spread among weekday and weekend days.

68 RRS provides an operating reserve from on-line generation resources that is responsive to frequancy based on
governor action and responsive to any automated or verbal dispatch instructions from ERCOT within 10 minutes.
Load resources providing RRS respond via underfrequency relays when system frequency drops below 59.7 Hz.
69http://mis.ercot.com/misapp/GetReports.do?reportTypeId=13242&reportTitle=Monthly%20ERCOT%20Deman
d%20Response%20from%20Load%20Resources&showHTMLView=&mimicKey.
70 Regulation Up provides an operating reserve that increases generation output (or reduces demand, if a load
resource) in response to automated signals to balance real-time demand and resources.
71 Regulation down provides an operating reserve that decreases generation output (or increases demand, if a
load resource) in response to automated signals to balance real-time demand and resources.
72 Non-spinning reserves provides an operating reserve that can be synchronized and ramped to a determined
amount of generation or load reduction within 30 minutes of notice.
73http://mis.ercot.com/misapp/GetReports.do?reportTypeId=13242&reportTitle=Monthly%20ERCOT%20Deman
d%20Response%20from%20Load%20Resources&showHTMLView=&mimicKey.
74 See slide 7 at:
http://www.ercot.com/content/wcm/key_documents_lists/218735/DSWG_May_28_2021_February_Winter_Ev
ent_Analysis_Raish.pptx.
75 http://www.ercot.com/services/programs/load/eils

39
Overall, the program achieved its targeted level of demand reduction of roughly
1,100 MW during the morning of February 15.76 Some of the energy consumers in
the program reduced their level of demand prior to the EEA Level 3 and deployment
of ERS, as many businesses closed in anticipation of the storm. Some of the early
demand reduction may have also resulted from public appeals for energy
conservation, and local transmission and distribution system outages.
While the participating “loads” or consumers in the ERS program provided demand
reduction well in excess of their obligations, ERS program participants contracted to
provide generation during emergencies generally under-performed. The ERS
generators met less than half of their obligation of around 300 MW in the early hours
of February 15.77 Performance of the ERS generators was reportedly hampered by
“supply constraints, refueling issues, and forced outages.”78 Some generators in the
ERS program indicated that they were not able to meet their requirements because
they ran out of fuel (many have enough on-site fuel for only a few hours or days).
Other ERS generators indicated that the distribution circuit through which they were
served was turned off, so they were not able to provide power to the bulk grid.

2.5.5. Automated Load Shedding via Under-frequency Relays
Under-frequency load shed (UFLS) relays exist on the transmission and distribution
grid. These are configured to trigger a circuit offline, and thus the customers on that
circuit, if experiencing a frequency of 59.3 Hz or lower. At 59.3 Hz, under-frequency
relays on the transmission and distribution grid can trigger automatic load shedding
of up to 5% of the transmission operator’s load (Table 2.b). Lower frequencies
trigger even more UFLS.
Table 2.b. Table from Section 2.6.1 of ERCOT Nodal Operating Guide indicating the settings for Under-Frequency
Load Shedding (UFLS) relays installed by Transmission Operators (TO).

76http://www.ercot.com/content/wcm/key_documents_lists/226624/April_2021_DSWG_Meeting_ERCOT_FINAL
.PPTX. Per slide 3: “As an ERS fleet in aggregate, the response generally met or exceeded the aggregate
obligation.” Note that ERS obligations differ in different time periods within a day.
77http://www.ercot.com/content/wcm/key_documents_lists/226624/April_2021_DSWG_Meeting_ERCOT_FINAL
.PPTX. Slide 15.
78http://www.ercot.com/content/wcm/key_documents_lists/226624/April_2021_DSWG_Meeting_ERCOT_FINAL
.PPTX, slide 8.

40
Confidential responses of TDSPs to ERCOT requests for information note UFLS relay
tolerances of +/- 0.01 Hz, and some TDSPs recorded frequencies between 59.300 and
59.310 Hz during the critical frequency period indicated in Figure 2.j. As reported by
five of the major TDSPs in ERCOT, the total MW UFLS by automatic (by experiencing
low frequency) triggering of relays was on the order of 200 MW for 2 to 3 dozen
circuits.
In addition to automated triggering of UFLS relays, the TDSPs also included some
circuits with UFLS relays in the so-called manual load shed in which they selected
circuits to trip offline to meet their portion of the load shed obligation as
commanded by ERCOT. There were over 1000 circuits (possibly more than 2000)
with UFLS relays included in this manual load shed. Thus, the manual load shed
affected two orders of magnitude more load, number of circuits, and customers than
were triggered via automated UFLS. At all times the TDSPs were still required to have
25% of load on circuits with UFLS relays.

2.5.6. Deployment of Various Demand Response (DR) Programs by Load-Serving
Entities
Many DR programs are operated by load-serving entities completely outside of
ERCOT’s formal markets. For example:
 CPS Energy operates a large portfolio of demand response programs that can
achieve demand reductions of well over 200 MW during a typical summer
deployment.79
 Austin Energy operates certain DR programs.80
 A number of retail electric providers operate programs that control
thermostats to achieve residential demand reduction.81
Though the focus of these programs has historically been on reducing demand during
the summer, at least one utility attempted to deploy their programs during the
winter event to achieve whatever demand reduction might be possible.82 The
success of these efforts is not yet publicly-known.

79 https://www.sanantonio.gov/Portals/0/Files/Sustainability/STEP/CPS-FY2020.pdf, p. 11, Table 1-1.
80 https://austinenergy.com/wcm/connect/5f6f5cdc-31bb-436c-a52f-
a050d113b5d2/DemandResourceMWSavings-WP.pdf?MOD=AJPERES&CVID=mRLC6hb, pp. 15-17.
81 For example: https://www.reliant.com/en/residential/electricity/save-energy/degrees-of-difference-
rewards.jsp; https://www.txu.com/savings-solutions/txu-ithermostat.aspx
82 See, for example: https://newsroom.cpsenergy.com/update-as-of-sunday-february-14-2021-400-pm-winter-
weather-and-extreme-cold-puts-community-at-risk-state-grid-operator-and-cps-energy-call-for-customers-to-
reduce-electric-and-natural-gas-use/.

41
2.5.7. Aggregate Levels of Demand Response
It is clear that a very large demand reduction was achieved during the February event
through a combination of formal programs and involuntary load shed action, by the
grid operator, TDSPs, load-serving entities, and individual consumers. ERCOT has
estimated that over 32,000 MW of demand reduction was achieved through the sum
of these actions when demand reduction peaked in the morning of February 16,
while the previous day saw peak levels of demand reduction of over 28,000 MW.83
However, it is not possible to specifically attribute the demand reduction to each of
these specific actions. Involuntary load accounted for the majority of load shed, and
these load shed actions by a TDSP limit the ability of a customer to respond to prices
or take some other action, for example.

2.6. Natural Gas and Operations during February 2021
This section covers how the production and flow of natural gas changed during the
event. It also provides context for the various end uses of natural gas among which
total consumption is partitioned. For a primer on the balance of natural gas in Texas,
see Appendix D.
2.6.1. Natural Gas Production
Per a February 25, 2021 report by the Energy Information Administration (EIA),84
Texas natural gas production fell by almost half during Winter Storm Uri – from 21.3
billion cubic feet per day (Bcfd) during the week ending February 13, to about 11.8
Bcfd at its lowest point on February 17 (see Figure 2.q.). As a daily average over
month, Texas dry natural gas production dropped from 21 in January 2021 to 13 Bcfd
in February 2021.85

83 See slide 4 at:
http://www.ercot.com/content/wcm/key_documents_lists/218735/DSWG_May_28_2021_February_Winter_Ev
ent_Analysis_Raish.pptx.
84 Texas natural gas production fell by almost half during recent cold snap - Today in Energy - U.S.
Energy Information Administration (EIA)
85 https://www.eia.gov/todayinenergy/detail.php?id=46896.

42

Figure 2.q. Texas Dry Gas Production through Jan 2016 – Feb 2021 (Source: EIA)
Based on a sample set of processing plants, located in the Permian, we also saw
reduced residual gas86 output from these plants during the week of the storm. Our
sample includes 27 processing plants, with a total capacity 4.4 Bcfd, which is about
25% of the total 17 Bcfd capacity in the Permian Basin.
Two key observations arise from an examination of this sample set of processing
plants:
 Per Figure 2.r, out of 27 gas processing plants in our sample, eight had zero
output on February 15, 15 had zero output on February 16, and 18 had zero
output on February 17.
 Figure 2.s shows the reported output from these 27 processing plants in
February versus their inlet capacity. In early February, throughput was
around 1.6 Bcfd, but declined to 1.4 Bcfd on February 12 and 13, and then on
February 14, declined rapidly over the next three days to 0.257 Bcfd on
February 16. This is an approximate 85% drop from the throughput level
earlier in the month.
Since the Permian Basin produces about 50% of the dry production in the State of
Texas and the data in Figure 2.s represent part of the processing plants from the
Permian, the loss of production out of Permian Basin could have been close to 8 Bcf
on February 13, which aligns with the reported single day drop of Texas from the EIA
report. For the month of February, based on sample data, the daily average Permian
gas processing could have been reduced by 6 Bcfd, or about 75% out of the reported
8 Bcfd reduction for Texas overall.

86 Residual gas is the natural gas that is left after natural gas processing, which is free from impurities,
moisture, natural gas condensates and is ready to be transported to the end user market through gas
pipelines. Residual gas is also known as pipeline quality dry gas.

43

Figure 2.r. Number of Permian Basin natural gas processing facilities at zero output, out of our sample of 27
facilities. (Source: Wood Mackenzie)

Figure 2.s. Throughput gas of Permian Basin processing plants out of our sample of 27 facilities. (Source: Wood
Mackenzie)

0%1%-1%
10%7%9%
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Throughput Gas of Permian Basin Processing Plants Sample
Residue Gas Inlet Capacity Incremental % Change in Throughput compared to Feb 1

44

Figure 2.t. Texas natural gas production by basin since 2016 (Source: GPCMTM)
The sample processing plant data indicates a severe reduction in dry gas production.
There are two major factors contributing to the decline of dry gas production in Texas
during the storm: frozen infrastructure and electric power interruptions.
Freeze-offs at wellheads can occur when unprotected wellheads experience
sufficiently low ambient temperatures causing water and other liquids in the gas to
form ice that can accumulate to such a degree as fill the entire cross-sectional area of
pipes and prevent flow to the wellhead. The consequences can range from a minor
inconvenience to major reductions in natural gas production. Wellheads in Texas are
generally not hardened for freezing conditions.
Figure 2.t shows the trend of average daily Permian Basin natural gas production
since 2011. During this time a higher percentage of gas production shifted to the
Permian, avoiding some weather interruptions more frequent in the Gulf Coast
region, such as hurricanes, but increasing vulnerability to cold weather.
Furthermore, the Permian Basin gas generally has a higher water content, making it
more prone to freeze in cold weather and form hydrates which can block the flow of
gas.
It is also possible, and has been noted by some natural gas companies, that power
interruptions to critical infrastructure contributed to a further decline in dry gas
production during the week of the storm. Remote processing plants, especially
larger ones (greater than 50 million cubic feet per day throughput), typically used to
have on-site power generation, but more modern processing plants are often grid
connected. The data indicate that natural gas output started to decline rapidly
before the electricity forced outages (load shed) began early on February 15, with
production declining about 700 million cubic feet per day (MMcfd) from February 8-
14, (see Figure 2.s). This decline is likely due to weather-related factors and not a
loss of power at natural gas facilities. However, some of the additional 600 MMcfd
0
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45
output decline from February 14-15 could be partly due to natural gas facilities
residing on circuits that the TDSP selected to follow ERCOT’s load shed orders.
2.6.2. Storage
According to the Texas Railroad Commission, there are 40 natural gas storage sites in
Texas with a total maximum 17,536 MMcfd reported withdrawal rate.87 Our sample
data set88 includes 5 interstate connected storage facilities and 7 intrastate
connected storage facilities, covering about 25% of the state’s total.
Figure 2.u shows the reported net flow rates for the observed interstate storage units
and compares them to past years. The data show a significantly larger withdrawal of
about 291,000 MMBtu/d89 in February 2021, almost three times higher than that of
February 2020. This high level of withdrawal leads to a historical low level of
reserves for these storage units as shown in Figure 2.v. Based on the sample data, it
appears that interstate gas storage inventory started to drop rapidly on February 9,
with less than 10% of working gas storage remaining on February 18, and it was
almost fully depleted by February 21 (see Figure 2.v and Figure 2.w).

87 Gas Storage Statistics website of the Texas Railroad Commission (April 2021 report, accessed June
24, 2021): https://www.rrc.texas.gov/gas-services/publications-statistics/gas-storage-statistics/.
88 Based on the sample set, there is about 55% coverage of intrastate storage, while 10% of interstate
storage data. The data set is based on available data from Genscape Wood Mackenzie.

46

Figure 2.u. Net withdrawal rates (positive values indicate net withdrawal) as the daily average for each month
for five Texas interstate storage facilities. (Source: Wood Mackenzie)

Figure 2.v. Texas natural gas storage inventory for our sample interstate storage facilities (2016 – February 2021)
with lines indicating the maximum and minimum storage levels for the February months from 2016 to 2021.
Note: 1 MMBtu ~ 1000 cubic feet of natural gas. (Source: Wood Mackenzie)
Figure 2.v and Figure 2.w (focusing on data for January and February 2021) show the
total storage of natural gas for our sample interstate storage facilities, and Figure 2.x
shows the withdrawal rates for those five facilities as a percentage of their
historically-observed maximum withdrawal rates. Out of the five interstate storage
units observed here, four experienced some level of increase of withdrawal during
the winter event to reflect the higher demand for natural gas in the market. One of
the four units, Unocal Keystone storage, experienced a large withdrawal the week of
February 8. This could be a reflection of the early rise of the natural gas price which
went above $4/MMBtu the week leading to the storm, which was already higher
than usual.
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Sample Facilities (2016 -February 2021)
Inventory Max. Level for Feburary Min Level for Feburary

47

Figure 2.w. Texas natural gas storage inventory of for our sample interstate Storage facilities (January and
February 2021). Note: 1 MMBtu ~ 1000 cubic feet of natural gas. (Source: Wood Mackenzie)

Figure 2.x. Natural gas withdrawal (as the percentage of maximum withdrawal rates) in February 2021 from each
of our five sample interstate storage facilities. (Source: Wood Mackenzie)
Intrastate natural gas storage facilities also experienced high withdrawal rates
through the week of the winter storm. However, the data for our sample of
intrastate storage facilities indicate that during the week of February 13 their
collective withdrawal rates never reached 100% of historically-observed maximum
withdrawal rate capacities (Figure 2.y). These intrastate storage facilities also had
0
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/
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/
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1
MM
B
t
u
Natural Gas Storage Inventory: Texas Interstate Storage Sample
Facilities (January and February 2021)
Inventory Max. Level for Feburary Min Level for Feburary
0
20
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80
100
2/
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Pe
r
c
e
n
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a
g
e

(
%
)

o
f

Ma
x
i
m
u
m

W
i
t
h
d
r
a
w
a
l

R
a
t
e
Withdrawal of Sample Interstate Storage Facilities
MOSS BLUFF HUB, LLC NATURAL GAS PIPELINE COMPANY OF AMERICA LLC
Northern Natural Gas Company Transwestern Pipeline Company, LLC
Unocal Keystone Gas Storage, LLC

48
higher than usual withdrawals before the beginning of the winter storm, on February
10, even at gas prices of $4 per million Btu (MMBtu). This drawdown of storage
before February 14 contributed to the lack of natural gas supply going into the
coldest parts of the storm and to the historically high natural gas prices during the
storm that in some cases were 100 times higher than normal. This situation leading
into Winter Storm Uri was an extreme condition in which there was not sufficient gas
delivery capability to prevent the extreme high price increase.

Figure 2.y. Natural gas withdrawal (as the percentage of maximum withdrawal rates) in February 2021 from each
of our sample of intrastate storage facilities. (Source: Wood Mackenzie)

2.6.3. Natural Gas Demand
This section discusses the impacts on natural gas demand from the winter storm of
February 2021. The dataset includes all sectors of demand in three categories, as
labelled at interconnection point of the interstate pipeline network (delivery points).
The dataset represents around 15% of the total consumption in Texas.
0
10
20
30
40
50
60
70
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100
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Pe
r
c
e
n
t
a
g
e
Intrastate Storage Factilities Sample Withdrawal
Bammell Boling Dayton North Markham
North Lansing Spindletop West Clear Lake

49

Figure 2.z. Texas daily natural gas consumption by sector (from our sample of interstate pipeline data) (Source:
Wood Mackenzie)

Figure 2.aa. Incremental change (in percentage) of daily natural gas delivery by sector relative to delivery on
February 1, 2021, (Source: Wood Mackenzie)
Figure 2.z and Figure 2.aa show natural gas daily consumption in the sample Texas
dataset by three sectors in February 2021,90 representing overall changes and
dynamics aggregated across three sectors. Figure 2.z indicates an aggregate increase
in consumption peaking on February 14. Power plants and “city gate” (residential,

90 “City gate” includes residential, commercial and some small industrial users. “Power Plants” represent
connections to gas-fired power generators. Large industrial users are labeled as “End user” in the data.
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
2/
1
2/
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7
3/
1
MM
B
t
u
/
d
Texas Natural Gas Consumption (~ 15% of total) by Sector
END USER City Gate Power Plant
-64%
35%
141%
79%
-100%
-50%
0%
50%
100%
150%
200%
2/
1
2/
2
2/
3
2/
4
2/
5
2/
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2/
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2/
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5
2/
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6
2/
2
7
2/
2
8
Incremental Percentage of Daily Delivery by Sector
vs. Feb 1. 2021
END USER City Gate Power Plant

50
commercial, and small industrial) consumers increased their natural gas consumption
during the storm as industrial “end users” decreased consumption. This aligns with
the Texas Railroad Commission’s February 12, 2021 Emergency Order91 that
additionally prioritized natural gas to power generation just after the highest priority
for residential customers and other buildings. Figure 2.aa shows the same
consumption by sector as a daily percentage change versus first day of February,
which provides an additional perspective on the change of consumption within each
sector of gas delivery.
Figure 2.bb - Figure 2.dd show how the daily consumption of each sector in 2021
compares to past years. The consumption by large industrial users (“End Users” of
Figure 2.bb) does not display a strong seasonal pattern of its demand of natural gas,
but it has a higher likelihood to have interrupted demand from weather events or
pandemic (see 2020 March through April). During Winter Storm Uri, the largest
industrial consumers experienced the highest levels of natural gas curtailment.
Relative to consumption on February 1, large industrial natural gas consumption
declined by 30% on February 14 and dropped rapidly to its lowest level on February
17, to a 64% reduction. Compared to the past five years, the February 2021
curtailment in industrial sector demand is one of the biggest drops observed in the
data.
City gate demand (Figure 2.cc), largely characteristic of residential and commercial
demand, rose to a maximum of 730,000 MMBtu/d on February 15, which is about
35% higher than that on February 1. Natural gas consumption by power plants
(Figure 2.dd) increased significantly from February 9 reaching about 140% of its
February 1 level on February 14. While the natural gas system was able to
significantly increase delivery during the cold weather conditions in the week ending
on February 14, both city gate and power plants deliveries started to drop by
February 15. As discussed elsewhere in the report, natural gas was already curtailed
to some power generation facilities before February 14, and this aggregate decrease
in deliveries to consumers indicates further constraints due to upstream reduction
from production and storage.

91 https://rrc.texas.gov/media/cw3ewubr/emergency-order-021221-final-signed.pdf.

51

Figure 2.bb. Texas natural gas consumption for large industrial (“End User” in data set) via our sample of
connection points to interstate pipelines (Source: Wood Mackenzie)

Figure 2.cc. Texas natural gas consumption for residential, commercial, and small industrial (“city gate” in data
set) via our sample of connection points to interstate pipelines (Source: Wood Mackenzie)
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec
Mi
l
l
i
o
n

B
t
u

p
e
r

d
a
y

(
M
M
B
t
u
/
d
)
Texas Natural Gas Consumption:
Large Industrial Users (interstate data)
2016 2017 2018 2019 2020 2021
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec
Mi
l
l
i
o
n

B
t
u

p
e
r

d
a
y

(
M
M
B
t
u
/
d
)
Texas Natural Gas Consumption:
City gate (interstate data)
2016 2017 2018 2019 2020 2021

52

Figure 2.dd. Texas natural gas consumption by power plants via our sample of connection points to interstate
pipelines. (Source: Wood Mackenzie)
2.6.4. Exports By Pipeline and Liquified Natural Gas (LNG)
Besides delivering gas to local consumers, power plants and industrial facilities, Texas
exports natural gas to other states in the US and other countries including Mexico
and those in Asia and Europe. To provide full context of the impacts of Winter Storm
Uri on natural gas production, delivery, and consumption, we present data on the
flow of natural gas out of Texas via pipeline and tanker.
Figure 2.ee shows the Texas natural gas flows by end users in Texas local markets
(consumers, Electric Generation and Industrial) and exports via pipelines and
liquified natural gas (LNG) ship cargos. One can observe the seasonal patterns of
peaking pipeline exports and consumers demand (residential and commercial
customers) in the winter with power plant consumption peaking in the summer
months. In addition to the consumption within Texas and fuel losses, there has been
8-10 10 Bcfd (~10,000,000 MMBtu/d) of exports via pipelines and LNG cargos.
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec
Mi
l
l
i
o
n

B
t
u

p
e
r

d
a
y

(
M
M
B
t
u
/
d
)
Texas Natural Gas Consumption:
Power Plants (interstate data)
2016 2017 2018 2019 2020 2021

53

Figure 2.ee. Texas daily natural gas delivery (averaged each month) by end user (in Texas) and export method
(pipeline and liquefied natural gas, or LNG, tanker). (Source: GPCMTM)

Pipeline exports from Texas reach the U.S. Northeast and East Coast markets via
interstate pipelines that cross Texas’ eastern state border. Pipeline exports to the
midcontinent and west coast markets, including Mexico, Arizona and California,
occur via pipelines that cross Texas’ western border. Although many of these
pipelines span a wide geographic range, it is fair to say that the exports from East and
West Texas serve different downstream markets, with small exceptions.
2.6.5. Texas Pipeline Exports
Since 2016, during the month of February, Texas normally exports a net 6 Bcfd
through its interstate pipelines. Figure 2.ff shows Texas pipeline net exports crossing
the East and Texas West92 border via interstate pipelines, since 2016.
Due to a lack of upstream supply, there is a reduction in both imports and exports
starting in the second half of the week leading to the storm (see Figure 2.gg). During
February 10-13, exports out of Texas dropped significantly below the previous five-
year February minimum for the pipelines in the sample. Exports out of East Texas
not only dropped to a historically low level, but also 5 out of 16 exporting pipelines
reported reversed flow, declining from a net exports of average 2.8 Bcfd in February
to net import of 0.3 Bcfd. For the west side, pipeline net exports dropped from 3.2

92 There is small portion of gas exported from West Texas goes to Mexico through El Pas Gas Pipeline system.
After the interconnection meter included for the Texas Export sample, there is one more meter downstream
within the Texas border that measures flows to Mexico, and its flow averaged around 114,000 MMBtu/day since
2020. That exported volume can be seen in Figure 2.hh as reported data for the El Paso Natural Gas pipeline.
0
2
4
6
8
10
Jan-2016 Jan-2017 Jan-2018 Jan-2019 Jan-2020 Jan-2021
Bc
f
d
Texas Gas Delivery By End User and Export Method
Consumers Industrial
Electric Gen.Lease and Plant Fuel/Fuel Loss
Net Export by Pipeline Net Export by LNG

54
Bcfd in February to 0.6 Bcfd February 18, a drop of almost 95% relative to the
historical February average of 6 Bcfd.

Figure 2.ff. Daily flow rates of Texas net exports of natural gas as in our sample of interstate pipelines crossing
Texas’ East and Western borders (2016 through February 2021). (Source: Wood Mackenzie)

Figure 2.gg. Daily flow rates of Texas net exports of natural gas as in our sample of interstate pipelines crossing
Texas’ East and Western borders (February 2021). (Source: Wood Mackenzie)

Furthermore, Texas exports to Mexico have averaged around 5.3 Bcfd since January
2021, according to data from Wood Mackenzie. Figure 2.hh shows daily cross border
flows, for February 2021 from Texas to Mexico, for a sample of five interstate
pipelines that account for about 35% of the total Texas exports to Mexico. This figure
-10
-8
-6
-4
-2
0
2
2/1/2016 2/1/2017 2/1/2018 2/1/2019 2/1/2020 2/1/2021
Bc
f
d
Texas Net Exports by Interstate Pipeline
East Texas Export Flow West Texas Export Flow
-12
-10
-8
-6
-4
-2
0
2
2/
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/
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2/
2
8
/
2
0
2
1
bc
f
d
Texas Net Export by Interstate Pipe Sample in Feb 2021
East Texas Export Flow West Texas Export Flow
Historical Feb max flow East + West Historical Feb min flow East + West

55
shows that the lowest exports to Mexico occurred on February 16, during the middle
of the ERCOT blackouts, at 40% below the exports on February 1.

Figure 2.hh. Natural gas flow from Texas to Mexico via a sample of pipelines. (Source: Wood Mackenzie)

2.6.6. Texas LNG exports
The two main markets for U.S. liquified natural gas (LNG) exports are East Asia and
Europe. For exported gas, the seasonality is determined by the demand of
destination markets. There is a clear winter peaking pattern for LNG cargos with a
longer winter (in Europe and Asia compared to Texas). Similar to pipeline exports,
LNG exports also peak during the winter with significant heating demand in Europe
and Asia. For example, in January, the month before the storm, U.S. LNG exports to
China hit a new record high as East Asia was experiencing a winter that was colder
than normal.
Texas exports LNG cargos from two existing LNG terminals in Corpus Christi and
Freeport that have a total liquefaction capacity of 4.3 Bcfd (Figure 2.ii). Based on EIA
reported data on Texas LNG exports, there was a drop in LNG exports of about 50% in
February 2021 as compared to the previous month. During the winter storm, there
was roughly a 25% drop of LNG cargo93 sent out from the U.S. as a whole.

93 EIA: U.S. Natural Gas Exports and Re-Exports by Point of Exit
(https://www.eia.gov/dnav/ng/ng_move_poe2_a_EPG0_ENP_Mmcf_a.htm).
-2
-1.5
-1
-0.5
0
2/
1
/
2
0
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1
2/
2
/
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0
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/
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/
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/
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2
8
/
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0
2
1
Bc
f
d
Texas Pipeline Cross Border Flow Sample to Mexico
El Paso Natural Gas OKTex Pipeline Company
Tennessee Gas Pipeline Texas Eastern Transmission Co
Valley Crossing Pipeline, LLC

56

Figure 2.ii. Monthly LNG exports from Texas terminals. (Source: EIA)

2.6.7. Natural Gas Infrastructure Participation in Load Curtailment
Requests for Information (RFI) responses to ERCOT from Qualified Scheduling Entities
(QSEs) indicated that approximately 67 locations (electrical meters) that were in
ERCOT’s ERS program were also in the fuel supply chain for generation resources,
including gas refining and pipeline infrastructure. A separate set of data that
compared the electric meter IDs of resources in the ERS program with those also
registered as critical load with the major TDSPs indicated that 5 locations that self-
identified as critical natural gas infrastructure were in the ERS program.94
Cross-referencing ERS participating loads in the municipal and cooperative utility
regions of ERCOT identified a further 5 locations that, via satellite imagery overlaid
with spatial natural gas pipeline data, appeared to also be associated with natural gas
infrastructure.
It is possible that there is overlap in the RFI and TDSP datasets mentioned above, but
nonetheless it does appear that some power plant fuel supply chain infrastructure,
including some self-identified as critical, were participating in paid load reduction
programs that would have turned them off when ERCOT deployed ERS resources.

94 These ERS-participating locations only identified themselves as critical natural gas loads after they had been
turned off by the TDSP.
0
50,000
100,000
150,000
200,000
250,000
300,000
12
/
1
/
2
0
1
8
1/
1
/
2
0
1
9
2/
1
/
2
0
1
9
3/
1
/
2
0
1
9
4/
1
/
2
0
1
9
5/
1
/
2
0
1
9
6/
1
/
2
0
1
9
7/
1
/
2
0
1
9
8/
1
/
2
0
1
9
9/
1
/
2
0
1
9
10
/
1
/
2
0
1
9
11
/
1
/
2
0
1
9
12
/
1
/
2
0
1
9
1/
1
/
2
0
2
0
2/
1
/
2
0
2
0
3/
1
/
2
0
2
0
4/
1
/
2
0
2
0
5/
1
/
2
0
2
0
6/
1
/
2
0
2
0
7/
1
/
2
0
2
0
8/
1
/
2
0
2
0
9/
1
/
2
0
2
0
10
/
1
/
2
0
2
0
11
/
1
/
2
0
2
0
12
/
1
/
2
0
2
0
1/
1
/
2
0
2
1
2/
1
/
2
0
2
1
3/
1
/
2
0
2
1
MM
c
f

p
e
r

M
o
n
t
h
Monthly LNG Exports By Terminal in Texas
Corpus Christi Freeport

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3. Electricity and Natural Gas Financial
Flows and Prices
This chapter recounts the economic and financial impacts of the event. Wholesale
electricity prices during the event are reviewed, as well as decisions by the PUCT
which affected those prices. Natural gas prices are also reviewed and the financial
impacts of the price spikes in the state’s electricity and natural gas industries are
discussed.

3.1. Energy Prices
While the Texas electricity market structure is primarily an energy, not capacity,
market,95 it relies upon market price adjustments to help match supply and demand
in real-time. These market price adjustments are the ERCOT Wholesale Electricity
and Scarcity Pricing Real-time prices. They are calculated based on three categories:
1) supply and demand, 2) levels of available reserves, and 3) “out of market”
reliability actions. During normal operations, prices are set by the offers of power
plants, the level of demand, and any constraints96 on the system. Over the past few
years, prices during normal operations have averaged in the low tens of dollars per
MWh.
When there is a risk that the supply may not be able to meet the demand, meaning
there are low levels of reserves, Real-Time Reserve Price Adders are employed to
increase electricity prices. These short-term price adders increase revenues to
generators and while they are meant to incentivize investment in new generation
sources, they also incentivize investment in other technologies, such as demand
response. The value of the Real-Time Reserve Price Adders is based on the
Operating Reserve Demand Curve (ORDC). Via the ORDC, once reserves fall below
2,300 MW, wholesale real time prices increase rapidly to the system-wide offer cap,
currently $9,000/MWh.97 These adders largely explain the rapid swings in real-time
wholesale electricity prices, from values below $1,000/MWh to the cap, from
February 12-15 (Figure 3.a).

95 An energy-based electricity market is one in which the production of energy (i.e., megawatt-hours, MWh) is
compensated, but not the availability of capacity (i.e., MW), aside from the provision of ancillary services and
resources involved in emergency response programs.
96 Such as transmission constraints.
97 It is possible for prices to go above $9,000/MWh if additional local constraints become binding.

58

Figure 3.a. ERCOT real-time wholesale electricity prices during February 12-19, 2021 in the San Antonio Zone of
ERCOT.

Real-Time Reserve Price Adders only include data from “in-market” conditions and
do not inlcude “out-of-market” actions98 that might impact in-market conditions. For
example, if reserves drop too low and ERCOT goes into emergency operations and
deploys Emergency Response Services (ERS), it may appear that reserves have
increased (either via emergency generation brought online or responsive load taken
offline). With a higher level of reserves, the value of the Real-Time Reserve Price
Adders can decline even when scarcity in the market is still very high. To compensate
for this possibility, another scarcity pricing mechanism, the Real-Time On-Line
Reliability Deployment Price Adder (RTORDPA) was developed to keep real-time
prices high when emergency actions have been taken.
While some forms of “out-of-market” actions are considered within the calculation of
the Real-Time On-Line Reliability Deployment Price Adder, firm load shed is not.99
According to current market protocols, if ERCOT initiates blackouts such that reserves
appear high and recalls or cancels other out-of-market actions, price formation is
once again based on supply and demand, even if demand is artificially lower due to
active blackouts. This is why prices on February 15 were below $9,000/MWh for part
of the day (Figure 3.a).

98 Such as ERS deployment and firm load shed.
99 See http://www.ercot.com/mktrules/nprotocols/current, Section 6.5.7.3.1.

59
3.2. Ancillary Service Prices
The prices of ancillary services (AS)100 reached new heights during the winter event.
Prior to the storm, the prices of regulation up, responsive reserve service, and non-
spinning reserves had never exceeded $4,999, $8,956, and $7,000 per MW,
respectively. Due to extreme scarcity, pricing protocols drove AS costs (Figure 3.b)
much higher than previous levels to $24,993, $25,674, and $12,867 per MW for
regulation up, responsive reserve service, and non-spinning reserves, respectively.
While the PUCT did take action during the winter event to specify wholesale energy
prices outside of the established ERCOT market protocols (see following section
describing PUCT orders during the blackout), it did not take similar action on AS
prices. The Independent Market Monitor has argued that the prices for these
services should have been capped at $9,000 per MW, consistent with the energy
offer cap of $9,000 per MWh.101

Figure 3.b. Prices of Ancillary Services from February 11, 2021 through February 22, 2021. Source: ERCOT

3.3. PUCT Orders During February Blackout
On Monday, February 15 ERCOT initiated load shed orders and found itself in an
unprecedented situation with regard to solving for day-ahead market prices. It was
unclear what the value of “demand” should be for the day-ahead scheduling
algorithms when power had been cut off to a large percentage of customers. If

100 The US Federal Energy Regulatory Commission’s Order 888 issued in 1996 defines AS as operating reserves
(MW) “necessary to support the transmission of electric power from seller to purchaser given the obligations of
control areas and transmitting utilities within those control areas to maintain reliable operations of the
interconnected transmission system.”
101 http://interchange.puc.texas.gov/Documents/51812_34_1113309.PDF.

60
ERCOT assumed demand levels based upon the subset of customers that were
connected to the grid, then there would be enough generation to meet that demand,
and prices would not reflect the level of scarcity in the market. In cases of
generation scarcity, the PUCT’s scarcity pricing mechanism is designed to increase
wholesale prices to the applicable maximum price levels, the system-wide offer
cap.102 During the grid emergency, the PUCT attempted to impose real-time
corrections to the market structure to handle this singular event.

3.3.1. Electricity Market Price Changes/Corrections During the Event
During the February freeze events, the PUCT issued two orders under Project 51617
that impacted ERCOT electricity market pricing. The first order103 determined that
prices during the load shedding that began on February 15, 2021 were not reflective
of scarcity in the market, because prices were clearing below the system-wide offer
cap of $9,000/MWh.104 The Commission asserted that this outcome was
inconsistent with the fundamental design of the ERCOT market. Energy prices
should reflect scarcity of the supply. If customer load is being shed, scarcity is at its
maximum, and the market price for the energy needed to serve that load should also
be at its highest.105
The order goes on to instruct ERCOT to “ensure that firm load that is being shed in
EEA3106 is accounted for in ERCOT’s scarcity pricing signals.” This instruction resulted
in setting ERCOT market prices to $9,000/MWh while load shedding was happening.
The first order under Project 51617, issued on February 15, 2021, also retroactively
raised prices in the market to the market cap of $9,000/MWh if they had been below
that value between the period of time that load shed began and the order was

102 The system wide offer cap can be set at two different levels, depending on the amount of peaker net margin
experienced in the market so far in a given year: the High System-Wide Offer Cap (HCAP) or Low System-Wide
Offer Cap (LCAP). See Texas Administrative Code Chapter 25: SUBSTANTIVE RULES APPLICABLE TO ELECTRIC
SERVICE PROVIDERS, Section 25.505 with discussion of Scarcity Pricing Mechanism:
http://www.puc.texas.gov/agency/rulesnlaws/subrules/electric/25.505/25.505.pdf.
103 PUC Project No. 51617: Order Directing ERCOT to Take Action and Granting Exception to Commission Rules.
February 15, 2021. https://interchange.puc.texas.gov/Documents/51617_3_1111656.PDF.
104 The system-wide offer cap in ERCOT is administratively set at $9,000/MWh, also known as the High System-
Wide Offer Cap (HCAP), until peaker net margin is reached at which time protocols direct to drop to the Low
System-Wide Offer Cap (LCAP) which is the greater of either 1) $2,000 per MWh or 2) 50 times the natural gas
price index value determined by ERCOT, expressed in dollars per MWh and dollars per MW per hour. The natural
gas price index value is the previous daily average price of natural gas as indexed in the Katy Hub (NPRR 952).
105 PUC Project No. 51617: Order Directing ERCOT to Take Action and Granting Exception to Commission Rules.
February 15, 2021. https://interchange.puc.texas.gov/Documents/51617_3_1111656.PDF.
106 Energy Emergency Alert Level 3 (EEA3) is the highest level of emergency conditions at ERCOT and is the point
when ERCOT is allowed to order firm load shed, i.e. instruct Transmission Operators to initiate blackouts.

61
issued. A secondary order107 under the same project, issued on February 16, 2021,
cancelled the retroactively raised prices section of the first order.
The second part of the February 16, 2021 order suspended the system-wide offer cap
price calculation mechanism for LCAP that would have come into effect when the
system reached the Peaker Net Margin (PNM).108 The PNM value increases based on
the amount of scarcity pricing seen in the ERCOT market, and it is cumulatively
calculated starting from a value of $0 on January 1 of each year. The PNM threshold,
defined as $315,000/MW-yr, is based on triple the Cost of New Entry (CONE) for a
new peaker power plant to enter the ERCOT market. When the PNM value exceeds
$315,000/MW-yr, the system-wide offer cap is supposed to change from the HCAP to
the LCAP. ERCOT reports the current Peaker Net Margin levels as of 4:00 pm every
day. Figure 3.c shows the PNM values throughout the storm. PNM never met its
threshold before 2021, but, by the end of the week of February 15, 2021 reached a
value more than double the threshold.

Figure 3.c. The Peaker Net Margin (PNM) for February 14-22, 2021 compared to the total value of PNM reached
by the end of the years 2011 and 2019.

Once the PNM is reached in ERCOT, the wholesale price cap changes from HCAP to
LCAP. When LCAP and HCAP were defined, it was assumed that LCAP would always
be lower than HCAP. However, on February 16, the PUCT stated that it was

107 https://www.puc.texas.gov/51617WinterERCOTOrder.pdf.
108 The PNM is used to approximate the amount of profit or margin that a new natural gas-fired power plant
might be able to earn, based on the cost of building a new plant, natural gas prices, and the efficiency of a new
natural gas-fired power plant.

62
concerned that the formula for LCAP would actually translate to a higher price than
the HCAP price of $9,000/MWh. The PUCT’s order in Docket No. 51617 states:
[T]he peaker net margin (PNM) threshold [is] established in 16 TAC §
25.505(g)(6). That threshold is currently $315,000/MW-year. As provided in
§25.505(g)(6)(D), once the PNM threshold is achieved, the system-wide offer
cap is set at the low system-wide offer cap (LCAP), which is “the greater of”
either “(i) $2,000 per MWh and $2,000 per MW per hour; or (ii) 50 times the
natural gas price index value determined by ERCOT, expressed in dollars per
MWh and dollars per MW per hour.” Due to exceptionally high natural gas
prices at this time, if the LCAP is calculated as “50 times the natural gas price
index value,” it may exceed the high system-wide offer cap (HCAP) of $9,000
per MWh and $9,000 per MW per hour. 16 TAC § 25.505(g)(6).109
Because of the extreme demand for natural gas and constraints in natural gas supply,
the price of natural gas was also much higher than normal during the February event.
At one point, daily gas price averages at the LCAP-indexed hub were trading near
$400/MMBTU.110 Tom Hancock, COO of Garland Power and Light, testified that he
received a quote for natural gas at $1,100/MMBtu.111
If the PUC had not ordered the suspension of the HCAP to LCAP transition, ERCOT
would have been required to release a market notice on February 17 notifying the
market that PNM had been reached on February 16 and that LCAP would have come
into effect on February 18. If the LCAP had been allowed to come into effect, the
LCAP calculation would have driven the market price higher than the HCAP on
February 18 to $15,359/MWh. The LCAP on February 19 would have been
$3,318/MWh. By February 20 the Fuel Index Price was low enough that the LCAP
dropped down to $2,000/MWh.112
Table 3.a shows what the values for LCAP would have been if the PUCT had not
suspended it.113

109 http://interchange.puc.texas.gov/Documents/51617_3_1111656.PDF.
110 MMBTU = million British Thermal Units
111 February 25 and 26, 2021, Joint Hearing: State Affairs and Energy Resources Part 1 and Part 2,
https://house.texas.gov/video-audio/committee-broadcasts/87/.
112 The LCAP is the greater of either $2,000 per MW per hour, or 50 times the natural gas price index value
determined by ERCOT, expressed in dollars per MWh and dollars per MW per hour. This calculation assumes that
the PUCT would have still have forced the market price to the system wide offer cap, but would have left the
LCAP in place.
113 PUC Project No. 51617: Order Directing ERCOT to Take Action and Granting Exception to Commission Rules.
February 15, 2021. https://interchange.puc.texas.gov/Documents/51617_3_1111656.PDF.

63
Table 3.a. Calculation of what LCAP would have been if not for the PUCT orders.114
Date LCAP ($/MWh)
2021-02-18 $15,359.00
2021-02-19 $3,318.00
2021-02-20 $2,000.00

Figure 3.d shows ERCOT market prices from February 14 to the end of February 19
without the LCAP (i.e., what actually happened) and if the LCAP had been allowed to
come into effect as per protocols.115

Figure 3.d. Approximate market prices with and without the LCAP (data used to calculate the LCAP provided by
ERCOT).116
Because Peaker Net Margin was achieved on February 16, as per the ERCOT
protocols, LCAP would have come into effect on February 18. On February 18,
market prices would have increased from approximately $9,000/MWh (the HCAP) to
$15,359/MWh. For the hours of scarcity pricing on February 19, the LCAP would
have reduced prices from $9,000/MWh to $3,318/MWh. Given that the LCAP would
have been approximately $6,360/MWh higher than the HCAP for the entire day on
February 18, and about $5,680/MWh lower for only a short period of time on

114 LCAP values were calculated based on the Fuel Index Price data provided by ERCOT.
115 We make the assumption that scarcity pricing would have ended at the same time as it did in reality.
116 These estimated prices are just the LCAP System Wide Offer Cap (SWOC) and do not include any estimate of
system dynamics that, in reality, can push prices higher than the SWOC.

64
February 19, the overall energy costs for that week would have been approximately
$5.2 billion dollars higher (Figure 3.e), or about 11% more absent action by the PUCT.

Figure 3.e. Cumulative wholesale energy costs with and without the LCAP.
Figure 3.e shows the difference in cumulative market energy costs with and without
the LCAP.117 Because the LCAP would not have come into effect until February 18,
energy costs are the same for both sets of market prices until then.

3.4. Financial Fallout
Regulators and policy makers have very limited information about contracts and
hedging relationships among participants in the State’s electricity and natural gas
industries. This is particularly true for financial transactions negotiated outside of
ERCOT’s formal day-ahead and real-time markets for energy and ancillary services.
Such information is generally regarded as confidential. Thus, when faced with the
decisions regarding whether to raise prices to attract more supply and encourage
price-sensitive loads to reduce demand, or whether to “re-price” energy transacted
through ERCOT's markets, the PUCT Commissioners stated that they were unable to
determine which market participants might benefit or be disadvantaged by such
actions.118

117 These values are calculated by multiplying the load times the price with and without the LCAP as shown in
Figure 3.d. While much energy in ERCOT is transacted in the Day-Ahead Market (DAM), it is not known how
different relative DAM prices would have been had LCAP not been suspended. Thus, while the absolute numbers
might be different, the percentage increase might be similar.
118 See PUCT Open Meeting of March 5, 2021, item 22:
http://www.adminmonitor.com/tx/puct/open_meeting/20210305/.

65
On April 14, 2021, ERCOT reported cumulative aggregate “short payments” of
approximately $2.9 billion, and that it would take 96 years to collect the amount
outstanding using its standard Default Uplift Invoice process.119 This estimate was
raised to $2.99 billion on May 14, 2021.120 Of that, $1.86 billion relates to the default
of Brazos Electric Power Cooperative Inc., which filed for bankruptcy on March 1,
2021. Other market participants that had failed to pay amounts owed to ERCOT at
that time included Rayburn Country Electric Cooperative, Eagles View Partners LTD,
Energy Monger LLC, Entrust Energy Inc., GBPower, Griddy Energy LLC, Gridplus Texas
Inc., Hanwha Energy USA Holdings Corp., Iluminar Energy LLC, MQE LLC, Power of
Texas Holdings Inc., and Volt Electricity Provider LP. As a consequence of receiving
less revenue than ERCOT has invoiced to the market, ERCOT has reduced payments
to market participants that are owed revenues from the market for congestion
revenue rights.121
Under present market rules, unpaid amounts are uplifted to all market participants
based on each market participant’s MWh activity (energy bought or sold through
ERCOT’s formal markets) in the month prior to the defaulted payment.122 However,
these uplift mechanisms are limited to $2.5 million per 30 days.
The financial impacts on electricity retailers depend upon the degree to which their
price risk was hedged and how service outages affected their obligations to provide
energy during the event. Griddy Energy LLC, Entrust Energy Inc., and Power of Texas
Holdings Inc. have each filed for bankruptcy.123,124,125 Their certificates to serve
customers in the ERCOT market were revoked, and their customers were moved to
other retailers through ERCOT’s “mass transition event” process. The customer
bases of GridPlus MQE LLC (My Quest Energy), GB Power, Volt Electricity Provider LP,
Energy Monger, and Iluminar Energy were acquired by JP Energy Resources, while
the customer bases of Entrust Energy Inc. and Power of Texas Holdings Inc. were
acquired by Rhythm.126 Just Energy Group – using the brand names Amigo Energy,
Filter Group Inc., Hudson Energy, Interactive Energy Group, Tara Energy, and

119 Electric Reliability Council of Texas, Inc.’s notice of planned implementation of default uplift invoice process.
PUCT Project No. 51812: Issues related to the state of disaster for the February 2021 winter weather event.
120 ERCOT Market Notice M-A051421-01, May 14, 2021. M-A051421-01 Estimated Cumulative Aggregate Short
Pay Amount (ercot.com)
121 http://www.ercot.com/services/comm/mkt_notices/archives/5377.
122 http://www.ercot.com/content/wcm/lists/226521/Senate_Jurisprudence_031021_FINAL.pdf.
123 https://www.bizjournals.com/houston/news/2021/04/01/entrust-energy-bankruptcy-behind-the-deal.html.
124 https://www.cbsnews.com/news/griddy-energy-texas-files-bankruptcy/
125 https://www.bankruptcyobserver.com/bankruptcy-case/POWER-OF-TEXAS-HOLDINGS.
126 https://www.prnewswire.com/news-releases/rhythm-acquires-customers-of-entrust-energy-inc-and-power-
of-texas-holding-inc-301241112.html.

66
terrapass – also filed for bankruptcy after sustaining an estimated $250 million
loss.127
Media reports provide some insights into how the event impacted the financial
standing of some market participants. However, we emphasize that our Committee
is unable to audit, verify, and affirm any of the financial information repeated here.
NRG, the largest retailer in terms of market share in ERCOT,128 reported a negative
impact of $500 million to $700 million.129 The second-largest retailer, Vistra, expects
its financial losses due to the storm to be around $2 billion.130 Both NRG and Vistra
own and operate power plants, in addition to serving retail customers.
The impacts on municipal utility systems were mixed. The state’s largest municipal
electric and natural gas provider, CPS Energy reported losses on natural gas fuel
purchases of between $675 and $850 million, and losses on purchased power costs
in the range of $175 million to $250 million.131 In contrast, Austin Energy may have
benefited by about $54 million.132 The Brownsville Public Utility Board has estimated
a shortfall of $32.1 million.133
Generation owners whose fleets of generation resources operated well and were
able to provide generation that met or exceeded their commitments134 were
generally not financially harmed, and could have profited if a generator was able to
provide generation that met or exceeded its obligations. Many generators, however,
have locked-in a price for their generation through a contract or exchange, thus
limiting its profit potential. If the generation owner is dependent upon natural gas as

127 Gold. R. (2021). Texas Power Market Is Short $2.1 Billion in Payments After Freeze; Electric retailers failed to
make payments for power purchased when prices skyrocketed during the freeze, state grid operator says. The
Wall Street Journal. Feb. 27.
128 https://www.sciencedirect.com/science/article/abs/pii/S1040619020301408.
129 Bank of America Global Research, NRG Energy, Uri Impacts Unpacked: More Constructive Backdrop than
Thought. May 6, 2021. NRG Energy, Inc. Financial Update on Winter Storm Uri Impacts:
https://finance.yahoo.com/news/nrg-energy-inc-financial-winter-100100947.html.
130 Bank of America, VST US: Uri Impacts More Complicated Than We Thought. April 27, 2021.
131 https://newsroom.cpsenergy.com/cps-energy-will-be-taking-decisive-action-to-protect-customers-and-the-
san-antonio-community-from-price-gouging-for-illegitimate-fuel-power-costs/.
132 https://emma.msrb.org/P21441577-P21119174-P21530470.pdf.
133 https://www.yahoo.com/now/brownsville-public-utilities-board-tx-
000816313.html?guccounter=1&guce_referrer=aHR0cHM6Ly93d3cuZ29vZ2xlLmNvbS8&guce_referrer_sig=AQA
AAKwSPg3ZndRfIqbgkl2hbe9Bp-QR7-qBQeINCXN5DbGZX7ha6if6FgC-zfj-
MH4C8Cm4VEnmEnbXQuLSN_vGRLS5rD4CHQS6omLbqtR2gU4g-EFOI257SWf4vyv_mw1ffecwHj5Y91c-
FAtrHN9PwiZ-bVT_v-uZtmDHctJ62UOK.
134 A commitment might result from the sale of energy through a purchased power agreement (PPA), some other
out-of-market bilateral contract between a generator and a counterparty, the sale of generation through a non-
ERCOT market such as the Intercontinental Exchange (ICE), or an award in ERCOT’s formal day-ahead market.

67
a fuel and the owner had exposure to the high natural gas spot prices, the net
impacts would be unclear without more detailed information.
A generation owner whose fleet of generation assets failed to perform well is likely to
have experienced a negative financial impact. To meet obligations through ERCOT’s
formal markets, such an entity may have been required to buy replacement energy at
a price as high as $9,000 per MWh (or higher). It has been reported that the state's
four largest power producers – Vistra, Excelon Corp., NRG Energy Inc., and Calpine —
collectively lost between $2.5 billion and $4 billion due to power plant performance
problems, high natural gas prices, fuel supply constraints, and other problems.135
Many owners of wind generation projects that failed to perform reported deep
financial losses.136,137,138,139,140 Wind generation owners often receive revenue
through financial hedges. Wholesale market prices in excess of contract prices
and/or wind generation below contracted quantities may trigger a payment to a
counter-party (often a financial institution). This has prompted at least one lawsuit
by a wind farm against a financial institution, seeking to avoid payments.141
Owners of natural gas-fueled power plants with performance below expectations
reported losses, including Exelon.142
Natural gas suppliers able to produce and transport natural gas to a market for a sale
based on the spot price profited during the winter week. Natural gas producers
reporting large gains due to the storm include Antero Resources Corp.,143 Comstock

135 Blunt, K, Gold, R. (2021) A Texas-Sized Problem: Overhauling the Power Market --- The February storm
exposed flaws in the state's hands-off approach to electricity. But changes promise to be complex and costly as
lawmakers try to balance reliability and pricing. The Wall Street Journal. April 17, 2021
136 https://www.windpowermonthly.com/article/1707858/texas-blackouts-hit-rwe-renewables-profits.
137 https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/innergex-expects-up-
to-c-60m-financial-hit-from-texas-storms-outages-62715363.
138 https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/rwe-takes-material-
earnings-hit-from-texas-freeze-as-impact-on-europeans-emerges-62756391.
139 https://www.globenewswire.com/news-release/2021/02/24/2181893/0/en/Clearway-Provides-Update-
Regarding-Recent-Texas-Weather-Events.html.
140 https://www.windpowermonthly.com/article/1715644/texas-freeze-lower-european-winds-hit-rwe-q1.
141 https://www.kltv.com/2021/03/12/lawsuit-claims-tx-panhandle-wind-farm-not-financially-responsible-after-
winter-storm-causes-frozen-turbines/.
142 https://www.bloomberg.com/news/articles/2021-02-24/exelon-sees-profit-cut-by-up-to-710-million-from-
texas-cold.
143 https://seekingalpha.com/article/4413442-antero-resources-growth-bug-bites-again.

68
Resources Inc., 144 and Macquiarie Group.145,146 Energy Transfer expects a $2.4 billion
gain,147 and BP reportedly made over $1 billion.148 Kinder Morgan, an owner and
operator of natural gas pipelines, terminals and storage, announced a $1 billion
windfall profit from gas sales during the storm.149 Yet a gas supplier unable to
produce and transport gas, or who was involved in a hedging contract might have not
been so fortunate.
Natural gas local distribution companies (LDCs) generally “pass-through” the
commodity price of gas to ratepayers, such that LDCs’ profits do not change based on
wholesale gas prices. To soften the impact on ratepayers, the pass-through of high
costs due to a price spike may be achieved over some extended period of time and
securitization might be used to reduce debt carrying costs to the benefit of utilities
and their consumers.150 Some LDCs, including Atmos Energy, have reported
challenges in financing the purchase of gas for resale to their customers during and
following the winter event in light of the high prices and extended cost recovery
period.151 Some LDCs also anticipate high billing arrearages, as retail natural gas
customers face utility bills with higher prices for the natural gas commodity.152
Various financial institutions (e.g., banks and financial trading companies) provide
financing and hedges to participants in ERCOT’s markets. The impacts upon
companies in this sector will vary, depending upon the performance of their clients,
the financial viability of their clients, and contractual terms and conditions. There

144 https://theintercept.com/2021/02/23/texas-winter-storm-gas-prices-executives/.
145 https://www.afr.com/companies/financial-services/macquarie-jacks-up-profits-on-texas-big-freeze-
20210222-p574jo.
146 https://www.reuters.com/article/us-macquarie-group-outlook/australias-macquarie-reaps-windfall-profits-
from-u-s-winter-freeze-idUSKBN2AM01O.
147 https://www.bloomberg.com/news/articles/2021-05-06/energy-transfer-made-2-4-billion-gain-from-texas-
winter-storm.
148 https://www.houstonchronicle.com/business/energy/article/BP-likely-made-at-least-1B-during-Texas-power-
16133739.php;
https://www.rigzone.com/news/wire/bp_execs_coy_about_texas_freeze_impact_on_gas_trading-27-apr-2021-
165272-article/.
149 Gerson Freitas, Kinder Morgan Posts Blowout Profit on Texas Winter Storm, Bloomberg. April 22, 202; Harry
Weber, Kinder Morgan gets big first-quarter lift from gas price volatility due to Texas freeze. S&P Global Platts,
April 21, 2021.
150 Bank of America Global Research (2021). GAS LDC 1Q21EPS preview: The day after the storm; measuring the
Feb URI. April 19, 2021. See also, HB1520 which passed in the Texas House on April 20, 2021.
151 https://www.reuters.com/article/us-usa-weather-texas-winners-factbox/factbox-winners-and-losers-in-
energy-sector-from-texas-cold-snap-idUSKBN2AQ260.
152 https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/gas-utilities-face-
unprecedented-test-in-digesting-astronomical-storm-costs-62961274.

69
have been media reports suggesting windfall profits for firms in this sector,153,154
though we have not been able to independently confirm these claims.
The near-term financial impacts on retail customers are dependent upon their
agreements with retail electric providers or other load-serving entities (e.g., rural
electric cooperatives and municipal utility systems). The vast majority of residential
energy consumers in areas of the state opened to retail competition buy electricity
under fixed-price rate plans and may see little impact on their electricity costs in the
near-term. Residential customers on variable pricing plans may have received
unusually high electric bills, as widely reported in the media. Over time, an increase
in wholesale electricity prices tends to get partially passed-through to the prices
quoted in new or renewed retail electricity offers from retailers (Hartley et al., 2019,
Brown et al., 2020).

153 Chung, J, Blunt, K. (2021). Texas Storm is a Windfall for some Wall Street Firms. The Wall Street Journal.
April.
154 Meyer, G., Noonan, L., Bank of America reaps trading windfall during Texas blackouts, Financial Times, March
5, 2021, at: https://www.ft.com/content/321c4fb2-ca11-4e15-9ef5-05598dd04012.

70
4. A Comparison to Winter Events in
2011 and 1989
It is instructive to compare the electricity industry’s performance during the February
deep freeze to the two earlier winter events which led to electrical outages in the
ERCOT grid:
 December 1989
 Early February of 2011.

4.1. December 1989 Winter Event
During December 21-23, 1989, the weather was similarly cold as compared to mid-
February of 2021. The low temperature in Austin was the same during both events.
The low in Dallas was just 1ᴼF colder in 2021 than in 1989. Houston reached a low
temperature of 7ᴼF during the 1989 winter event, or 6ᴼF lower than the low
temperature reached in Houston in 2021.
However, the electricity industry in Texas was far different in 1989. It was dominated
by vertically-integrated electric utilities in 1989, and there was little market-wide
control over operations.
Months before the 1989 winter event, the PUCT staff warned of reliability concerns
associated with ERCOT’s high reliance on natural gas for electricity generation, which
represented 53% of the generation mix in 1989.155
Dependence on natural gas in the ERCOT generation mix (almost three times
the national dependence) represents some reliability concern. … if severe
winter conditions were to occur, there could be curtailment of gas supply for
generating units. If such curtailment does occur and it becomes necessary to
substitute fuel oil for gas, the rated capability of some units will be reduced
due to equipment design, pipeline delivery constraints and/or oil
inventories.156
During the December 1989 winter storm, demand for electricity increased, along
with the demand for natural gas for space heating. Weather-related equipment
problems caused generating units to go offline. Power plant outages were traced to
frozen instruments, frozen valves, boiler tube leaks, frozen batteries, and fish
plugging cooling water intakes. Consistent with the concerns expressed by the PUCT
staff earlier in the year, natural gas flows were curtailed by Lone Star Gas to the

155 Public Utility Commission of Texas, Long-Term Electric Peak Demand and Capacity Resource Forecast for
Texas, 1988, Volume I: Summary of Results and Recommendations, Feb. 1989, p. 6.6.
156 Public Utility Commission of Texas, Long-Term Electric Peak Demand and Capacity Resource Forecast for
Texas, 1988, Volume I: Summary of Results and Recommendations, Feb. 1989, p. 6.7.

71
utilities in North Texas in early hours of December 21st, and many utilities serving
South Texas lost their natural gas supplies the following morning. There was firm
load shed of 1,710 MW (4.5% of peak load) on December 23rd, 1989. “Rolling”
blackouts were achieved, lasting less than 10 hours for any given region, and
different regions of ERCOT experienced different durations of outages. System
frequency remained above 59.65 Hz throughout the event. At the time, the 1990
PUCT report on the 1989 winter event stated that “The combination of heavy
demand and loss of generating units caused near loss of the entire ERCOT electric
grid.157 We now know the generator outages and blackouts were far smaller in
magnitude than the outages in February 2021.
The financial impacts of the December 1989 event were quite modest in contrast to
later events. Natural gas prices remained fairly stable in December 1989, as did retail
electricity prices. The PUCT reviewed the costs incurred by the utilities under its
jurisdiction and approved recovery of those costs determined to be reasonable and
necessary and prudently-incurred. The utilities reported that corrective actions
would involve costs of less than $3 million (which did not include costs that might be
incurred by non-utility generators).158

4.2. February 2011 Winter Event
During the first week of February 2011, unusually cold and windy weather prevailed
over the southwest U.S. While the weather was not as severe as during the winter
events in 1989 and 2021, it nonetheless triggered similar problems. The FERC 2011
summary report of the winter event noted a total of 210 individual generating units
in ERCOT experienced either an outage, a derate, or a failure to start, leading to a
controlled load shed of 4,000 MW, affecting 3.2 million customers (FERC, 2011).159
The FERC 2011 summary report also noted “... 193 ERCOT generating units failed or
were derated, representing a cumulative loss of 29,729 MW” that was not a
simultaneous outage in capacity and a peak of 14,702 MW in “... generation offline
from such trips, derates, or failures to start.” Thus, approximately one-third of
ERCOT’s total generation fleet was unavailable at the lowest point of the event.160
Generation loss involved units of all ages and multiple types of fuel.161 The Texas

157 Public Utility Commission of Texas, Electric Division Evaluation Report, Electric Utility Response to the
Winter Freeze of December 21 to December 23, 1989, November 1990.
158 Electric Division Evaluation Report, Electric Utility Response to the Winter Freeze, Public Utility Commission of
Texas, November 1990.
159 FERC/NERC (2011), p. 1.
160 FERC/NERC (2011), p. 7.
161 Trip Doggett, ERCOT CEO (2011), ERCOT Presentation to Joint Senate Committees, February 2, 2011 Grid
Emergency Events. February. Slide 10.
http://www.ercot.com/content/news/presentations/2011/Senate_EEA_Presentationfinaltg.pdf

72
Reliability Entity (TRE) report on the same blackout noted “... a total of 225 individual
generator units experienced a unit trip, a unit de-rate, or a failure to start …”
resulting “... in a maximum of 14,855 Megawatts (MW) of unplanned unavailable
capacity during the period. These generation issues, combined with pre-scheduled
generation outages of 12,413 MW, created a significant generation capacity shortfall
in the ERCOT Region.” (TRE, 2011) We do not have an explanation for these
variations in the number of generator outages within the FERC report and between
the FERC and TRE reports, but they are within about 30 generation units. Both FERC
and TRE noted very similar forced outages and derates of 14,702 MW and 14,855
MW, respectively.
On February 2, 2011, wholesale market prices reached the offer cap, which had
recently been increased to $3,000 per MWh. The EEA Level 3 lasted from 5:43 a.m.
to 2:01 p.m. on that day.162 Frequency remained above 59.5 Hz throughout the
event.163
The natural gas system could not meet demand. The production losses stemmed
principally from freeze-offs, icy roads, and electric outages to the equipment used in
the natural gas industry. Electric blackouts called by ERCOT and implemented by the
TDSPs along with customer electrical curtailments for other reasons caused or
contributed to 29% of the natural gas production outages in the Permian basin and
37% of the natural gas production outages in the Fort Worth basin.164 These outages
prevented the operation of electric pumping units and compressors on gas gathering
lines.
The FERC/NERC inquiry into the 2011 events concluded that gas shortages were not a
significant cause of the electric generator problems during that event, nor were
rolling electrical blackouts a primary cause of the production declines at the
wellhead. Nonetheless, this gas and electric interdependency was a contributing
factor.165
In response to the 2011 event, the 2011 session of the Texas legislature passed a law
requiring the PUCT to analyze the preparedness of power plants for extreme weather
events as in Section 186.007 of the Texas Utilities Code.166 The statute required that

162 Kent Saathoff of ERCOT Staff (2011), TDSP Curtailment Procedures and Service Restoration Priorities Plan,
slide 4.
http://www.ercot.com/content/news/presentations/2011/TDU%20curtailment%20workshop%20PUC%2011-3-
11.pdf.
163 Kent Saathoff of ERCOT Staff (2011), TDU Curtailment Procedures and Service Restoration Priorities Plan, slide
5. http://www.ercot.com/content/news/presentations/2011/TDU%20curtailment%20workshop%20PUC%2011-
3-11.pdf.
164 FERC/NERC (2011), p. 9.
165 FERC/NERC (2011), p, 11.
166 Texas Util. Code Section 186.007.

73
power plants submit information to the PUCT about their readiness for extreme
weather events, and that the PUCT prepare a report on “power generation
weatherization preparedness.” More specifically, the statute required the PUCT to
“analyze and determine the ability of the electric grid to withstand extreme weather
events in the upcoming year” considering anticipated weather patterns. The law also
authorizes the PUCT to enact rules relating to the implementation of the
weatherization report, and to require power plants to amend inadequate
weatherization plans. The PUCT enacted Substantive Rule 25.53 in response to the
2011 legislation.167 The 2011 law states that this weatherization review process must
result in a report by the end of September 2012, but subsequent reports could be
filed as deemed necessary. The 2011 law does not explicitly require annual
weatherization reports. To date only one report, in 2012, has been filed by the PUCT
under Section 186.007, and this 2012 report, written by Quanta Technologies, LLC,
identified best practices for winterizing power plants and winterization shortcomings
at ERCOT plants.168 We could not verify whether ERCOT generators implemented
those recommendations, or whether the PUCT followed up with generators in
connection with those recommendations. ERCOT, however, has held annual “winter
weatherization workshops.” including a September 2020 workshop that featured
winter weather forecasts for 2020-21.169

4.3. Comparison of the Three Events
Table 4.a summarizes key indicators for comparison of the 1989, 2011, and 2021
winter events that triggered power outages in ERCOT. Caution must be exercised,
however, when drawing any conclusions based on a comparison of these three
events. The generation fleet has evolved over time. We have less reliance on coal
and greater reliance upon renewable energy resources today. Moreover, the electric
and natural gas industries have evolved over the past 32 years. Yet, some
observations can be made.
Each of the three winter storms resulted in customer outages or blackouts. During
each event, weather-related problems forced outages and de-ratings at power plants
and the availability of natural gas to gas-fired power plants was a notable problem.
But these were otherwise very different events. The extent and duration of the
outages were far greater in 2021. We are unaware of any loss of life being linked to
the electrical outages in 1989 and 2011.

167 https://www.puc.texas.gov/agency/rulesnlaws/subrules/electric/25.53/25.53ei.aspx.
168 Report on Extreme Weather Preparedness, Best Practices, Quanta Technologies, LLC (September 27, 2012),
pp. 7-18.
169 FN--ERCOT and Texas RE Generator Winter Weatherization Workshop by (Webex Only), URL:
www.ercot.com/calendar/2020/9/3/210162.

74
Table 4.a Summary of key metrics summarizing the severity of the 1989, 2011, and 2021 winter storms causing
significant power generation outages and derates, load shedding, and low frequency conditions in ERCOT.
Descriptor Dec. 1989a Feb. 2011 Feb. 2021
Peak Load Estimated w/o
load shed (MW) ~ 38,000 + 1,710 59,000#
76,819
(estimated by
ERCOT)
Maximum load shed
(MW)
1,710
4.3% of peak load
~4,900
8.3% of peak load
20,000
26% of peak load
Peak forced and planned
Generation Outage as
nameplate Capacity
(MW)
(planned outage in
parenthesis)
~ 13,000
(not necessarily
simultaneous, unable to
determine peak simultaneous
outage)
~ 27,200
(12,413)
52,037
(ERCOT, 2021a)
Generation units
experiencing an outage
(number)
86 193 to 225170 ~ 585
Customers (meters)
without power (millions)
not quantified in 1990 PUCT
report 3.2 ~ 4.5
(Busby et al., 2021)
Duration of EEA Level 3
condition (hours)
0-9 hours of load shed spread
over two different intervals
(depending on region)^
~8 ~105
Lowest Grid Frequency
(Hz) 59.65 59.576 59.302
Natural Gas flows were
curtailed to electric
utilities and/or
generation units before
and during blackouts
Yes
(< ~1,000 MW)
Yes
(1,282 MW)*
Yes
(6,700 MW at peak)
Did TDSPs cut off
electricity supply to
natural gas
infrastructure?
unknown Yes Yes
a: Information from PUCT (1989).
#: Figure 2 of Potomac Economics (2011).
^: The Emergency Energy Alert (EEA) system did not exist in 1989. ERCOT requested utilities enact
Emergency Electric Curtailment Plans (EECP) from Dec. 22, 8:40 am -12:00/12:30 pm (for North &
South Texas) and Dec. 23, 6:40 am – 12:40 pm. Utilities reported firm load shedding as occurring on
December 23 for: 4 hours (Houston Power & Light), 3.6 hours (City Public Service San Antonio), 2.5
hours (Lower Colorado River Authority).
*: FERC (2011), page 191.

170 FERC (2011) report states "But over the course of that day and the next, a total of 193 ERCOT generating units
failed or were derated, representing a cumulative loss of 29,729 MW." The Texas RE report states the number of
failed or derated generating units was 225.

75
The 1989 event preceded the introduction of competitive generation and retail
markets in ERCOT. The PUCT was able to review the costs incurred by the utilities
under its jurisdiction and approve recovery of winterization investments through
rates of those costs determined to be reasonable and necessary and prudently-
incurred. These post-freeze winterization investments were estimated in the millions
of dollars in aggregate (PUCT, 1990). Natural gas prices remained stable throughout
the event. There were no significant “wealth transfers” between electricity suppliers
and retailers or between industries.
During the 2011 event, the market structure in ERCOT was similar to today’s market
structure. A nodal wholesale market structure had been introduced in December
2010 – two months prior to the event. Yet, the wholesale offer cap was a much-
lower $3,000 per MWh during the 2011 event – one-third of what it is in 2021. As
during the 1989 event, natural gas prices remained fairly stable, in contrast to the
extreme spike in gas prices experienced in 2021. The financial impacts of the 2011
event received relatively little attention, and we are unaware of data or published
estimates of financial impacts.
Ninety-six of the 585 generating units (16.4%) in ERCOT that reported outages or
deratings during the winter event in February 2021 also experienced problems
during the February 2011 event.171 This includes four coal-fired generating units
which were operated at reduced output levels during the 2021 emergency.172
Eight generating units experienced outages or de-ratings during each of the three
winter emergencies of 1989, 2011, and 2021. For example, the large Limestone
coal/lignite Unit 1 (presently owned by NRG Texas Power LLC) reported problems
from low feedwater flow and frozen instruments in 1989, experienced problems in
2011, and was partially de-rated during the winter storm of February 2021. The
other seven generating units reporting outages or deratings during all three events
were relatively small natural gas-fired combustion turbines or cogeneration
facilities.173 However, this comparison of performance of plants during the three
events has limited value, since many power plants in operation today and in 2011
were built after 1989.

171 Sources: http://www.ercot.com/content/wcm/lists/226521/Unit_Outage_Data_20210312.xlsx and
PUCT Project No. 27706, filing by ERCOT, Attachment A.
172 Calaveras Unit JKS2, Oak Grove SES Unit1A, Oak Grove SES Unit2, and Limestone Unit LEG_G1.
173 These are Air Liquide’s Bayou Cogen station’s units G2 and G4; Unit1A at Luminant’s Stryker Creek plant; Unit
7 at Luminant’s Mountain Creek facility; CT4 at Luminant’s Morgan Creek plant; and two very small gas turbines
at the TH Wharton and WA Parish plants, which are presently owned by NRG Texas Power LLC. Based on
publicly-available sources: PUCT Project No. 27706, filing by ERCOT, Attachment A; PUCT (1990); and
http://www.ercot.com/content/wcm/lists/226521/Unit_Outage_Data_20210312.xlsx

76
5. Summary
The Energy Institute at the University of Texas at Austin assembled a team of faculty
and researchers to identify and review credible sources of data in an attempt to
provide a factual account of what happened and what went wrong during the winter
disaster. Our hope is that this analysis will provide a reasonable basis for subsequent
policy decisions designed to improve the performance and resilience of the State’s
energy systems.
Because of time constraints, data limitations, and the intention to limit the report
scope to events and data rather than recommendations, many questions have been
left unanswered. For example, we did not analyze the sequences of rolling outages
(e.g., on a circuit-by-circuit basis), and we do not yet have a good understanding of
what it might take to deploy advanced metering systems to achieve customer
outages in a more “rolling” and “surgical” manner than occurred during the 2021
event. We also did not explore whether any natural gas infrastructure facilities were
committed to providing an ancillary service during the event, but were unable to
perform due to a disruption in their electricity supply.
Our understanding of natural gas flows during the event is incomplete, despite
having acquired and analyzed a proprietary source of natural gas data. For example,
even without weather-related equipment failures, it is unknown to what level of
peak flow rate and duration the Texas natural gas system can deliver natural gas
demand to all customers during a winter event such as Winter Storm Uri. A full
understanding of the hedging positions and out-of-market contractual agreements
among ERCOT market participants will probably never be known given the
confidentiality surrounding such agreements, thus limiting our understanding of the
full economic consequences of the event. Robust estimations of the cost of better-
winterizing the energy supply system will require further site-specific analysis.
It is our hope that subsequent studies – by The University of Texas, other universities,
FERC, NERC, and other organizations – may be able to make progress in these areas.
We have intentionally avoided making policy recommendations in this report. Once
policy directions are better-established, we would be pleased to contribute analysis
designed to explore implementation strategies, the impacts of various policy options,
and related issues.
We note that while we were completing this report, the Texas Legislature passed
multiple bills in response to the February event, including Senate Bills 2 and 3. These
bills focus on weatherization of infrastructure as well as the governance of the grid
operator and regulator. Other bills in the 2021 session, such as House Bill 4492,
focus on the financial impacts of the winter storm.

77
Acknowledgements
This work was funded by the Public Utility Commission of Texas (PUCT) through an
interagency transfer to the University of Texas at Austin. The PUCT reviewed a pre-
release draft of this report to ensure that no confidential information was disclosed,
but did not otherwise influence the content or findings from this analysis.

78
Conflict of Interest Statements
Various participants in the state’s natural gas and electricity markets fund research at
The University of Texas, and some contributors to this report provide consulting
assistance to companies or organizations involved in the energy industry. Disclosures
of any relationships that might be perceived to introduce a conflict of interest may be
found via the UT Energy Institute and at: https://energy.utexas.edu/ercot-blackout-
2021.

79
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Appendix A. Short History of Texas
Electric Grid and ERCOT: From the
Beginning to 2021
The current infrastructure, rules, regulations, and organizational roles impacting the
ERCOT market are the outcome of many decisions made over multiple decades.
Here, we provide a brief history of these decisions to place the ERCOT outages of
service in February 2021 in historical context.
For shorthand in this report, we use the acronym “ERCOT” to possibly refer to the
wholesale electricity market, the infrastructure that generates and/or delivers
electricity, and ERCOT the organization. ERCOT the organization does not own the
electricity infrastructure (i.e., power plants, transmission and distribution lines,
battery storage) within the ERCOT grid. The grid infrastructure is owned by the
generation companies who participate in the market and by transmission and
distribution utilities. ERCOT the organization administers the day-to-day electricity
market operations and performs transmission planning. The PUCT oversees ERCOT
the organization to ensure that it and the market participants comply with the
legislative intent and law.
A.1. Why Does Texas Have Its Own Grid?
Electric power development began in the late 1800s as small power plants and local
wires were installed in cities across the U.S., including Texas cities. By nature, they
were isolated, but eventually grew enough to establish connections among
themselves.
The 1935 Federal Power Act established federal jurisdiction over interstate
commerce via the Federal Power Commission (FPC), which has since become the
Federal Energy Regulatory Commission (FERC). The Public Utilities Holding Company
Act (PUHCA) of 1935 created individual companies – utilities – with contiguous
service territories. Each utility would act as a monopoly to serve customers within its
geographic territory, and in return electricity rates and profits would be subject to
state-level approval. PUHCA provided the framework for all electricity service until
some regions restructured, or “deregulated,” beginning in the 1990s (Tuttle et al.,
2016).
Local city grids continued to link to each other, and by the beginning of World War II,
the Texas Interconnection System was formed (Cohn, 2017). “Faced with the threat
of federal regulation in the wake of the 1935 passage of the Federal Power Act, the
principal utilities in Texas … elected to isolate their properties from interstate
commerce” (Cudahy, 1995).
In 1965, “North America experienced its worst blackout to date as 30 million lost
power in the northeastern United States and southeastern Ontario, Canada” (NERC,

83
2019). In response, Congress passed the Electric Power Reliability Act in 1967 that
led the electricity industry to form the National Electric Reliability Council in 1968,
now known as the North American Electric Reliability Corporation (NERC). NERC is a
council of regional electricity coordination organizations. In the wake of these
changes in federal and national level coordination, in 1970 the utilities operating
exclusively within Texas set up their own reliability council named the Electric
Reliability Council of Texas, or ERCOT.
The question of electrical isolation of ERCOT utilities was not considered until 1974
when an Oklahoma attorney “… filed a motion with the SEC on behalf of a group of
municipal and cooperative electric distribution systems served by Oklahoma Public
Service” (OPS) (Cudahy, 1995). OPS was one of four utilities owned by Central and
Southwest Corporation (CSW). CSW174 owned utilities that spanned areas of
Oklahoma, Louisiana, Arkansas, and Texas (Cudahy, 1995). A four-year legal battle
ensued between CSW and the existing, purely Texas-based, utilities. The dispute was
whether to allow utilities to sell or generate electricity within ERCOT from/to states
besides Texas and become subject to interstate commerce federal regulatory
jurisdiction. CSW wanted electrical connections to transfer electricity to and from
Texas, and the ERCOT-only utilities did not.
These battles affected language in the federal Public Utility Regulatory Policies Act
(PURPA) of 1978, and the right of the newly formed Federal Energy Regulatory
Commission (FERC) to force utilities to interconnect, for example during
emergencies, without triggering FERC jurisdiction for other purposes, for example
the review of wholesale electricity rates (Cudahy, 1995). Following the passage of
PURPA, the utilities in dispute negotiated a settlement. “They finally settled upon a
direct current [DC] interconnection [between ERCOT and SPP,175 or other states]
because, unlike an alternating current tie, the power flows over a direct-current link
could be controlled. … The parties agreed to other terms as well, notably that the
interconnection would not subject ERCOT to federal regulation for other purposes”
(Cudahy, 1995). As a result, CSW maintained interconnection across its companies in
multiple states, and the ERCOT-only utilities retained state regulation but not federal
regulation.

174 CSW own[ed] all the common stock of four vertically integrated operating utilities: Central Power and light
Company (Central Power), headquartered in Corpus Christi in South Texas; West Texas Utilities Company (West
Texas), headquartered in Abilene in West Texas; Public Service Company of Oklahoma (Oklahoma Public Service),
headquartered in Tulsa, Oklahoma; and Southwestern Electric Power Company (Southwestern), serving Arkansas,
Texas and Louisiana and headquartered in Shreveport, Louisiana.” CSW later was merged into American Electric
Power, Inc. in 2000 (AEP, 2021)
175 Southwest Power Pool.

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A.2. Wholesale Market Restructuring (Deregulation) and Adjustment Timeline
In 1995 the Texas Legislature passed Senate Bill 373 to restructure the electric
generation sector in ERCOT. The bill ensured equal access to the transmission grid
for power generators and established ERCOT as the Independent System Operator
(ISO) in 1996, the first ISO in the U.S. although its initial functions were very limited
relative to today’s ISOs. Before this time, ERCOT was only the reliability coordinator
that reported to NERC (ERCOT, 2016). “Additional objectives of SB 373 were to
ensure an equitable interconnection process, facilitate generation capacity and
transmission expansion, and provide customer protection.”176 (Adib and Clark, 1996)
In addition to further restructuring wholesale power generation, Texas SB 7 in 1999
ordered the introduction of retail competition in the service areas of the investor-
owned utilities within the ERCOT power region by 2002. By 2002 the investor-owned
utilities in the ERCOT power region which were previously vertically-integrated were
“unbundled,” or separated, into three separate entities: power generation,
transmission and distribution utilities, and retail electric providers (REPs). Rural
electric cooperatives and municipal utility systems were permitted to either
participate in retail competition (“opt in”) or decline to participate, although changes
in the wholesale market would affect them regardless of their decision.177
Prior to restructuring, generation dispatch decisions and other operational decisions
were made locally in ten control areas. However, ERCOT transitioned to operating as
a single control area under the legislative framework established through SB 373 (in
1995) and SB 7 (in 1999).178
While markets were developed for wholesale generation and retail activities,
investor-owned TDSPs remain under conventional regulatory oversight.
SB 7 also gave the PUCT authority over market oversight, including oversight of
ERCOT. SB 7 sought prevent the exercise of market power, including the provision
that no single generation company can control more than 20% of the total installed
generation capacity.179 Via ERCOT’s bylaws (as an ISO) and authority of the PUCT, a
stakeholder process provides the opportunity for stakeholders (generators, TDSPs,
consumer groups, etc.) to participate in the design and operation of the electricity
market.
SB 7 set a Texas renewable portfolio standard (RPS) of 2,880 MW (adding 2,000 MW
to 880 MW of existing capacity) of renewables and created a renewable energy

176 For SB 373, see: https://capitol.texas.gov/BillLookup/Text.aspx?LegSess=74R&Bill=SB373.
177 See SB 7 (https://capitol.texas.gov/BillLookup/Text.aspx?LegSess=76R&Bill=SB7) Sec. 41.051 (cooperatives)
and Sec. 40.051 (municipal utilities).
178 http://www.ercot.com/news/releases/show/77
179 Luminant (a subsidiary of Vistra) owns almost 20% of generation in ERCOT.

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credit (REC) market to facilitate that standard. In 2005, Texas legislators increased
the RPS to 5,880 MW of renewable capacity, and via SB 408 directed the PUCT to
facilitate the process to design and construct new transmission to serve a set of
“Competitive Renewable Energy Zones” (CREZ). As of the end of 2020,
approximately 25,000 MW of wind and 4,000 MW of solar photovoltaic capacity
were installed in ERCOT, thus far surpassing the RPS.180
Table A.1. Timeline of the Evolution of a Competitive Market in ERCOT181
1975 Passage of the Texas Public Utility Regulatory Act (PURA),
establishing the PUCT.
1978 The federal Public Utility Regulatory Policy Act (PURPA) is
enacted, facilitating and providing a pricing mechanism for utility
purchases of power from cogeneration and small power
production.
1983 Amendments to the Texas PURA to reflect the 1978 enactment of
PURPA and introduction of the elements of integrated resource
planning, such as a ten-year demand and resource forecast. The
PUCT is no longer responsible for forecasts and planning for
electric grid investments.
1992 The passage of the US Energy Policy Act.
1995 State Legislature passes Senate Bill 373 amending the Texas PURA
to introduce wholesale competition in September 1995.
February 1996 The Commission establishes the requirement for ERCOT to
become an Independent System Operator (ISO) and requires
utilities to offer wholesale open-access transmission service.
Late 1990s The PUCT approved an interconnection rule to facilitate
merchant plant development.
May 1999 State Legislature passes Senate Bill 7 amending the Texas PURA
to introduce retail competition on January 1, 2002 and further
restructure the wholesale market.
2000-2001 The PUCT finalized its decision regarding functional unbundling
plans for integrated utilities. In addition, the Commission

180 See ERCOT “Resource Capacity Trend Charts” at http://www.ercot.com/gridinfo/resource (e.g, December
2020:
http://www.ercot.com/content/wcm/lists/219848/Capacity_Changes_by_Fuel_Type_Charts_December_2020.xls
x).
181 Some information included in this table is from Adib and Zarnikau (2007).

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finalized several important rules to enhance the transition to
competition within ERCOT.
August 2000 The PUCT established Wholesale Market Oversight to monitor
market activities and detect market power abuses and other
market manipulation.
June 4, 2001 The PUCT finalized its decision with regard to the ERCOT
Protocols that established market rules for the wholesale
electricity market.
July 31, 2001 The operation of the ERCOT single control area began and a pilot
retail program was introduced.
January 1, 2002 Customer choice began within ERCOT electricity market and
“price to beat” was established within each incumbent investor-
owned-utility service area and became effective for residential
and small commercial customers with peak load lower than 1
MW.
September 2002 Retail Market Oversight was established to monitor the retail
market and identify areas for improvements.
February 2003 Price spikes in wholesale market prompt re-examination of the
use of balancing energy, wholesale price mitigations formulas,
and credit requirements for REPs.
Late 2004 Switching rates for commercial energy consumers exceeds
thresholds and the “price to beat” for commercial customers is
terminated in many service areas.
September 2005 PUCT decides to transition market to a nodal structure.
2005 Texas Legislature adopts SB 408 designating the creation of
Competitive Renewable Energy Zones and provides authority to
PUCT to direct ERCOT to plan for transmission to connect
approximately 18 GW of wind capacity.
2005 The legislature adopts SB 408 that increases the number of
independent representatives on ERCOT’s board and designates
an independent monitor for the wholesale electricity market182.
August 2006 The PUCT approves rules (Subst. R. §25.505) for “scarcity pricing”
with new energy offer caps.

182 SB 408 (79R Legislative session in 2005):
https://capitol.texas.gov/BillLookup/Text.aspx?LegSess=79R&Bill=SB408.

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2010 On December 1, the nodal wholesale pricing system goes live
approximately four years after initially planned. Along with nodal
pricing comes the “day ahead market” for individual power
plants to bid for next-day electricity generation on a 15-minute
basis.
October 2012 PUCT approves a timeline to gradually increase the energy offer
cap to $9,000 per MWh through amendments to Subst. R.
§25.505.
June 2014 Operating Reserve Demand Curve (ORDC) is first implemented, to
raise energy prices when physical operating reserves are low.
January 2019 The PUCT orders a shift in the ORDC to increase energy prices
further when operating reserves dwindle. PUCT also decides to
implement real-time co-optimization in the selection and pricing
of energy and ancillary services in the wholesale market.183
March 2020 A further shift in the ORDC is implemented.

A.3. Why isn’t ERCOT Connected to Other Grids?
Previous paragraphs summarize the history of the ERCOT grid as separate from
others in North America. However, the costs and benefits of interconnecting ERCOT
with neighboring reliability councils were studied in the late 1990s, per a request by
the Texas Legislature.184 The established Synchronous Interconnection Committee
(SIC) failed to reach a definitive conclusion regarding whether the benefits of
interconnection would likely outweigh the costs:
Due to the complexities of the issues and uncertainties surrounding the
evolving electric marketplace, the SIC was unable to conclusively establish
that AC interconnection is, or is not, desirable either as a candidate
transmission investment or as an instrument of policy to promote competition
in future electricity markets.185
It is possible that a similar analysis today would yield differing results, as questions
remain surrounding the costs and benefits of greater interconnection with
neighboring markets or reliability councils.

183 See PUCT Project No. 48540.
184 Per SB 373 (74th legislative session in 1995).
185 SIC, 1999, cover letter.

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A.4. Today’s ERCOT Wholesale Market
Today, ERCOT serves 90% of the electric load in Texas. This power region has
experienced consistent load growth in recent decades due to a strong economy and
increasing population, unlike some other U.S. markets which have experienced little
growth. Currently, 26 million people within Texas receive electric service via the
electric grid managed by ERCOT.
ERCOT administers day-ahead and real-time markets for energy, as well as a day-
ahead market for ancillary services (AS). ERCOT is relatively unique in that it is an
“energy-only market” and thus does not operate a capacity market or impose
resource adequacy targets in order to maintain a target reserve margin.186 Market
forces are heavily relied upon to provide enough generation for resource adequacy,
and market price offer caps have been raised to relatively high levels in hopes of
providing sufficient compensation to the generation sector to incentivize investment
to meet peak electricity demand. The price offer cap has increased almost 10-fold
over a span of 13 years to $9,000/MWh. While normal market operations can push
prices to scarcity levels, multiple price add-ons have been developed to increase
prices when reserves are low or emergency reliability actions have been taken.
ERCOT retains only a few small direct current (DC) interconnections with neighboring
markets and reliability councils, and remains a fully intrastate system with limited
federal jurisdiction over its market.
A.5. Characteristics of the ERCOT Retail market
Of the approximately 11 million metered customers in ERCOT, 187 about 8 million
have retail choice and can select among different retail electric providers offering
different electricity pricing plans and services.
Efforts to introduce competition into the retail sector of the state’s electricity market
began in June 1999 with the passage of Senate Bill 7 (SB 7) by the Texas Legislature.
SB 7 permitted retail competition in the service areas of the investor-owned electric
utilities within ERCOT’s power region on a commercial basis beginning January 1,
2002. These service areas, identified in Figure A.1., include two of the nation’s ten
largest metropolitan areas – Dallas/Fort Worth and Houston. New entrants were
permitted to compete with retail arms of five utilities that were formerly vertically-
integrated: Houston Lighting and Power Company, TXU Electric, AEP-Texas North,
AEP-Texas Central, and Texas-New Mexico Power Company. Oncor became the TDSP
successor to TXU Electric, while CenterPoint Energy is the TDSP successor to Houston
Lighting and Power Company.

186 Other “energy only” markets include electricity markets in Alberta and Australia.
187 http://www.ercot.com/content/wcm/lists/219736/ERCOT_Fact_Sheet_1.04.21.pdf

89

Figure A.1. Areas Initially Opened to Retail Competition. Source: PUCT at:
https://www.puc.texas.gov/industry/maps/maps/tdumap.pdf.

At the start of retail competition in 2002, certain constraints were placed upon the
prices charged by the five retailers that were successors of former vertically-
integrated utilities (then known as the AREPs, or affiliated retail electric providers).
After January 1, 2005, the AREPs were allowed to provide alternative prices to their
customers, provided these alternative pricing plans did not exceed the “price to
beat” (PTB) set by the PUCT. By December 2007, approximately 40 percent of
residential customers in areas exposed to retail competition had switched to a
competitive retailer – i.e., a retailer other than one that was a successor to one of
the former vertically-integrated utilities – or a different AREP. On January 1, 2007,
PTB constraints fully expired, removing any regulatory oversight over retail prices.
The outcome was an overall reduction in average prices (Zarnikau and Kang, 2009;
Swadley and Yucel, 2011).
Before retail choice was implemented in Texas, Direct Energy entered the Texas retail
market by purchasing the retail branches of AEP-Texas North and AEP-Texas Central
(formerly known as West Texas Utilities and Central Power and Light). Another of the
five original AREPs changed ownership when Reliant Energy – a successor of Houston

90
Lighting and Power Company – was acquired by NRG Energy in 2009.188 In 2011,
Direct Energy acquired another original AREP – First Choice Power, the retail affiliate
of Texas-New Mexico Power Company.189 The last remaining AREP, TXU Energy, was
acquired by a group of private investors (led by KKR, TPG Capital, and Goldman
Sachs) in 2007. Following a bankruptcy in 2013, TXU Energy and its generation
affiliate (Luminant) were renamed as Vistra Energy in 2016.190
In recent months, following the merger of NRG Energy and Direct Energy, concerns
have been raised over market concentration in ERCOT’s retail market. After the
completion of the merger on January 2, 2021, NRG Energy and Vistra control about
78% of the residential retail market, though concentration in other market sectors
(e.g., commercial and industrial market segments) is lower (Brown, et al, 2020).
On the competitive retail side, the 2021 winter event has reduced the number of
retailers. Griddy Energy, Entrust Energy, and Power of Texas Holdings have left the
market and Just Energy Group has filed for bankruptcy. By February 24, 2021, the
number of competitive rate options advertised on the PUCT-administered Power to
Choose website had dropped by half.191 A departure of retailers from the market has
occurred in the past,192 but the number of retailers that have left the market recently
is unprecedented.

A.6. Summary: ERCOT History and Current Status
The ERCOT grid and ERCOT the organization have changed considerably since the
Texas legislators ordered restructuring of wholesale markets. Wind and solar
generation were practically zero in 1999, but amounted to 25% of the 381 terawatt-
hours (TWh) of generation in 2020 (Figure A.2) Natural gas generators have provided
40-46% of generation during the last 15 years, while coal generation had declined
from 40% in 2010 to less than 20% in 2020. There are currently no plans to build
new nuclear power plants in ERCOT.

188 https://en.wikipedia.org/wiki/NRG_Energy; https://www.power-grid.com/td/nrg-energy-to-acquire-reliant-
energys-texas-retail-business/#gref
189 https://www.prnewswire.com/news-releases/direct-energy-to-acquire-first-choice-power-for-270-million-
130411228.html
190 https://www.txu.com/company/why-txu-energy/about-us.aspx;
https://www.dallasnews.com/business/energy/2016/11/04/luminant-and-txu-energy-have-a-newly-named-
corporate-parent-vistra/
191 Based on calculations performed by Hen-Hao Tsai, a former researcher at UT-Austin who is now employed by
MISO. Communicated via email to Jay Zarnikau on Feb. 24, 2021.
192 Based on ERCOT’s public notices, retailers that have left the market prior to 2021 include: Texas Commercial
Energy (2003), Utility Choice Electric (2004), Ampro (2006), Buy Energy (2006), Franklin Power (2005), Blu Power
of Texas (2008), Hwy 3 MHP (2008), Sure Electric (2008), Pre-Buy Electric (2008), National Power Company
(2008), Abacus Resource Energy (2011), EPCOT Electric (2012), TexRep7 LLC (2012), Reach Energy (2014), Proton
Energy (2014), and Reach Energy (2014).

91

Figure A.2. The percentage of annual electricity generation in ERCOT, by fuel, from 2006-2020

92
Appendix B. Internal ERCOT
Meteorological Discussions Before the
Storm
To help forecast electricity demand or “load” and make other preparations for day-
to-day grid operations, ERCOT utilizes multiple weather models, NOAA forecasts, as
well as data from outside weather vendors to inform their internal predictions about
short and long-term weather across the state. Communications between the
resident meteorologist and various planning, outage, and resource groups at ERCOT
indicate the difficulty in forecasting the onset and severity of Winter Storm Uri of
2021. These day-to-day communications are internal to ERCOT, but ERCOT issues
outside communications to market participants to warn of major weather events
that could impact market operations.
Of the internal ERCOT emails we reviewed; one written January 28 was the first
mention that ERCOT would experience a spate of cold weather. This e-mail noted
that February is that hardest month to forecast, but that there was evidence that
February 2021 would be colder than normal. Another email on February 1 indicated
that a polar vortex was working, but it was likely to be pushed east of Texas. On
February 3, an email indicated that there was a good chance that February was going
to be the coldest weather of the 2020/2021 winter, but the models used for
predictions were varying widely with forecasted lows for Austin varying between
19oF and 53oF on February 8. By February 4 the various models were converging on
Dallas and Austin seeing their coldest weather of the year, with a good chance of
Houston and possibly for Brownsville also seeing their coldest temperatures of the
year. On February 5, the models began to diverge on the timing of when the cold air
masses will arrive in Texas. The February 6 weather update compares the coming
cold to January 2018 in severity. The February 7 update explained that the models
were still 20-30 degrees apart in their temperature predictions with the coldest
model showing cold weather similar to January 2018.
By February 8 the models began to trend back together, showing February 14 to be
very cold. The meteorologist noted that “[t]his is the most challenging, worrisome
forecast since I joined ERCOT…” One of the models indicated a scenario that would
rival the weather event of 1989, but the forecasted cloud cover made it hard to
believe. Also, there were still tens of degrees difference between the various
models, but they were trending to levels equivalent to the extreme cold weather
experienced in February 2011. The February 8, 2021 update was the first to mention
that there could be significant icing issues with this storm.
The February 9 update indicates that the models were in agreement that February 14
– February 17 would be very cold, but that there was still a 15-20oF difference

93
between them. The February 9 update also noted that there was a high chance of
freezing rain in West Texas in the short-term, and that there likely wouldn’t be
enough time for it to melt before the coldest temperatures arrived. On February 10
some of the models that have been predicting warmer weather began to predict
weather closer to the coldest model, and a December 1989-like scenario can’t be
ruled out. Additional information conveyed on February 10 said that the 2011
February 2 freezing conditions arrived much more abruptly than the anticipated
oncoming freezing conditions over the oncoming week of 2021. A February 11
weather update indicated that the event could last as long as February 18.
The February 12 weather update indicated that the forecasts were all trending
colder, and that the models were having trouble accurately in predicting snow this
late in the winter (mid-February) because there was a lack of historical precedent for
snow this late in the winter. The February 12 update further noted that there were
continued disagreements between models and vendor-supplied temperature
forecasts and that “ERCOT simply hasn’t seen anything quite like this – this late into
the winter.”
On February 13 the weather models were still disagreeing on the severity of the
coming cold in some parts of the state, and the ERCOT meteorologist communicated
a possibility of a second winter storm that would hit mid-week, bringing more snow.
The ERCOT meteorologist also noted that they could not rule out forecasted lows in
the mid-teens (degrees Fahrenheit) in the Rio Grande Valley.
The last of the supplied emails, from February 14, discussed that all but one solar
farm in ERCOT was likely to receive snow and that the models still had disagreements
of between 10-15oF in the severity of the cold over the next few days, making
forecasting difficult. In this email, it was also noted that Dallas temperatures on
February 14 were currently below the latest forecasted levels.
The internal meteorological communications reviewed appeared to describe a very
difficult storm to predict, oh which the intensity wasn’t fully realized until just before
it happened.

94

Appendix C. Generator Outages Relative
to Time Reaching Freezing Temperature
Another relevant question to ask in assessing the electric grid’s ability to withstand
freezing conditions is “How long do generators experience freezing conditions before
generators experience outages?” That is to ask, if a sub-freezing winter storm arrives
in Texas, how much time does it tend to take for power generation to go offline, for
any reason?
We display the timing of the February 2021 outages in Figure C.1., with respect to
when power plants first reached freezing temperature (0°C or 32°F). Some parts of
Texas, for example the panhandle, reached freezing temperatures days before the
southern coastal parts of Texas reached freezing temperatures — the figures account
for this difference.

Figure C.1 combines the MERRA-2 weather data with ERCOT’s publicly reported
timing of generator outages as compiled within the “ERCOT’s Generator
Outage/Derate Visualization App” (EGOVA) dataset that relates the generators to
power plants in U.S. government databases with location data.193 We first associate
a MERRA-2 temperature time series with each power plant based on the nearest
weather station. Then, starting with the first hour on February 5, we find the first
hour with a temperature at or below 0°C, and plot the reported generation outages
relative to the time at which the power plant first experienced 0°C.
It is easiest to explain the methodology for the concrete example of the nuclear
generator that experienced an outage. ERCOT reported that South Texas Nuclear
Project (STNP) generation unit #1 experienced an outage from February 15 at 5:27
am to February 17 at 9:07 p.m., a span of approximately 64 hours. The MERRA-2
weather data suggest that STP reached 0°C at approximately 2 am on February 15.
Thus, STP went offline approximately 3 to 4 hours after reaching 0°C, and the figure
for Nuclear indicates STP’s capacity reduction starting 4 hours after first reaching 0°C.
Similarly, 64 hours after going offline, STP operators brought the generator back
online, and the capacity reduction returned to zero at 68 hours after first reaching
0°C, since the generator was at full capacity at that time.
If a power plant experienced a capacity reduction, generation derating, or outage,
before reaching 0°C, that is reported as a negative value (before) the 0-hour on the x-

193 https://bit.ly/EGOVADatabase

95
axis. Figure C.1 sums all capacity outages for plants of the same fuel relative to the
time they experienced freezing temperatures.194

Figure C.1. The capacity reduction (generation outages) for all types of generators relative to when they first
experienced 0°C.

194 That is to say, if two natural gas generators, with capacity reductions of 100 MW and 200 MW, respectively,
experienced their outage 3 hours before reaching 0°C at each location, then this would be shown as a 300 MW
outage at the x-axis value of –3, for 3 hours before reaching 0°C.

96
We can draw some conclusions from Figure C.1, but there are many caveats. One
takeaway is that the duration of freezing temperatures is important, in addition to
the temperatures experienced. Compared to wind and solar outages, the peak coal
and natural gas generator outages occur at much longer intervals of time after
reaching freezing temperatures. The peak capacity of outages, relative to the time
when the plants first experienced freezing temperatures, was approximately 6 days
for natural gas plants, 5 days for coal plants, 1 day for wind turbines, and 3 days for
solar generators. This result suggests that a multitude of complicating factors might
accumulate or occur after many hours at, or below, freezing temperatures to affect
natural gas and coal generation. The impacts to wind and solar farms appear to
occur relatively quickly, which is consistent with the reporting suggesting that a
majority of their outages were related to snow or ice accumulation.
Some of the caveats in the interpretation of Figure C.1 include the lack of other
weather data, such as precipitation and wind speed, as well as other factors that
caused power generator outages, such as fuel limitations and other mechanical
failures. For example, it is possible that the same cold temperatures with dry, rather
than wet, conditions could have caused fewer generation outages from all types of
generators. Further, generation units experience outages on a regular basis that are
independent of the weather.

97
Appendix D. Texas Natural Gas Balance
Per the U.S. Energy Information Administration (EIA), Texas is the largest energy-
producing and energy-consuming state in the U.S., including crude oil and natural
gas. In 2020, Texas accounted for 43% of the U.S. crude oil production and 26% of its
marketed natural gas production.195 Texas also consumes more energy (in aggregate)
than any other state.
The extreme cold weather from Winter Storm Uri and associated electricity supply
disruptions caused serious interruptions in Texas natural gas supply due to freeze offs
in field operations in the oil and gas value chain. The storm affected rates of natural
gas production and industrial sector consumption with both experiencing their
largest monthly declines on record. During the same period, residential consumption
reached record highs.

Figure D.1. Overall Natural Gas Balance
To contextualize natural gas operations during the storm and associated blackout, it
is important to understand the natural gas balance of Texas (see Figure D.1. Overall
Natural Gas Balance). There are three major sectors of the natural gas value
chain; production, transmission and distribution. The balance of the market
describes the aggregated relation between the supply and demand segments. There
are multiple ways to supply a market with natural gas, including local production,
local withdrawal from storage, and imports regions. There are also multiple
demands for natural gas: including distribution to downstream consumers in
individual market segments, injection into underground storage units, and exports to

195 EIA: Texas - State Energy Profile Overview - U.S. Energy Information Administration (EIA)
Supply
•Production
•Withdrawal out of local storage
unit.
•Imports by pipeline
•Imports by LNG
Demand
•Residential/Consumer sectors
•Industrial sector demand
•Gas-fired power generation
•Exports via pipeline
•Exports via LNG cargo
•Injection into local storage unit
•Fuel loss and Lease, Plant Fuel

98
other markets. There are five major segments of demand for natural gas –
residential, commercial, gas-fired electricity generation, industrial, and
transportation.
Figures D.2 and D.3 show the monthly natural gas supply-demand balance196 in the
state of Texas from January 2016 to February 2021. Aggregate natural gas supply in
Figure D.1 includes two major supply sources, dry gas production and net storage
withdrawal. Dry gas production197 refers to the process of producing consumer-
grade natural gas, after removing nonhydrocarbon gases (e.g., water vapor, carbon
dioxide, helium, hydrogen sulfide, and nitrogen), and it does not include any volume
used for production at the lease site, or any processing losses. The volumes of dry
gas withdrawn from gas storage reservoirs are separate and not considered part of
production. Dry natural gas production equals marketed production less extraction
loss. Aggregate natural gas demand includes three categories: 1) local gas
deliveries,198 2) net exported gas,199 and 3) losses of natural gas in field extraction
and processing, as lease and plant fuel, and as pipe loss fuel. Figure D.3 shows an
increasing demand for Texas exports of natural gas via pipeline and LNG to other
markets.
The aggregated supply side should equal to the aggregated demand side,
theoretically. Though in reality, there is often a small balancing item representing
any quantities lost and imbalances in the data due to differences among data
sources. This balancing item is usually around 0.5-1.5%.
𝑃𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛+𝑁𝑒𝑡 𝑊𝑖𝑡ℎ𝑑𝑟𝑎𝑤𝑙 𝑓𝑟𝑜𝑚 𝑆𝑡𝑜𝑟𝑎𝑔𝑒=
𝐶𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛+𝑁𝑒𝑡 𝑃𝑖𝑝𝑒𝑙𝑖𝑛𝑒 𝐸𝑥𝑝𝑜𝑟𝑡+𝑁𝑒𝑡 𝐿𝑁𝐺 𝑒𝑥𝑝𝑜𝑟𝑡+(𝐹𝑢𝑒𝑙 𝑙𝑜𝑠𝑠+𝐿𝑃𝐹)

196 Figure D.2 – 5 GPCM® Base Case Database as of 2021 Q1 a market simulator for North American Gas and LNG™
by RBAC.
197 EIA: Definitions, Sources and Explanatory Notes on natural gas.
198 Including electric generation, residential, and commercial customers
199 Gas exported Texas via pipeline to other states and Mexico, as well as net exported gas as liquified natural gas
(LNG) cargo to international destinations

99

Figure D.2. Texas Monthly Natural Gas Supply (Source: GPCMTM)

Figure D.3. Texas Monthly Natural Gas Demand (Source: GPCMTM)

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9
Oc
t
-
1
9
Ja
n
-
2
0
Ap
r
-
2
0
Ju
l
-
2
0
Oc
t
-
2
0
Ja
n
-
2
1
Bc
f
d
Texas Monthly Natural Gas Demand
Consumers Industrial
Electric Gen.Lease and Plant Fuel/Fuel Loss
Net Export by Pipeline Net Export by LNG

100
Appendix E. Other (non-energy)
Infrastructures Impacted from Storm:
Water and Housing
The winter storm’s impacts did not stop with the electricity and gas infrastructure.
The storm also directly and indirectly impacted other infrastructures, including water
and housing. At one point, up to 12 million Texans200 were without water or under
boil advisories due to either low water pressure or damaged treatment facilities.201
While property damage was not limited to Texas, the state is expected to file roughly
half the insurance claims associated with the winter storm.202 The Federal Reserve
Bank of Dallas estimates that insured losses in Texas alone range between $10 billion
and $20 billion. 203 The Dallas Fed estimates that total losses from the storm could
approach $130 billion in direct and indirect costs, while other estimates put it as high
as $300 billion. 204

200 https://www.texastribune.org/2021/02/17/texas-water-boil-notices/
201 https://www.dailysentinel.com/social_media/article_e3e219d1-e267-513d-848d-10dc3109e595.html.
202 https://www.wsj.com/articles/winter-freeze-damage-expected-to-hit-18-billion-from-burst-pipes-collapse-
roofs-11613757414.
203 https://www.dallasfed.org/research/economics/2021/0415.
204 https://www.perrymangroup.com/media/uploads/brief/perryman-preliminary-estimates-of-economic-costs-
of-the-february-2021-texas-winter-storm-02-25-21.pdf.

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-41

IDAHO POWER COMPANY

ATTACHMENT 4

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-21-41

IDAHO POWER COMPANY

REDACTED
ATTACHMENT 5
80MW Solar Resource Financial Analysis
PPA and Utility Ownership Customer Costs ($M)
Line
No Total Present Value
1 20-yr PPA Cost 154.7$ 73.8$
2 Replacement Energy Cost (yr. 21-35)188.5 22.9
3 Imputed Debt Cost 73.7 28.1
4 Total PPA Customer Cost 416.9$ 124.9$
5
6 35-yr Utility Ownership 240.7$ 94.8$
7
8 Customer Savings (line 4 - line 6)176.2$ 30.1$
1 20-yr PPA cost $32.50 at year 1 escalating at 2.0% per year
2 Replacement energy costs determined from market rates as prescribed in Idaho Power's 2019 IRP WECC planning case
3 Imputed Debt calculated for original 20-yr PPA and replacement energy contract
4 Assumes 26% investment tax credit (ITC)