HomeMy WebLinkAbout18 Purchase Power Review FY22 io"'TRUCKEE DONNE
- AGENDA ITEM #18
i Public
MEETING DATE: April 5, 2023
TO: Board of Directors
FROM: Joe Horvath P.E., Electric Utility Director/Assistant GM
SUBJECT: Purchase Power Review FY22
APPROVED BY
Brian C. Wright, General Manager
RECOMMENDATION:
Provide input to staff on the District's actual versus budgeted purchase power costs and
energy consumption for FY22.
BACKGROUND:
On October 6, 2021, a Workshop was presented to the Board to discuss the District's
proposed Purchase Power Plan as part of the proposed FY22-23 Budget. The workshop
covered forecast energy and costs for these fiscal years. The FY22-23 Purchase Power
Plan was approved by the Board on November 3, 2021 with the adoption of the FY22-23
Budget. The FY22 Purchase Power Plan budgeted amounts, based on a forecasted
energy purchase of 170,275 MWh, and a summary of budgeted versus actual amounts for
FY22 are shown in the following tables:
vftt /
Total Energy Supply -Various $12,463,084 $73.19
Transmission — NV Energy $1,045,916 $6.14
Total FY22 $13,509,000 $79.34
Total Energy Consumption (MWh) 170,275 173,824 2.1%
Purchase Power Cost per $/MWh $79.34 $96.79 22.0%
Total Energy Cost FY22 $13,509,000 $16,823,869 24.5%
Over Under Budget $3,314,869
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Energy production (MWh) by source in FY22, and the change compared to the previous
year, is detailed in the following table:
Note: Gree, denotes carbon-free and brown denotes fossil fuel resources.
Source 2021 2022 Change Type
Horse Butte Wind 46,067 42,795 (3,272) Intermittent
Pleasant Valley Wind 405 453 48 Intermittent
Transjordan Landfill Gas 26,029 25,436 (593) Base Load
Stampede Dam (WAPA) 5,597 8,474 2,878 Intermittent
TCID Hydroelectric Dams 3,741 7,601 3,861 Intermittent
Veyo Waste Heat Recovery 6,108 10,194 4,086 Base Load
Nebo Natural Gas 16,203 15,567 (636) Base Load
5-Year Market Purchase 33,114 18,923 (14,190) Base Load
Unspecified Market Purchases 32,771 44,380 11,610 Base Load
Total Energy Production 170,033 173,824
The District's total energy consumption was about 2% more than budget, and total
purchase power costs were $3,314,869 or 25% more than budgeted for FY22. The two
major factors that affect the total purchase power cost are energy consumption by our
customers and resource costs. A 2% increase in energy usage, by itself, should equate to
a corresponding but approximate 2% increase in purchase power costs.
The District's average energy growth over the last 15 years is about 1% per year. This has
been historically off-set by strong performance of the District's energy conservation
programs. In FY22 the District consumed 173,824 MWh compared to 170,033 MWh in
FY21, an increase of about 2.1% in just one year. It is likely that this increase is due in part
to the extreme temperatures experienced in September, November, and December. The
increase also appears to be due to electrification, a significant trend that will likely continue
in the future due to growing electrification interest and initiatives at the local, State, and
Federal levels. Through the month of November, energy growth was 1 .2% above 2021 .
However, December was a very cold month which resulted in significant increase in electric
energy usage of about 12% compared to the previous December. Therefore the overall
energy increase for FY22 was 2.2% compared to FY21. The increased energy usage
resulted in the need to make additional market energy purchases.
However, despite this small increase in energy use, there were several factors that
contributed to a much larger total increase in purchase power costs. These factors include:
• Loss of Nebo Power Station generation in November and December;
• Delay in the planned commercial operation date of June 1, 2022 for the Red Mesa
Solar Project;
• Reduced 5-Year Market Purchase energy amounts (anticipated Red Mesa Solar
energy production which did not occur); and
• Increase in corresponding unspecified market energy purchases due to the above at
significantly higher prices driven by unprecedented spikes in natural gas prices, very
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low hydroelectric production across the western region, and high demand due to
extreme temperatures in September, November, and December in California and
across the western US.
All these factors helped increase the District's actual purchase power cost compared to
budget. A more detailed discussion of each factor follows.
Nebo Power Station - The Utah Associated Municipal Power Systems (UAMPS) Nebo
Power Station (Nebo), a natural gas-fired generation facility, is located in the central Utah
city of Payson, and has a maximum capacity of 146 MW. The District's agreement with
UAMPS for a 5MW share of electricity typically supplies about 10% of the District's total
annual energy needs. Nebo is taken off-line twice a year in April and October for a 3 to 4
week period to perform preventive maintenance operations and minor repairs.
During the October, 2022 preventive maintenance work, UAMPS staff discovered
significant damage to portions of the steam turbine rotor blades. If left unrepaired, there
was a very high probability that this damage could lead to a catastrophic failure of the
turbine. The decision was made to send the steam turbine to a repair facility in Texas with
an estimated return to service date of mid-December. Unfortunately,the repairs took about
6 weeks longer than expected. Nebo was finally returned to full operation on January 31,
2023. The unexpected loss of Nebo generation during November and December (peak
energy months for the District) resulted in a corresponding increase in market energy
purchases. Market energy prices reached historic highs during 2022, but especially in
September, November, and December, which greatly contributed to the District's resource
costs exceeding budget.
Red Mesa Solar Project - The District has a 6 MW share of the Red Mesa Project, which
equates to about 10 percent of the District's total annual energy requirements. In
September 2019, the Board adopted Resolution 2019-20 authorizing the Red Mesa
Tapaha Solar Project with UAMPS. The Red Mesa Project is owned and operated by the
Navajo Tribal Utility Authority(NTUA). The Red Mesa Project's Commercial Operation Date
(COD), the date the Project would produce powerfor participants, was scheduled for June
1, 2022. In early 2022, NTUA informed UAMPS of the need to renegotiate the Purchase
Power Agreement (PPA) due to material price increases and supply chain constraints
outside of NTUA control caused primarily by COVID-19. This also would delay the COD. In
September 2022, the Board adopted Resolution 2022-17 authorizing the amended
agreement for the Red Mesa Tapaha Solar Project with UAMPS with amended pricing from
$23.15 MWh with a 2% annual escalation factor to $37 MWh with no escalation for a term
of 25 years, and a new COD of March 15, 2023 with a not to exceed date of September 15,
2023. The District's participation at the 6 MW amount remains unchanged.
The delay in the commercial operation date for the Red Mesa Project from June 1, 2022 to
March 2023 resulted in a corresponding increase in market energy purchases.
Unfortunately, the need to purchase additional energy from the market came at a very
challenging time. With reduced hydroelectric production from drought conditions and the
nationwide reduction of fossil fuel base load sources, the demand for natural gas had
increased, resulting in upward pressure on natural gas prices. The District purchased
energy at much higher prices from the market that would have otherwise been supplied by
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the lower-cost Red Mesa Project during 2022, also greatly contributing to the District's over
budget situation.
5-Year Market Energy Purchase -The District has an existing 5-Year market power
purchase contract with UAMPS that began on April 1, 2022 and ends March 31, 2027. The
existing 5-year market power purchase represents about 20% of the District's annual
energy requirements and is priced at$35 per MWh. The market power purchase is shaped
and scheduled to the District's load profile, filling the energy `gaps' in our purchase power
portfolio that are otherwise not supplied by other generation sources. The 5-year market
power purchase contract is an important component in our portfolio, developed by UAMPS
in 2002 and renewed on a 5-year cycle for their members, that enables the District to
deliver low-cost power to reliably meet customer loads.
The District was able to reduce the market purchase component from the previous 5-Year
market power purchase (2017 to 2022) of 35% to the current 20% level by adding other
resources. The main driver for the decrease in the market power purchase was the
planned addition of the Red Mesa Solar Project to the District's power portfolio, scheduled
to start operation no later than June 1, 2022. With the delay in the COD of Red Mesa
Project, the current 5-Year market power purchase covers a much smaller portion of the
portfolio, resulting in additional market energy purchases at higher costs.
Market Energy Pricing -The market price for energy rises or falls, primarily, as the cost of
natural gas changes. This is due to natural gas increasingly becoming the marginal fuel for
electricity generation, therefore natural gas power plants typically establish the market-
clearing price of energy generation. Natural gas prices have remained relatively low in the
years prior to 2021, ranging from $2.00 to $4.00 per metric million British thermal units
(MMBtu). Due to a variety of factors including high demand due to cold temperatures and
the war in Ukraine, these prices have now been ranging from $6.00 to $10.00 per MMBtu,
and sometimes spiking much higher.
For example, natural gas prices averaged $25.00 per MMBtu in December 2022, an all-
time high. Some of the market forces effecting higher natural gas pricing included:
increased demand for electricity due to weather conditions, less than average amount of
natural gas in storage in the western states area, increased exports of liquefied natural gas
(LNG)to Europe, pipeline congestion and lack of new pipeline construction, and shortages
of coal deliveries to coal-fired generation facilities. As a consequence of increased natural
gas prices and heavy demand for energy during the hot summer months and cold winters,
market energy prices have been ranging between $100MWh to $200MWh for the months
of July through September and $200 MWh to$250MWh for November and December. The
District's market energy purchases averaged $95.87 per MWh in FY22, compared to
$64.60 per MWh in FY21, and $40.10 per MWh in FY20. The FY22 market energy price
represents a 48% increase compared to FY21 market energy pricing, and a 139% increase
compared to FY21 market energy pricing.
Other District Resources -Although there was reduced energy production of 3,865 MWh
from the Horse Butte Wind and Transjordan Landfill Gas projects, this energy was offset by
an increase in energy production from all hydroelectric sources and a larger increase from
the Veyo waste heat recovery project. Wind production varies yearly due to the intermittent
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nature of this resource. While drought conditions across the western US have resulted in
significantly lower energy production from almost all hydroelectric sources, the District's 3
sources - Western Area Power Administration's (WAPA) Stampede; Truckee Carson
Irrigation District's (TCID) Old Lahontan; and TCID's 26 Foot Drop power plants - had
combined energy production of 16,075 MWh in FY22, compared to 9,337 MWh in FY21,
an increase of 6,738 MWh. This energy is highly dependent on winter weather, and this
increase may not represent a long-term trend. The District also procures carbon-free
energy from the Veyo Project, a waste heat recovery generating facility located in Veyo,
Utah. Energy production from Veyo was 10,194 MWh in FY22, compared to 6,108 MWh in
FY20, an increase of 4,886 MWh.
Energy costs and consumption by month for FY22 are graphically depicted in the graphs
included in Attachment 1:
• Budgeted vs. Actual Power Purchase Cost, 2022;
• Budgeted vs. Actual MWh Consumption by Month, 2022;
• Peak Load in MW by Month, 2017-2022;
• Budgeted vs. Actual Power Sales, 2007-2022;
• Retail Energy Sales — Residential vs. Commercial, 2018-2022;
• Purchase Power Cost by Month, 2022;
• Market Energy Power (Pool) Cost by Month, 2022;
• Resource Mix by Percentages, 2022; and
• Resource Mix by Percentages, 2021 (for comparison purposes).
Historical energy usage data for the years 2005 through 2021 are depicted in the following
tables included in Attachment 2:
• Energy Purchases with Transmission System Losses,
• Actual vs. Budgeted Energy Purchases;
• Energy Sales to Customers; and
• Distribution System Losses.
Renewable Portfolio Standard (RPS)
On October 2, 2013 the Board approved the Renewable Energy Resources Procurement
Plan per the requirements of Senate Bill (SB)X1-2 (2011). This plan defined the minimum
required percentage (RPS) of renewable energy resources compared to retail sales per
three-year compliance period to the end of 2020. Other legislation has increased the RPS
requirements and extended the compliance periods to the end of 2030. In 2015, SB 350
was signed into law, which mandated a 50% RPS by December 31, 2030. In 2018, SB 100
was signed into law, which again increases the RPS to 60% by 2030 and requires all
state's electricity to come from carbon-free or clean resources by 2045. In addition,
lawmakers passed SB 1020 in 2022, which requires 90% clean electricity by the end of
2035 and 95% by the end of 2040 as intermediate milestones to the target of 100% clean
energy by 2045. Compliance periods and RPS requirements are as follows:
Period 1 - January 1, 2011 through December 31, 2013 - 20% RPS;
Period 2 - January 1, 2014 through December 31, 2016 - 25% RPS;
Period 3 - January 1, 2017 through December 31, 2020 - 33% RPS;
Period 4 - January 1, 2021 through December 31, 2024 - 44% RPS;
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Period 5 - January 1, 2025 through December 31, 2027 - 50% RPS; and
Period 6 - January 1, 2028 through December 31, 2030 - 60% RPS.
The District's final RPS amount is the ratio of all qualifying renewable energy received
divided by the District's total retail energy sales, as defined by the California Energy
Commission (CEC). Section 3201(bb) of CEC regulations define retail energy sales as:
"Sale of electricity by a POU to end-use-customers and their tenants, measured in Muth"
This does not include energy consumption by a POU, electricity used by a POU for water
pumping, or electricity produced for onsite consumption (self-generation)." The retail
energy sales calculation for the District according to the CEC definition is shown in the
following table:
ketail Sales pNfiE
FY22 Energy Sales to Customers 167,155
Water Pumping Energy Sales -6,420
Other District Energy Usage -533
FY22 Retail Sales for RPS 160,201
The District has a diverse portfolio of clean resources including hydroelectric, landfill gas,
wind, and heat recovery generation. Most of these resources include renewable energy
credits (RECs)that are transferred to the District in accordance with the energy generated.
However, several resources including Stampede hydroelectric, TCID hydroelectric, and
Veyo heat recovery projects come with a partial amount of RECs, or no RECs at all. These
resources actually generated about 26,269 MWh in FY22. Since these are RPS eligible
and/or carbon free resources, the District purchased additional RECs to cover the RECs
that were lacking from these resources. The District's estimated renewable energy portfolio
performance, or RPS, for FY22 is shown in the table below.
Eligible Renewables and Carbon-Free � MWh RECs % Retail Sale
Hydroelectric (Stampede— Estimated,partial) 4,237 2.6%
Landfill Gas Trans'ordan 25,436 15.9%
Wind (Horse Butte, Pleasant Valley) 43,248 27.0%
Heat Recovery Ve o, carbon-free, w/o RECs 0
Unbundled RECs Small Hydro & Heat Recovery) 14,000 8.790
Estimated RPS FY22 54.3%
RPS Requirement 2022 38.5%
The estimated RPS for FY22 is about 3% lower than FY21. The factors contributing to a
lower RPS value this year include the delay of Red Mesa solar being replaced by
unspecified market purchases, a 7% reduction in wind generation and a 2% reduction in
landfill gas generation compared to 2021, along with an increase of 3% in total retail
energy sales. The District's final RPS value for FY22 will be known only after final energy
and REC information for District resources becomes available sometime in Q2, 2023. The
final RPS value has historically been somewhat greater than the estimated value above.
However, the final RPS is also dependent upon the total amount of RECs that the Western
Area Power Administration (WAPA)transfers to the District for Stampede generation. This
amount varies from year to year, and is typically much less than half of the actual energy
delivered to the District from Stampede. In addition, changes to the overall RPS value are
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also due to the variability of renewable resource generation from year to year. It should
also be noted that the District's electric resource portfolio was essentially the same in FY22
as in FY21. This will change in FY23 with the addition of the Red Mesa Solar Project to the
resource portfolio and should result in a corresponding increase to RPS between 5% to
9%.
ANALYSIS:
Staff believes that, for the District, a future with higher load growth driven by community
growth and electrification is likely. Not only must the District continue to convert our current
electric resource portfolio to 100% clean or carbon-free, we must also plan for additional
resources with growth. This necessitates electric resource planning that considers and
incorporates multiple factors including:
• Carbon Free vs. RPS vs. Fossil Fuel Resources - The District's FY22 RPS is
estimated to be 54%, well ahead of State mandates, with efforts to achieve 100%
carbon free by 2045 or sooner while considering rates and reliability;
• Intermittent vs. Base Load Resources - A significant portion of the District's
renewable resources are wind, solar, and hydroelectric and are intermittent in
nature, with no control over the timing and amount of generation. In order to meet
the District's 24-hourload needs, base-load or resources that can be scheduled are
required,
• Daytime vs. Nighttime Availability- The District has modeled our current portfolio,
with the addition of Red Mesa Solar Project, and demonstrated that we are
approaching 100% carbon free during the daytime hours. In order to achieve 100%
carbon free, the District will be increasingly required to procure carbon free
resources during the evening and nighttime hours;
• Affordability and Equity - The District must continue to consider the impacts of
rising electric rates on our community and to California's climate goals and
strategies. Electric rates are bricks and mortar for economic development and
critical for electrification efforts;
• Portfolio Timing, Diversification, and Risk - The management of the District's
electric resource portfolio considers and balances -in addition to all of the above -
timing, diversification, and risk, and
• Conservation and Demand-Side Management Programs - Reducing energy
consumption, and most importantly the time of energy consumption, can reduce
resource procurement requirements and costs. The District's work on an Integrated
Resource Plan (IRP) is a key tool to balance the costs to procure electric resources
vs. the costs to reduce or modify how an electric resource is used.
Staff plans to bring to the Board additional workshops and future actions to address the
District's electric resource planning and how this fits with the District's budgets, strategic
initiatives, regulatory requirements, and mission. To this end, staff anticipates engaging the
services of a qualified consultant to provide professional services for the development of
an IRP. The IRP is a long-term planning tool used to evaluate and optimize the District's
portfolio of energy supply resources, including energy efficiency and demand response, in
order to meet our customer's electric needs well into the future. The IRP will evaluate
traditional generation, increasing renewable generation including demand-side and energy
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storage resources, and variations of meeting and expediting state mandated carbon-free
resource goals. For the short term, UAMPS is helping all members, including the District,
reduce our exposure to purchasing market energy by the following actions/items:
• Procure 5-Year fixed price natural gas contracts sufficient to run Nebo Power
Station for baseload (24/7) operations (105MW)all year, with maximum output(146
MW) during times of peak member demand;
• Procure 1-Year forward market energy purchases sufficient to fill energy gaps in
member portfolios; and
• Establish a market volatility reserve fund at UAMPS.
California Air Resources Board (CARB) Cap and Trade Program
The Cap-and-Trade Program is a key element of California's strategy to reduce
Greenhouse Gas (GHG) emissions, with annual auctions that began in 2013. Section
95892(d)(3) of the regulation states the following: "Auction proceeds and allowance value
obtained by the electric distribution utility shall be used exclusively for the benefit of the
retail ratepayers of each distribution utility, consistent with the goals ofAB32, and may not
be used for the benefit of entities or persons other than such ratepayers." The Board
approved the use of auction proceeds to offset the cost of the District's renewable energy
resources, therefore meeting the goals of AB32. Four auctions are held annually, with
results for FY21 and FY22 as shown below.
Settlement Proceeds to
2021 Cap and Trade Auctions Price District
Auction 26, February 2021 $17.80 $169,100
Auction 27, May 2021 $18.80 $178,600
Auction 28, August 2021 $23.30 $221,350
Auction 29, November 2021 $28.26 $278,135
Total Auction Proceeds FY21
applied as revenue in FY22 $847,185
Settlement Proceeds to
2022 Cap and Trade Auctions __Price_ District
Auction 30, February 2022 $29.15 $131,816
Auction 31, May 2022 $30.85 $139,504
Auction 32, August 2022 $27.00 $122,094
Auction 33, November 2022 $26.80 $121,189
Total Auction Proceeds FY22
applied as revenue in FY23 $514,604
The revenues collected from the auctions in one fiscal year is spent in the following fiscal
year, consistent with standard accounting practice. Staff estimated auction proceeds to be
$600,000 in FY21, and $400,000 for FY22.These amounts were conservatively budgeted
as revenue in FY22 and FY23 to help pay for energy from renewable resources. The actual
auction proceeds were higher than budgeted for in FY21 (proceeds applied to FY22 as
revenue), and slightly higher than budgeted for in FY22 (proceeds applied to FY23 as
revenue). The number of auction allowances for the years out to 2030 have been greatly
reduced by CARB for all POU's, including the District, starting in FY21. Staff estimates
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auction proceeds to be about $300,000 for FY23 and beyond, although this is directly
impacted by trends in auction settlement prices and any additional regulatory changes.
FISCAL IMPACT:
A summary of budgeted versus actual energy and cost amounts for FY22 are shown in the
following table:
Summary FY22 Budget vs Actual
Power Purchases, MWh Budget Actual
Total Energy Purchase, MWh 170,275 173,824
Percent Difference, Actual vs. Budget 2.1%
Power Purchase Costs Budget Actual
Total Energy Supply $12,463,084 $15,579,403
Transmission - NV Energy $1,045,916 $1,216,762
Miscellaneous Costs $0 $27,704
Total Power Purchase Cost $13,509,000 $16,823,869
$ Over/(Under Budget $3,314,869
Difference, Actual vs. Budget 24.5%
Purchase Power Cost $/MWh $79.34 $96.79
Percent Difference, Actual vs. Budget 22.0%
Staff will present to the Board a separate report that addresses the financial impact of the
$3.3M over budget position and the potential use of rate reserve funds to mitigate the
material 25% overage in purchased power costs.
Goals and Objectives:
This item is in support of the following goals and objectives:
District Code1.05.030 Goals:
1. Manage for Financial Stability and Resiliency
2. Environmental Stewardship: Create a sustainable resilient environment for all of our
communities.
District Code1.05.020 Objectives:
1. Responsibly serve the public.
5. Manage the District in an environmentally sound manner.
6. Manage the District in an effective, efficient, and fiscally responsible manner.
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ATTACHMENTS:
Attachment 1 Energy Costs and Consumption by Month - FY22
Attachment 2 Historical Energy Usage Data - FY05 to FY22
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