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Home My WebLink About _ 9.5(b)--Electric Utility's Financial Report - 3rd Quarter GI �" Y C� F � � �- ' � ° � � i � CITY OF REDDING �� REPORT TO THE CITY COUNCIL MEETING DATE: May 19, 2026 FROM: Nick Zettel, Director of ITEM NO. 9.5(b) Redding Electric Utility ***APPROVED BY*** � �� t� �.� � y" ,� � -� �,� � ` °° � � �'�^��.��-�.,. , -,, �k ct e o ��rcctor �i9' e in r tric�[Jtriity � � 515�`2��G G��I1a��arbc�x �'��1�a�nag�r � S11412t726 nzettel@cityofredding.org wtarbox@cityofredding.gov SUBJECT: 9.5(b)--Consider Redding Electric Utility's Quarterly Financial Report and Industr Activities U date. Recommendation Accept the City of Redding Electric Utility's Fiscal Year 2025-26 Third Quarter Financial Report and Industry Activities Update. Fiscal Impact No fiscal impact is associated with the requested action. AZteNnative Action The City Council (Council) may reject staffs recommendation and provide alternative direction. Background/Analysis The attached March Financial Report shows that Redding Electric Utility (REU) outperformed budget projections in Net Operating Revenues for the first nine months of the fiscal year. The favorable variance is primarily driven by the timing of expenses and deferred activities, with additional contributions from modestly higher revenues and lower Power Cost and Generation/System Operations and Maintenance (O&M). These timing differences are temporary and are expected to align with budgeted assumptions in future reporting periods. Although unrestricted reserves decreased by approximately $5.1 million through March, the Utility anticipates approximately $2.8 million in reimbursements in May for third-quarter capital outlays. The cash reserve balance remains in compliance with the Council's Rinancial Management Policy. Report to Redding City Council May 13,2026 Re: 9.5(b)--Electric Utility s Financial Report-3rd Quarter Page 2 Revenue Billed retail revenue through March was $2,327,795 (2.1 percent) below budget. Although overall system energy usage remained generally on target for the period, the variance in retail revenue is primarily attributable to timing differences between energy consumption and billing cycles, as meter read schedules do not align perfectly with calendar months. As a result, a portion of usage during the period wi11 be reflected in subsequent billing cycles. Minor variations in customer usage patterns also contributed to the difference and are within expected ranges. Total wholesale sales were $2,114,819 (18.2 percent) above budget, reflecting favorable market conditions and increased wholesale market activity. Miscellaneous income was $1,451,889 (101.9 percent) above budget, primarily driven by $Ll million in fiscal agent investment income recorded for July 2025 through February 2026 related to Electric Bond trustee accounts. These earnings are generated on funds held by the trustee and increase restricted cash balances; while recorded as revenue, they are associated with bond- related accounts rather than operating activities. As a result, overall operating revenue was $1,238,913 (1.0 percent) above budget. Operating revenue after energy costs was $3,489,169 (5.6 percent) above budget, primarily driven by higher-than-budgeted wholesale sales revenue. Additional favorable variance was realized from lower-than-budgeted costs related to generation, transmission, and Joint Powers Agency expenses. Timing differences in certain operating expenses also contributed modestly to the variance and are expected to normalize over subsequent reporting periods, resulting in a more typical alignment with the budget by year-end. Expenses Power Cost (Cost of Ener�� The combined costs for generation, purchases from the Western Area Power Administration (WAPA), Big Horn Wind Project, contracts, and the spot market were $2,250,257 (3.5 percent) below budget projections. This variance is within normal budgetary expectations and reflects routine fluctuations in energy procurement and operating conditions during the period. The total cost of energy decreased by $2,284,373 (3.6 percent) year over year. Power Cost for the load (Power Cost less Wholesale Sales) increased by $2,224,177 (4.9 percent) year-over- year, reflecting changes in net energy procurement and system operating conditions. Svstem O&M System O&M costs for the first nine months of the fiscal year were $4,591,800 (10.2 percent) below budget projections. The favorable variance was primarily driven by the timing of expenses and deferred activities, with additional savings attributable to personnel costs. Report to Redding City Council May 13,2026 Re: 9.5(b)--Electric Utility s Financial Report-3rd Quarter Page 3 Debt Service and Capital Outlay Debt service paylnents and obligations through March totaled $14.0 million (on plan). Capital expenditure totaled $13.8 million (55.1 percent spent). The pace of spending is consistent with expectations for this stage of the �sca1 year. These expenditures are bond-funded, ensuring that the capital program is fully supported by dedicated financing rather than impacting operating budgets. Continued monitoring will ensure that remaining projects stay on schedule and within budget throughout the year. Special Fund Expenditures Special Fund Expenditures, which include spending on Public Benefit and Cap-and-Trade Programs, totaled $2,501,569 (representing 25.4 percent of the budget) through March. Staff are actively reviewing initiatives and identifying opportunities to deploy the remaining allocated funds, ensuring that program objectives are met and resources are used effectively throughout the fiscal year. Electric Utility Unrestricted Cash Balance At the end of March, the unrestricted cash balance was $401 million, representing approximately 100 days of cash on hand. This is down from $45.2 million, or 123 days of cash on hand, at June 30, 2025. REU's Financial Management Policy (Council Policy 1414) requires a minimum of 75 days of cash and aims for 150 days of cash. The anticipated receipt of approximately $2.8 million in bond reimbursements in May related to third-quarter capital outlays is expected to increase unrestricted cash by approximately six days, to approximately 106 days of cash on hand. However, reserves remain below the Council's financial policy goal of 150 days. Director's Contingency Fund The REU Director's Contingency Fund was not utilized through March; however, several pending items are expected to draw on these funds in the coming months. Anticipated expenditures primarily relate to increased costs associated with WAPA-owned 230-kV infrastructure at the Whiskeytown Substation, as well as Power Plant system needs and maintenance activities at the Corp Yard. These costs were unexpected but necessary for ongoing operational and system requirements. Envir�onmental Review This is not a project defined under the California Environmental Quality Act, and no further action is required. Council Pr�ioNity/City Manager Goal • Budget and Financial Management — Achieve balanced and stable 10-year Financial Plans for all funds. Report to Redding City Council May 13,2026 Re: 9.5(b)--Electric Utility s Financial Report-3rd Quarter Page 4 Attachments Attachment 1 -Notes on Financial Operating Statement Attachment 2 - Electric Utility Financial Results for Mar 2026 Attachment 3 - Electric Utility Financial Dashboard for Mar 2026 Attachment 4- Electric Utility Financial Results by Major Exp. Groups for Mar 2026 Attachment 5 - Electric Utility Unrestricted Cash Balance Mar 2026 Attachment 6- Electric Utility Industry Update for Mar 2026 City of Redding Electric Utility Notes to Financial Report Notes on Financial Operating 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; and Other :Revenue, which 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 J:PA 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, efforts have been made to provide our ratepayers with the most cost-effective energy supply. This is often achieved by buying and selling natural gas or electricity to lower overall costs. This could include selling natural gas and replacing it with less expensive electricity rather than burning it at our power plant. It might also involve selling energy contracted at one trading hub and buying it at another,less expensive one.Additionally,we optimize the value of our gas storage facility by purchasing natural gas when prices are low and using or selling it in other months. All these transactions benefit our customers but tend to inflate the Wholesale Sales and Cost of Energy figures above their original budgets. This occurs because accounting rules require us to record these transactions at their gross revenue and expense amounts, not based on the utility's net benefit. System O&M Expenses summarizes 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 financial 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 an unexpected industry disruption occurs, revenue and expenses will increase or decrease accordingly. 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 ELECTRIC UTILITY FINANCIAL RESULTS—MARCH 31,2026 . -•• � � o : - , � �,.� .� u.�.��.��.� .. �. ,,.,� � �...�..,._�.��. .._. �.ww.w. �u.. r e � � � �.� �_�. ..� �N �.� ��.� �.e� . . ��v�.� ...... . .�. .._�ww.�� .�.w... . �..v.�.� Energy �.�. w_. System�oad(MWh) 573,956 573,626 0.1% 330 593,491 Key Performance Indicators Days Cash on Hand 100 98 Operating Revenues RetailSales 109,898,505 112,226,300 -2.1% (2,327,795) 109,781,575 Wholesaie Sales 13,759,609 11,644,790 18.2% 2,114,819 18,268,159 Miscellaneous Income 2,876,514 1,424,625 101.9% 1,451,889 4,244,866 Total Operating Revenues 126,534,628 125,295,715 1.0% 1,238,913 132,294,599 Operating Expenses Power Cost Purchased Power 17,544,218 14,624,900 20.0% 2,919,318 16,778,660 Generation,Transmission and JPA(Variable) 23,581,887 25,014,500 -5.7% (1,432,613) 25,586,164 Generation A&G and O&M(Fixed) 20,070,984 23,807,945 -15.7% (3,736,961) 21,116,638 SubtotaiPowerCost 61,197,089 63,447,345 -3.5% (2,250,257) 63,481,461 System O&M General&Administrativel 4,295,460 5,510,548 -22.1% (1,215,089) 3,681,533 Interdepartmental(Ind.In-Lieu of Tax)1 8,793,488 8,889,488 -1.1% (96,000) 9,483,133 Transmission&Distributionl 24,584,454 27,865,165 -11.8% (3,280,712) 22,909,696 Customer&Field Services 2,561,520 2,561,520 0.0% (0) 2,377,250 Subtotal System O&M 40,234,921 44,826,722 -10.2% (4,591,800) 38,451,612 Total Operating Expenses $ 101,432,010 $ 108,274,066 -6.3% $ (6,842,057) $ 101,933,073 Net Operating Revenue $ 25,102,618 $ 17,021,649 47.5% $ 8,080,969 $ 30,361,526 Total Debt Service $ 14,037,430 $ 14,061,600 0% $ (24,170) $ 10,791,423 � � � . e . e , t o � . .. . .n. . �. . . . . . � .� _ CapitalOutlay � � � � �� Capital Outlay(Revenue Funded) Capital Outlay(Bond Funded)Z 13,761,939 24,983,060 55.1% 11,221,121 11,969,620 Total Capital Outlay $ 13,761,939 $ 24,983,060 55.1% $ 11,221,121 $ 11,969,620 Special Fund Expenditures Public Benefit Programs 1,630,537 6,974,765 23.4% 5,344,228 1,785,359 Cap-and-Trade Programs 871,032 2,866,370 30.4% 1,995,338 188,375 Total Special Fund Expenditures $ 2,501,569 $ 9,841,135 25.4% $ 7,339,566 $ 1,973,734 Financiai Results $ (5,198,320) $ 5,626,749 CHANGES IN YTD-Budget FY2026: 'Resolution No.2026-018:Mid-year Budget modification reducing nine positions for a decrease of$1,527,560 and an increase in Interdepartmental of$82,470. Z Resolution No.2025-051 and 2026-02:Budget increase of$137,700 for Security Pipeline Fence Project and$425,000 for the Unit 9 FERc Relicense Project. Z Indudes$5,468,360 in FY2025 carryover. EI.ECTRIC UTILITY FINANCIAL DASHBOARD - MARCH 31, 2026 � ��t�il Sal�s ($- illians} �� Cumulative Difference 2025 RcivaE 2Q2&Actual 2026�udgefi ' t � l 2Q i i'� l � �� o �� .t�..�r ,� t �� ; ; 1C} �' :t�.z,� � i �� x �+ � � �� ,, �� , tft N` N �:. i�:. r�t � N � � ; [ i . x � � k ! i u � � f � � � � t `t„ � t � i �� ` ' � s l� t t ° 1 i ew, [ m � �€ � � � I " � N t . �. �� m .,w .�,_�'� �.,._� .�._� ._� ��.._M.� m.e .e..m.a �.. �...,: .� . .... �€ �,._..s �a .��_�. �� ...,�m� u.'�m.__.��._ .� .x� .,,i. 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Q�� '��.. ��?�'�. ��,��. ��'�. ��. �{��' }�F}� �� , �� EI.ECTRIC UTILITY FINANCIAL DASHBOARD - MARCH 31, 2026 °T�tal p�r�tin �venu�s ( - illio�s� � � C�arnulative Difference 2025 Actual 2026 Actual �� 2�25�udget ' �� 2{� ' � �� j. � x � � 16 � 14 x �� ' � ��..,,,.� � I2 �`� 1U �'� } :, a g ' . �� , .�' .; , , . . _ �� ww ., , ;� k: � �. . u w.,��: �.0 m.e.��. t l � } ...,..,....t l ...... t ....�q:. �: �...v: � e.,m.: .,� .,..a....... .�. .......b., � .-.-,.�,.a... «�.....a .� u. +� ? ¢ � � i � �{ � �E � m � .. 'i 1 � � i � �..,, .�.,�,..,.,.�....�' € .,...�.,,«n �� „«,.eal,�R, �e.......,..,�,�.� yl?�. ...:,ri AM�.. n, ,� ti Q.. � �..�..�. � ..P,.�„M �, �.�:.,�,.M,��.. 1 �� i � � CS � � i G� � ;.�„„ � I � � E `t�, �3 ;� JC1C �� QlJG�: �EP�� t7CT NQU DEC J,4R1 FE� NIAR �PR M�Y 9t31� Q � k�;��,.��Cl.im�ulatiue DifFerence ��2025 Acival 2026 Actual �� 20�6 6udg�:t ' ��: 25 �� t7 ' i ,�15 �� „�� ,.,., ,. �,,,�, � �t�� ' �� ,�� x��W ,� ��, � 2� u ��,wr �, ,; � r.��..; �i..�.....� ,��,..�n s �. n. � a � t' � , ` �; �� } z �... �.. f ` ,: ; w. # ' � � � et � uy , ; u5 � � o0 4 � 7 ��.1 . ,�.,.,,.�< t , �,.....�; 3 ,...�.... ......� �SLt..�' _ .. .._..: .��, ' ,...�yp: —i., , ; ' . ,.......< .......: .,..� ., p � >� t � a `h a �v, 4 s 1°r"P C?: � ��'� � �� r 6 ; t ; � � � y , : OCi i �, � ; ` � a e + Q1 t e e . �. e � I , „' � �'. � �. o �,.. t �. � ��, � k ' F . ��. �. , E i �`(�S� ..�_.�.��,.�� ._�._` � __._...�� _..a�.�, t__�_.�.a � ._. w...� _�w...�: ��_�_._w��_._�mR��.�._�. �� ,..�..; .�t.� � JUL A,UG SEP C?Cl"' Nt�U C3EC J,4t� F�B M�R �PR tVl�'C JCI�i EI.ECTRIC UTI�ITY FINANCIAL RESUI.TS - MARCH 31, 2026 Department's Budgets/Actuals Separated into Major Expenditure Groups .. : . . -. � �� . . FY 2023-24 Actual ~ $ 44,430,319 $ 105,765,883 $ 14,014,972 $ 14,298,520 $ 178,509,694 FY 2024-25 Actual $ 44,592,574 $ 101,671,317 $ 15,996,001 $ 14,762,143 $ 177,022,035 FY 2025-26 Adopted $ 47,610,841 $ 100,864,380 $ 18,952,000 $ 18,633,800 $ 186,061,021 FY 2025-26 Amended * $ 46,083,281 $ 100,946,850 $ 24,983,060 $ 18,633,800 $ 190,646,991 FY 2025-26 Actual $ 31,428,992 $ 72,504,587 $ 13,761,939 $ 14,037,430 $ 131,732,948 FY 2025-26 Budget Remaining $ 14,654,289 $ 28,442,263 $ 11,221,121 $ 4,596,370 $ 58,914,043 % of Budget Spent 68.2%a 71.8% 55.1% 75.3% 69.1% *FY 2025-26 Amended reflects Resolution No.2026-018(mid-year budget modification),reducing nine positions for a $1,527,560 decrease in Personnel,an$82,470 increase in Materials, Supplies&Services(Interdepartmental),and a$6,031,060 increase in Capital Outlay related to Resolution Nos.2025-051 and 2026-02($562.700),and FY2025 carryover($5,468,360). ' �o.a 65.0 60.0 �s.a � �o.o _ � e� � 45.0 � �^ .��„� � 4�A . 35.0 30.0 z�.a zo.o Jul 11ug Sept C�ct Nov Dec Jan Feb l�iar Apr Iviay J�an �IJnrestriet�d Cash-2025-26 35.� 36.£3 �&0.6 �2.9 �k2.0 39.1 3f3e2 35.7 ��0.1 �ITnrestricted Cash-2024-25 33.5 3�,� 3�.9 34.3 33.2 32.6 33.4 3E�.6 35.�3 54.4 48.1 45.2 City of Redding Electric Utility Industry Activities Update—3rd Quarter FY2026 Federal Update During this reporting period, Northern California Power Agency (NCPA) and its members participated in the American Public Power Association (APPA) 2026 Legislative Rally in Washington, D.C., engaging with federal policymakers on key issues, including hydropower operations, wildfire liability and prevention,permitting reform, and increasing electricity demand driven in part by data center growth.These discussions were generally well-received by legislators. At the federal level, Congress continues to work toward FY 2026 Department of Homeland Security(DHS) funding,while the Senate Energy and Natural Resources Committee recently held hearings highlighting concerns over rising electricity demand and costs. Federal agencies are advancing portions of the clean energy agenda,with the Department of the Interior(DOI)resuming approvals of solar and wind projects and the Department of Energy (DOE) proceeding with funding for hydropower, hydrogen, carbon capture, and grid infrastructure initiatives. Permitting reform and wild�re mitigation remain key priorities. Proposed legislation, including the PERMIT Act (I�.R. 3898), seeks to streamline Clean Water Act permitting. At the same time, draft transmission reform proposals could expand the Federal Energy Regulatory Commission's (FERC)jurisdiction to include public power utilities. The proposed Wildfire and Grid Reliability Act (5.4193) would provide significant grant funding to support wildfire risk reduction and grid resilience. Additionally, the Environmental Protection Agency's (EPA) proposed hydropower rule would limit state authority under the Clean Water Act and impose stricter review timelines, potentially affecting future permitting for facilities such as the City-owned Whiskeytown generator. Overall, the evolving federal landscape presents both opportunities and challenges for Redding Electric Utility (REU), including increased permitting complexity, regulatory uncertainty, and continued pressure on resource planning and reliability. State Le�islative Update The State Legislature is considering over 40 bills affecting the electric industry,including wildfire mitigation, electricity pricing, distributed energy resources, and potential extension of the Diablo Canyon facility.Key legislation includes SB 905 (Becker),which would establish a reimbursement program to offset ratepayer costs for electrification, public purpose programs, and wildfire mitigation, and AB 1820 (Schiavo), related to EV charging permitting fees, which has received a "N�ot Favor"position from California Municipal Utilities Association(CMUA) and N�CPA. The second year of the legislative session began in December, with several two-year bills carried over that may continue to impact the electric industry. The Legislature must act on these bills by January 31 to advance them. While fewer new energy bills are anticipated in 2026, key priorities remain focused on energy affordability, 1oca1 permitting reform, wildfire liability, and responses to evolving federal energy policies. 1 At NCPA's Strategic Conference in Sacramento, affordability was identified as the Legislature's top priority, with wildfire mitigation costs remaining a primary driver of rising energy costs statewide. Most legislation relevant to publicly owned utilities (POUs), including REU, is currently moving through committee,with ongoing engagement by NCPA and CMUA to advocate for public power interests. State Regulatorv Update The California Air Resources Board (CARB) has revised the Advanced Clean Fleets (ACF) regulation, delaying the 100% zero-emission vehicle (ZEV) requirement from 2027 to 2030 and expanding applicability to all public agencies. While added exemptions provide some flexibility, compliance challenges remain due to high costs, limited vehicle availability, and operational constraints—particularly for emergency response and reliability. REU will continue working through CMUA and NCPA to advocate for additional flexibility and realistic implementation. On the Cap-and-Invest program, CARB's initial proposal would have reduced allowance allocations for electric utilities beginning in 2027,undermining AB 1207's affordability objectives by limiting the number of allowances available to offset power supply costs. For REU, this would have resulted in a loss of more than 59,000 allowances, valued at approximately $3.53 million, directly impacting ratepayer costs. Following extensive stakeholder engagement and over 700 comment submissions, CARB's updated 15-Day Language reflects a more favorable outcome for REU,providing nearly 70,000 additional allowances for the 2027-2030 period.While this revision acknowledges how utilities procure clean energy and mitigate impacts for REU,many other POUs and all investor-owned utilities (IOUs) would still experience reduced allocations, effectively penalizing early carbon reduction efforts. As a result, CMUA, NCPA, and the Joint LTtility Group (JUG)are expected to oppose the current proposal and advocate for maintaining original allocation levels through 2030 to support affordability and equitable treatment across utilities. At the state level, wildfire liability reform remains a key issue. The California Earthquake Authority's AB 254 study outlines potential structural changes, including modifications to inverse condemnation and limitations on utility liability exposure. These proposals may shape future legislation, with REU continuing to engage to ensure balanced,practical solutions. Additional regulatory efforts include implementation of SB 1158 (hourly emissions reporting beginning in 2028) and CPUC-1ed gas planning and decarbonization pilots under SB 1221. REU, in coordination with CMUA and NCPA,will continue to monitor and participate in these processes to protect affordability, maintain operational flexibility, and support achievable compliance. Conclusion REU staff, in coordination with NC:PA and CMUA, are actively engaging with legislators and regulators to protect public power interests and support policies that ensure safe, reliable, and affordable service. As one of California's lowest-cost electric providers, REU remains committed to maintaining affordability and reliability while advancing state clean energy goals, minimizing risk, and preserving local control and rate stability. 2