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HomeMy WebLinkAbout _ 9.5(c)-- Redding Electric Utility's FY23-24 Financial Report � � �' � � � � � � ' � �' � � ' � ` CITY OF REDDING REPORT TO THE CITY COUNCIL MEETING DATE: September 17,2024 FROM: Nick Zettel, Director of ITEIVI NO. 9.5(c) Redding Electric LTtility ***APPROVED BY*** � ��. ; � _ � v �� ��„ ���� �1c ct c, yrectc� �ii' e in� tri�ttt32ity �),'S;?t�2� rS' �P�tt�,C�i ��t t� �3,'1C�t'2{}? nzettel@cityofredding.org btippin@cityofredding.org SUBJECT: 9.5(c)--Consider Redding Electric Utility's Fiscal Year 2023-24 Financial Report and Tndustr Activities U date. Recommendation Accept City of Redding Electric Utiility's Fiscal Year 2023-24 Financial Report and Industry Activities LTpdate. Fiscal Impact There is no fiscal impact related to accepting this report. Alternative Action The City Council (Council) could chaase not to accept the report and provide further direction to staff. BackgNound/Analysis The Fiscal Year 2023-2024 Financial Report shows that Redding Electric Utility (REU) performed better than budgeted. The improved REU Financial Results were driven by higher- than-expected revenue and savings in system operation and maintenance (O&M). Although power costs rose, the impact was mitigated by a 122,7 percent increase in hydropower deliveries (259,707 MWh versus 116,594 MWh in FY2023) and lower natural gas commodity prices. Unrestricted reserves decreased by approximately $7.3 million over the fiscal year, totaling $411 million. Despite this decrease, the reserves exceeded REU's five-year plan projections, anticipating an end-of-year balance of $37.5 million. The June 2024 balance surpassed expectations by $3.6 million and meets the Council's Financial Management Policy requirements. Report to Redding City Council September 21, 2024 Re: 9S(c)--Redding Electric Utility's FY23-24 Financial Report Page 2 Revenue Billed retail revenue for the year was $4,487,571 (3.5 percent) above budget due to higher end- use. Approximately one percent of this is attributed to warmer-than-average weather, with summer months averaging one degree warmer than normal (normal weather is an average of the previous ten years). Wholesale Sales exceeded the budget by $15,143,696 (90.6 percent), supported by favorable hydro conditions, resource optimization in the real-time market, and a relatively new winter strategy. Overall, operating revenue for the year was $21,626,751 (14.9 percent) above projections. After accounting for energy costs, operating revenue was $5,241,743 (7.5 percent) higher than budgeted. Expense Power Cost(Cost of Ener�v) The combined costs for generation, purchases from the Western Area Power Administration, Big Horn Wind Project, contracts, and the spot market were $16,385,008 (21.7 percent) above budget projections for the year. The Redding Power P1ant generation cost was higher than forecast due to increased load and wholesale sales. The total Cost of Energy decreased by $25,965,229 (22.0 percent)year-over-year. Power Cost for the load(Power Cost less Wholesale Sales) decreased by $12,077,834 year-over-year(16.7 percent). System O�erations &Maintenance (O&M� System O&M costs for the year were $4,155,339 (7.4 percent) below projections. This cost reduction was mainly due to the timing of certain activities and the deferral of expenditures and activities to the next fiscal year, resulting in unrealized savings. Debt Service and Capital Outlay Debt service payments and obligations for the year totaled $14,399,278. Capital Expenditures for the year totaled $12,918,994 (�8.5 percent spent). The pace of eapital projects and expenditures has increased, driven by the timely receipt of procured equipment and productivity. Special Fund Expenditures Special Fund Expenditures include the expenditures for Public Benefit and Cap-and-Trade Programs, which totaled$2,941,400 (35,6 percent spent) for the fiscal year. Electric Utility Unrestricted Cash Balance The unrestricted cash balance at the end of the year was $41,1 million, representing approximately 112 days of cash. REU's Financial Management Policy(Council Policy 1414)has a minimum of 75 days of cash and a goal of 150 days of cash. Report to Redding City Council September 21, 2024 Re: 9S(c)--Redding Electric Utility's FY23-24 Financial Report Page 3 Director's Contingency Fund For the year, $229,200 (45.8 percent) of the REU Director's Contingency Fund was utilized primarily to cover the increased costs for the vegetation management contract, general consulting services, and compliance expenses. Environmental Review This is not a project defined under the California Environmental Quality Act, and no further action is required. Council PrioNity/City NfanageN Goals • Budget and Financial Management — "Achieve balanced and stable 10-year Financial Plans for all funds." Attachments Attachment 1 -Notes on Financial Operating Statement Attachment 2 - Elec�ric Utility Financial Results for Jun 2024 Attachment 3 - Electric Utility Financial Dashboard for Jun 2024 Attachment 4 - Electric Utility Unrestricted Cash Balance Jun 2024 Attachment 5 - Industry Update City of Redding Electric Utility Notes to Financial Report Notes on Financial O�erating Statement Operating revenues are divided into three revenue elements: Retail Sales are sales of electricity to end-use customers; Wholesale Sales are to customers who resell electricity; Other Revenue includes the sale of services, joint-pole arrangements, interest income, and other miscellaneous revenue generated in the operations of Redding Electric Utility(REU). Operating Expenses are divided into two expense elements: Power Cost and System O&M. Cost of Energy summarizes Purchased Power costs. The primary sources of purchased power include Western Area Power Administration deliveries and long-term contracts for Wind Energy through M-S-R. Fuel expenses,purchases from the spot market, and expenses associated with participation in the California lndependent System Operator make up the remainder. The Generation and Transmission component comprises power plant variable costs (fuel) and fixed costs (all non-fuel costs), as well as all JPA costs (M-S-R and TANC), except Wind Energy. The Wholesale Sales and Power Costs budgets are based on known contracts and confirmed resources. Throughout the year, an effort is made to provide the most cost-effective energy supply for our ratepayers. This is often done by buying and selling natural gas or electricity to reduce the overall cost. This could incl�ude selling nat�ural gas and replacing it with less expensive electricity than burning it in our power plant. It could also include selling energy we have contracted for at one trading hub and buying it at another less expensive one. It could also include maximizing the value of our gas storage facility to purchase natural gas in one month when it is less expensive and use it or sell it in another month. All these transactions benefit our customers but significantly inflate the Wholesale Sales and Cost of Energy numbers over their original budgets. This is because accounting rules require us to record these transactions at their gross revenue and expense amounts, not on the utility's net benefit. System O&M Expenses summarize costs for all other functional groups, i.e., Administration, Customer Services, Engineering, Financial Services, Line, Compliance, and Resources. Special Revenue funds, i.e., Public Benefits and Cap-and-Trade, are shown separately. Debt Service is paid twice per fiscal year, once in December and again in June. Capital Outlay includes current- year appropriations and unfinished projects approved by the Council in prior years. This �nancial report provides year-to-date comparisons to the current budget and the same year- to-date results for the prior year. Operating revenues are reported as billed. Costs for energy, other operating expenses, and capital outlay are recorded when paid. For this report, debt payments are spread evenly over the year, giving a more helpful picture of the financial results. Projections are based on normal weather trends and known industry activity. If actual weather conditions are above or below average for the month or unexpected industry disruption occurs, revenue and expenses will increase or decrease accardingly. REU's residential and small commercial rate structures are heavily weighted on volumetric charges ($/kWh), and abnormal weather causes more significant variances in net operating results, emphasizing the difference between the rate structure and cost structure. The recorded results are preliminary and subject to revision until the final audit is complete. Attachment 1 E�ECTRIC UTII.ITY FINANCIA�RESULTS-1UNE 30,2024 s �°•+e o • e : ,.e , . 3 ) Y � � 1 � 6 � 1 � 1 � ti.,... ..,,.,. .. ... �.,�..� ..�,.. �.� . .H.. � ..�..... . .��� .�. . .......�..,.. ., .��,..... ,. .�...... ........... �� .�...�. ,,.. ...�.� �..�. ..�., �. .0 ,�,.,,, . �.,.�.... , Energy System�oad(MWh) 766,057 733,867 4.4% 32,189 778,980 Key Performance Indicators Days Cash on Hand 112 148 Operating Revenues Retail Sales 130,932,571 126,445,000 3.5% 4,487,571 130,952,824 Wholesale Sales 31,849,696 16,706,000 90.6% 15,143,696 45,737,091 Miscellaneous Incomez 3,896,574 1,901,090 105.0% 1,995,484 21,219,521 Total Operating Revenues 166,678,841 145,052,090 14.9% 21,626,751 197,909,436 Operating Expenses Power Cost Purchased Power 21,163,746 19,559,700 8.2% 1,604,046 34,818,378 Generation,Transmission and 1PA(Variable) 38,547,290 29,846,200 29.2% 8,701,090 52,623,309 Generation A&G and O&M(Fixed) 32,254,452 26,174,580 23.2% 6,079,872 30,489,030 Subtotat PowerCost 91,965,488 75,580,480 21.7% 16,385,008 117,930,717 System O&M General&Administrative 4,776,755 8,395,530 -43.1% (3,618,775) 6,405,207 Interdepartmental(Incl.In-Lieu of Tax)Z 13,337,298 13,302,190 0.3% 35,108 6,246,800 Transmission&Distribution 30,596,608 31,168,280 -1.8% (571,672) 27,993,137 Customer&Field Servicesz 3,221,520 3,221,520 0.0% - 10,070,913 Subtotal System O&M 51,932,181 56,087,520 -7.4% (4,155,339) 50,716,056 Total Operating Expenses $ 143,897,669 $ 131,668,000 9.3% $ 12,229,669 $ 168,646,773 Net Operating Revenue $ 22,781,172 $ 13,384,090 70.2% $ 9,397,082 $ 29,262,663 Total Debt Service $ 14,399,278 $ 14,401,020 0% $ (1,742) $ 14,413,877 e ....... ...�. , a .a a. ,._,, �i �' � '��Wml, �����i;� j a .�• `i � � � � � � � , w , � , €, � ,.. . . ,,,. =.n .............. � .. � .. �,,..,_ .... ,,. ,.,,...�. . .. .., ..... . ...,... , _...�..... , t,.,.4... ....,. . .. ,,.. ... . ,,...r .. . ,...., .....w, Capital Outlay Capital Outlay(Revenue Funded) 12,918,994 16,450,800 78.5% 3,531,806 13,292,383 Capital Outlay(eond Funded) Total Capital Outlay $ 12,918,994 $ 16,450,800 78.5% $ 3,531,806 $ 13,292,383 Special Fund Expenditures Public Benefit Programs 2,399,363 4,129,400 58.1% 1,730,037 2,503,536 Cap-and-Trade Programs 542,037 4,137,590 13.1% 3,595,553 3,420,225 Total Special Fund Expenditures $ 2,941,400 $ 8,266,990 35.6% $ 5,325,590 $ 5,923,761 Financial Results $ (�,478,500) $ (4,367,358) CHANGES IN FY2024: 'Customer Services and Field Services are removed from the Electric Department's Financial Results,and an allocation of expenses is recorded. Z Interdepartmental Allocations are not assigned to various divisions within the Electric Department as in previous years but recorded as its own category. E�ECTRIC UTI�ITY FINANCIAL DASHBOARD -JUNE 30, 2024 � ��.�,.��Curnulati�e Difference 20�3 Ac�u�1 2024Actua) s,����2£324�udgt�t y; 1� ; � ��' '� � {; � �� :j ����a��� �:� � ,� ,as , o-�� � 22 ; , �0 `� ` � � �, � �, � , �, „ � � �._ � n .., ������ ���� , $ , ��� :. .. . .� . ,� �. �� � .... _, . . ..0 .t, .. �..,s,.�, ..n, '.�,� %� � 6 ,. '�.. .� �� ,,� ,� ct � ,, .. :,, .. �........ ....... .:.....�,'„ ?.. ! � �s ��� � x... .} .,,.. a eh � , . .{ f . � ... �. ... . :, �� h ' � � H i ti c{ � ri N p ��� f d�. � v,,,,,,. r} � � y rH t 1 f ; � � ;{ x ? S ., � ,;� # { r � ; := �, a ,4 .} � ,s $ r r � �� s ,t� s:>, � e. ' r,°,. . �-i.+ �,, �.,...� d �.t; a {� t p ry +� q � , d . � � 1 � �`: ! b i � LQ N {�� �,,,,..,.,�, m,.,<. :�,.... 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I P,ti s�r.i ((t t ii�� ! 4ti, � �5.$t 3 E�{>i �� k�,',��,},� �'%��rti, ,� �� .1 4r%'f�) k., 4;s ���j;c,�{, {' .I�IL AUG SEP Cb�T N(�U �EC J�14� FE� M�1R �PR Mt�«Y .i�lN �' �,� �r�„. ,.�,�t, , ,�> �,;,<,�:, ,���.>��,, , a� ri�,,�„�s, .. ,n,.�r z t,,, r,�, ,,;, ; ����„' .,�f � � } E�ECTRIC UTI�ITY FINANCIAL DASHBOARD -JUNE 30, 2024 � � � ���� � ;�� i-1 Cumulative C?i�f�rence ��2023 Actua( 2024 Actual 2U24 Budget �� � �� �5 ; `` �r � � �0 ' ����� ,�25 � i � r a � �� �0 r`��' i`; ;�� .� `'' � '��ar� � . �� ��� �� r � � � 3 �: ��., n�� r�. �.: E f o ; , �;' ', � ; .. _� ,< �' �...�< ., f ��� 1. i E } ' t �.� # I � � u��.,� h� � � r i � J � r`:.,, � ry j �', *K f� �, � ,d,,,,...3'� $ �' � � �J ,' � I tY5 tri ,' , "� 'j ��.. ,. s, , ,w,. ,,. ,,,, . . ` i f r � � i.... 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Jizl Aug S€pt (?ct �i�v 3�ec �ata F�la 1�Iar A.pr May �un ITnr�stricted Cash-2023-24 49.7 51,4� 52.� 44.� 42.6 40.6 42.8 41.7 39.3 �0,5 40.1 �1.2 �I�nrestricted Cash-2022-23 43.'� 45.7 45.� �3.t7 43.3 4(7.6 39.8 36.2 35.C1 32.`7 32,3 4$.4 City of Redding Electric Utility Industry Activities Update—4ti" Quarter FY2024 Federal Update In May 2024, the Federal Energy Regulatory Commission (FERC) issued Order No. 1920, a significant ruling on regional electric transmission planning and cost allocation. The order aims to modernize the United States electric grid by addressing long-term transmission needs and facilitating the integration of renewable energy sources. This will affect how future transmission projects will be planned, funded, and constructed. The order requires regional transmission organizations (RTOs) and independent system operators (ISOs) to conduct long-term regional transmission planning, considering future grid needs over a 20-year horizon. This is intended to anticipate and address challenges related to grid reliability, renewable energy integration, and capacity expansion. Tn an early August hearing, Senate Finance Committee Chair Ron Wyden (D-OR) affirmed his commitment to defending tax-exempt financing in the upcoming 2025 congressional debates. He highlighted the adverse effects of the 2017 Tax Cuts and Jobs Act, which repealed the issuance of tax-exempt advance refunding bonds, significantly hindering state and local government's capability to manage and reduce their debt. State Le�isiative Update Each year, the Northern California Power Agency (NCPA), a public Joint Powers Agency, organizes a Legislative Tour of inember service areas for federal and state legislative staffers. This year's tour included a stop in Redding.Vice Mayor Julie Winter and Director Zettel provided short presentations, a demonstration of the Emergency Operations Center, and a tour of the Carr Fire burn areas.The purpose of these tours is to highlight critical issues and challenges affecting electric utilities. Senate Bill 1006 (SB 1006), authored by Senator Steve Padilla, was introduced to modernize California's aging electrical grid. The bill mandates that utilities in California explore and report on the feasibility of grid-enhancing technologies (GETs) and advanced conductors. These technologies are intended to increase the grid's capacity for renewable energy,improve reliability, and potentially lower costs by making better use of existing infrastructure. As of September, SB 1006 has successfully passed through the California legislat�ure. The bill is now in the fmal stages of the legislative process, awaiting the Governor's signature before becoming law. As reported in the last update, REU was closely following the Energy Resources Programs Account (ERPA) Structural Deficit Relief Trailer Bill's proposal to raise the statutory cap of the existing ERPA surcharge from $0.0003/kWh to $0.00066/kWh and extend the surcharge to behind-the-meter electricity consumption. The Senate Committee on Budget and Fiscal Review proposed not to increase the surcharge until ERPA dips below a prudent reserve—which,according to the department, is approximately $20 million. Although it did not pass this time, it may be revisited in the future. State Re�ulatory Update On April 9, the California Air Resource Board (CARB) released its Standardized Regulatory Impact Assessment(SRIA),outlining the initial proposed revisions to the Cap-and-Trade Program. California's Cap-and-Trade program aims to curb carbon emissions statewide while offering Publicly Owned Utilities (POUs), including REU, carbon allowances to alleviate the financial burden on their ratepayers. Due to early investments in carbon-free resources, REU has received a surplus of allowances,which have been monetized. In alignment with program requirements,the Cap-and-Trade revenues have been used to support customer programs, including but not limited to 1ow-income energy efficiency, City fleet electrification, public EV charging stations, and electrification rebates. CARB is exploring the removal of 265 million allowances from the budgets spanning 2025 to 2030, followed by a gradual decline trajectory aimed at achieving carbon neutrality by 2045. Currently undergoing informal rulemaking, some of the most notable potential revisions to the Program encompass reductions in the allocation of allowances to electric utilities, requirements dictating the utilization of allowance values, and the shortening of compliance periods. If CARB adopts changes proposed in its SRIA, REU could incur an additional $22 million in power supply costs from 2025 to 2030 due to reduced allowance allocations and the expenses associated with meeting carbon obligations. CMUA, NCPA, the Joint Utility Group, and REU continue closely monitoring these proceedings, meeting with CARB, and providing oral and written comments while evaluating various scenarios in readiness for formal rulemaking. Low Carbon Fuel Standards U�dates The California Air Resources Board(CARB or Board)has scheduled a public hearing to consider amendments to the Low Carbon Fue1 Standard (LCFS) for November 8, 2024. CARB staff continues to analyze and incorporate modifications to the rulemaking proposal, including a near- term step-down in carbon intensity benchmarks of 7% or greater, as well as refinements to feedstock sustainability provisions, zero-emission vehicle infrastructure eligibility provisions, provisions that would increase support for zero-emission vehicle fueling, and other provisions. If approved by the Board,the amendments are expected to be in effect in early 2025. Participating in the LCFS Program generates revenue to support REU's transportation programs. On August 13, CARB released a 15-day language regulatory language, which included several new program provisions. If the amendments are approved, a portion of the program funds would be directed to OEMs (auto manufacturers)that are below a set threshold of EV sales, and program participants would be required to submit third-party credit verifications. REU is working with NCPA to develop comments to ensure the value and integrity of the program remain intact. Conclusion REU continues to work actively with legislative and regulatory partners to manage risks and minimize exposure through several strategic actions. In collaboration with the Northern California Power Agency (NCPA) and the California Municipal Utilities Association (C1V1UA), REU provides feedback to reduce operational burdens and mitigate potential cost increases for customers. Additionally, REU is deeply involved in regulatory rulemaking processes alongside CMUA and other utility groups, advocating for favorable outcomes and preparing for potential financial impacts. These proactive measures ensure that REU is well-positioned to navigate the evolving legislative and regulatory landscapes effectively.