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Home My WebLink About _ 9.5(a)--Electric Utility's Financial Report - 2nd Quarter GI �" Y C� F � � �- ' � ° � � i � CITY OF REDDING �� REPORT TO THE CITY COUNCIL MEETING DATE: February 17, 2026 FROM: Nick Zettel, Director of ITEM NO. 9.5(a) Redding Electric Utility ***APPROVED BY*** �` � � ,� �k et e �rcctor�i9' e in r tric�Llt'rtity �13t2��G � ibl�T,Pers�n�lel T7ig�ctar � ?I12/2426 nzettel@cityofredding.org kkibler@cityofredding.gov SUBJECT: 9.5(a)--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 Second Quarter Financial Report and Industry Activities Update. Fiscal Impact There is no �scal impact related to accepting this report. AZteNnative Action The City Council (Council) could choose not to accept the report and provide further direction to staff. Background/Analysis The attached December Financial Report shows that Redding Electric Utility (REU) outperformed budget projections in Net Operating Revenues for the first six months of the fiscal year. While slightly higher revenues and lower Power Cost and Generation/System Operation and Maintenance (O&1V1) contributed to the positive results, the variance was primarily driven by the timing of expenses and deferred activities. These timing differences are temporary and are expected to fully align with budgeted assumptions in future reporting periods. Although unrestricted reserves decreased by approximately $6.1 million through Deeember, the Utility anticipates approximately $3 million in reimbursements in February for second-quarter capital outlays. For context, the Utility received $6.5 million in bond reimbursements in November for first-quarter capital outlays. The cash reserve balance remains in compliance with the Council's Financial Management Policy. Report to Redding City Council February 12,2026 Re: 9.5(a)--Electric Utility s Financial Report-2nd Quarter Page 2 Revenue Billed retail revenue through December was $993,043 (1.3 percent) above budget, reflecting elevated system energy usage during the period, influenced in part by seasonal weather conditions. Total wholesale sales were $40,261 (0.5 percent) above budget. Overall, operating revenue was $1,220,171 (1.4 percent) above budget. Operating revenue after energy costs was $2,007,670 (4.7 percent) above budget, primarily driven by higher-than-budgeted retail revenue, with secondary contributions from lower-than-budgeted generation, transmission, and Joint Powers Agency costs. Timing differences in certain operating expenses also contributed modestly to the variance and are expected to normalize in subsequent reporting periods. Expenses Power Cost (Cost of Ener�y) The combined costs for generation, purchases from the Western Area Power Administration (WAPA), Big Horn Wind Project, contracts, and the spot market were $787,500 (1.8 percent) below budget projections. This variance is within normal budgetary expectations and reflects routine fluct�uations in energy procurement and operating conditions during the period. The total cost of energy increased by$1,025,996 (2.5 percent) year over year. The Power Cost for the load (Power Cost less Wholesale Sales) increased by $1,538,414 year over year (4.6 percent), primarily reflecting changes in net energy procurement and system operating conditions. Svstem Operations & Maintenance(O&M� System O&M costs for the first six Inonths of the fiscal year were $3,966,514 (12.9 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. Debt Service and Capital Outlay Debt service payments and obligations through December totaled $9.4 million (on plan). Capital expenditure totaled $9.1 million (47.8 percent spent). The pace of spending is consistent with expectations for this stage of the fiscal 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 for Public Benefit and Cap-and-Trade Programs, totaled $1,671,234 (repres�nting 1'7.0 percent of th� budget) through December. 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. Report to Redding City Council February 12,2026 Re: 9.5(a)--Electric Utility s Financial Report-2nd Quarter Page 3 Electric Utility Unrestricted Cash Ba�ance At the end of December, the unrestricted cash balance was $39.1 million, representing approxiinately 96 days of cash on hand. REU's Financial Management Policy (Council Policy 1414)requires a minimum of 75 days of cash and aims for 150 days of cash. With the anticipated receipt of approximately $3.0 million in bond reimbursements in February related to second- quarter capital outlays, unrestricted cash is expected to increase by approximately 7 days, resulting in approximately 103 days o�cash on hand, further strengthening compliance with the Council's financial policy. Director's Contingency Fund The REU Director's Contingency Fund was not utilized through December. EnviNonmental Review This is not a project defined under the California Environmental Quality Act, and no further action is required. Council Prior�ity/City Manage� 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 - Electric Utility Financial Results for Dec 2025 Attachment 3 - Electric Utility Financial Dashboard for Dec 2025 Attachment 4 - Electric Utility Unrestricted Cash Balance Dec 2025 Attachment 5 - Electric Utility Industry Update far Dec 2025 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- DECEMBER 31, 2025 s ' -t• e � � e ... � . B' ' ' �' ' ' ' �' ' ' f . ! . 6 . i . 6 � A� .4 � � �, ., . , ,, . a e . ., , . . . � . ,.. <. � Energy 4, _� �. 4 ..,, � . � � System Load(MWh) 414,675 410,177 1.1% 4,498 430,910 Key Performance Indicators Days Cash on Hand 96 89 Operating Revenues Retail Sales 78,797,043 77,804,000 1.3% 993,043 78,224,304 Wholesale Sales 7,880,801 7,840,540 0.5% 40,261 8,393,220 Miscellaneous Income 1,136,616 949,750 19.7% 186,866 3,539,651 Total Operating Revenues 87,814,461 86,594,290 1.4% 1,220,171 90,157,175 Operating Expenses Power Cost Purchased Power 12,729,671 10,265,200 24.0% 2,464,470 10,359,442 Generation,Transmission and JPA(Variable) 16,168,318 17,265,200 -6.4% (1,096,882) 16,774,894 Generation A&G and O&M(Fixed) 13,777,575 15,932,664 -13.5% (2,155,089) 14,515,232 Subtotal PowerCost 42,675,564 43,463,064 -1.8% (787,500J 41,649,568 System O&M General&Administrative 2,841,640 4,032,166 -29.5% (1,190,526) 2,558,965 Interdepartmental(Incl.In-Lieu of Tax) 5,862,325 5,871,345 -0.2% (9,020) 6,362,235 Transmission&Distribution 16,469,716 19,236,684 -14.4% (2,766,968) 15,200,099 Customer&Field Services 1,707,680 1,707,680 0.0% (0) 1,584,834 Subtotal System O&M 26,881,360 30,847,874 -12.9% (3,966,514J 25,706,133 Total Operating Expenses $ 69,556,924 $ 74,310,938 -6.4% $ (4,754,013) $ 67,355,700 Net Operating Revenue $ 18,257,536 $ 12,283,353 48.6% $ 5,974,184 $ 22,801,475 Total Debt Service $ 9,361,273 $ 9,374,400 0% $ (13,128) $ 7,188,302 � , .• . . .• .• e x � �• .- .- w- .• c - a . o . � . � o � # �..�m rz.. .v..�w� n .�y..�,. ...a w.,�.v ..�, n��w�.t_ �.., � .� 5 �,...w.� � , �,�.... ,�.....�....,...,.. � .......� �. . ��,.�..,� ..��.�.a.� �...n�.�. CapitalOutlay ��„ �� Capital Outlay(Revenue Funded) 8,221,726 Capital Outlay(Bond Funded) 9,067,693 18,952,000 47.8% 9,884,307 - Total Capital Outlay $ 9,067,693 $ 18,952,000 47.8% $ 9,884,307 $ 8,221,726 Special Fund Expenditures Public Benefit Programs 1,085,519 6,974,765 15.6% 5,889,246 1,182,049 Cap-and-Trade Programs 585,714 2,866,370 20.4% 2,280,656 63,467 Total Special Fund Expenditures $ 1,671,234 $ 9,841,135 17.0% $ 8,169,901 $ 1,245,517 Financial Results $ (1,842,663) $ 6,145,930 ELECTRIC UTILITY FINANCIAI. DASHBOARD - DECEMBER 31, 2025 IR�tail Sal�s ($- �Ilions� ` �„�'�'�"��Cumulative DiFference ��2025��ctual 2026'�Actual : �� ' 2026&ud��t ' �' 1� i €r t ' � �� , i' � �� i' � 14 t' i �� .. .; , , �,�� : . ;�: �' ��u 2 �� r c ... .. {tf..: . y. � ........_: t.. ....: ....�.._ �..,.�. .... 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Jf��.��. ��+', �� ! ;,�� „'l � i" ��,�Curnulative Difference ��2025 Actual 2026 Acfi�aal 2026 6udget � � 5 � � � � 4 ', � ,�. ; � � i r C' � 1 � � s� t ��'��n� �. i. a �e 'aw�� ,,y��'� � , ,...��.: �M..: �.....n: ... ...,��4 .w�.ro.,� ....r.�. �. ��. p i � ; t j �.0 i s s � �� -0.2 4 -0.1 ` � � $ � �� ) �� ; � ,' ...... ._.. ..._,..�. ..�.�..;k ....., l ......._.:� .,....,.. ...__...: ........, k :. /��ry ......... _..,... �' V.7 .i k � � t c � � y i; � �� ,.� ��. k � � � [ � � � t ,,,,, � ,( �,,� �, � � ,, � .,. � ,, � . 3 : E . 1. �� , � .. ,��.,u,mm,'�$��,.� �M��..�,,,,�, r,� .��u.n�&. .�.,,�.r�: � �.N,,:��, e.we„�� w�,e,,,, � ,�e�n.,��.ro ..,...�>,��,.�� 1,�_,�,..» } JUL ;4U� SEP t7C7 IUOU [7�C JA�1' FE�' MAR PPR M/�1' 1U� � ELECTRIC UTILITY FINANCIAI. DASHBOARD - DECEMBER 31, 2025 T�t�l p�ratin� eve�u�s ($- �Ili��s) Cumulatiue Diffiererrce 2025 Actual 2026 Acfival � 2Q26 Budget '�� q�. 2Q s � 1� ' �. � 1& m 14 �.�=��:a�� $ Wo��.�:W. �4aA„w�� . ��m: v �� i.s. } �.� ' _ �.,...., e �.., . ...,. A..� �� .�........ . i � ` y �j ,... ,,..�� ........�.' �.........: ....<..._1 .w. ..i ,..,.e.; ��. . ,....... ...«..e' .....,,..y .e......: ,,,,,.,.,. ...,....,e t 'i, Y �, t 1 �.,. �., a m.i � T ,,,,�. � �' �� i � �� '. � k 1 i ��. t � 4 � � m.»,,.�„w,.� �..�.„a.„�,w,S��.._..,..��.,� b��:,,,,e,3G�.,',.�,„��,.�..,tri.�> t�., ..�..,'�� a. .�,� k�. .. $„�,. ,�.;, �.. � ......�..�., � � � . l r i � � ; ; � • ; F � x � � � g � � , � � s, ° ' , � i i, ;. i, , ,,�� JtJC AiJ� SEP C�CT NO� (�EG 3AN FE� 1\fIAR �PR I1�AY Jl�l�i ; �� T�t�l �r�tir�� Exp�nse ($- illi�ns) i ""�"'. Cumulative Diff�rence 2025 Actual 2Q26�ctual ��2026 Budget ' i= �� i 1 ��. N9 e,:. � �I� f i � t ��.� �� t,� �CRSU��Rito.�i+"+'"*t". � ,s *� � .�. . . . ,'�»5�:Hv ` . i. ..re.. , . '9`t'y�R,`5..'b, �fi••• u•,:•�m• '�`^i5+1U.it3Sv � . . � � a��e�„x��ym��,.m�arm�aa�.�saeaw�.;4,:�sa�a��is�a.u�:;�,s�r'ux�'� i �V ; 3 � � ........,:, n ..,�..��.: , ,....�, � „ ,.. ...�. � ..,,...m: t ,,.....,.,e {`. t, } t t � S 3 . 3 �. t ; '+ C � � 1" r�� ...� "� .�4 l ... � iu y � y� ,, + ,..., .. ., .a,.._ .,. } � q � � � � k � � 1 , .' , , € $� F#� . 9 2yp 4 � ' j � � C � �. ; � ��. 5 � � � �. � �� y�t € �� 4 S � t 1 � .__!�,?� � �_.� �.m ' _ �.��.w...; ..��.__� .� ._��. � .._.�.,_� � �, ��p� r,y .�M�___r�:.� .w_�.m.��..w._.� � _..�_ ��,�..�TM. ! 1UL '� fiU�'�� SEP�� GT� NO1� L?EC IAN'�� FE� IV1�R �PF� MAY � �t3{�1�� ' 7�.0 65.0 60.Q 55.0 � SQ.Q � � ,a 45.0 � �, wm 40.0 _, ��~ 35.0 3Q.0 25.Q _ za.n _ Jul E�ug Sept f�ct Nav LBec Jan I'eb Mar Apr May Jura Ur�restrietecl Cash-2025-26 38.4 3�.8 40.6 42.� 42.0 39.1 tTn�•estricted Cash-2024-25 33.5 3$S 3�.9 34.3 33.2 32.6 33.�k 3E�.6 35.�3 5�.� 4�.1 �5.2 City of Redding Electric Utility Industry Activities Update—2nd Quarter FY2026 Federal Update Following a 43-day federal government shutdown, Congress enacted FY 2026 appropriations, restoring federal operations and funding key agencies.However,broader federal policy shifts have constrained renewable development and altered long-term incentives. These recent federal actions have created a more uncertain policy environment for clean energy resources, infrastructure investment, transportation electrification, and utility planning. In 2025, legislative actions scaled back key Inflation Reduction Act clean energy incentives and introduced tariffs on inputs critical to renewable generation, contributing to widespread project delays, cancellations, and heightened financial uncertainty across the clean energy sector. Simultaneously, a shift in federal land-use policy has constrained wind and solar development, while ongoing legal challenges to California's zero-emission vehicle authority have injected additional uncertainty into the state's transportation electrification efforts. Despite these headwinds, Congress approved a bipartisan FY 2026 appropriations "minibus" that continues funding for select energy-related programs, including grid protection, energy efficiency, wildfire management, and water and land management agencies. Federal discussions in 2026 remain focused on permitting reform, grid reliability, affordability, and forest management. Proposed reforms seek to streamline permitting timelines for energy and infrastructure projects, including hydropower, while improving forest health and wild�re resilience. Testimony from public power representatives emphasized the importance of proactive vegetation management, streamlined approvals for routine grid work, and liability reforms to protect ratepayers. Collectively, these developments reflect a shifting federal landscape that constrains renewable investment incentives, increases regulatory and legal risk, and places greater responsibility on state, local, and regional initiatives to advance reliability, affordability, and climate objectives. State Le�islative Update The second year of the 2025-26 California legislative session began in December, with several two-year bills carried over and subject to a January 31 deadline. While fewer energy-specific bills are expected in 2026, legislative priorities remain focused on energy affordability, wildfire mitigation and liability, local permitting reform, and responses to evolving federal energy policy. At the January Northern California Power Agency (NC:PA) Strategic Conference, legislative leaders emphasized affordability as the Legislature's top energy priority, identifying wildfire mitigation costs as the single largest contributor to rising electricity costs statewide. 1 State Regulatorv Update Regulatory activity continues to evolve across multiple agencies. The California Air Resources Board (CARB) repealed the private fleet provisions of the Advanced Clean Fleets regulation following developments related to a federal waiver, leaving the requirements applicable only to public fleets. As a public utility,Redding Electric Utility(REU),through the California Municipal Utilities Association (CMUA) and NCPA, continues to advocate for operational exemptions and flexibility related to daily use, mutual aid, and vehicle procurement. Updated regulatory language is expected in early 2026. CARB also released proposed revisions to the Cap-and-Invest program that would reduce greenhouse gas allowance inventories starting in 2027.These changes pose potential financial risks to electric utilities. REU and its partners are advocating for the preservation of existing allowance allocations through 2030, consistent with AB 1207, to maintain customer affordability. The California Energy Commission (CEC) adopted the l Oth Edition of the Renewables Portfolio Standard Eligibility Guidebook in December 2025, providing clarifications related to energy storage and renewable accounting. In addition, implementation of SB 1158 will require hourly emissions reporting beginning in 2028; REU is coordinating with CMLTA to ensure reporting requirements remain practical and cost-effective. The California Earthauake Authority (CEA) is developing the AB 254 Natural Catastrophe Resilience Study to evaluate long-term reforms related to insurance access, wild�re mitigation, and liability. While publicly owned utilities are not subject to the California Wild�re Fund,which administered by CEA, the study's findings are expected to inform broader wildfire risk mitigation strategies. Conclusion REU staff, in coordination with N�CPA and CMUA, remain actively engaged with policymakers to protect public power interests and ensure policies support safe,reliable, and affordable electric service. As one of California's lowest-cost electric providers, REU remains focused on maintaining affordability and reliability while navigating a changing policy environment, managing risk, advancing clean energy goals, and preserving local control and rate stability. 2