The URL can be used to link to this page

Home My WebLink About _ 9.5(b)--Electric Utility's Quarterly Report - 3rd QuarterREPORT TO THE CITY COUNCIL MEETING DATE: June 3, 2025 FROM: Nick Zettel, Director of ITEM NO. 9.5(b) Redding Electric Utility ***APPROVED BY*** 51 cic ct c , yrecto € f c in) tric Utility SUBJECT: 9.5(b) --Consider Redding Electric Utility's Quarterly Financial Report and Industry Activities Update. Recommendation Accept the City of Redding Electric Utility's Fiscal Year 2024-25 Third Quarter Financial Report and Industry Activities Update. Fiscal Impact There is no fiscal impact related to accepting this report. Alternative Action The City Council (Council) could choose not to accept the report and provide further direction to staff. 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. Higher revenues and savings in System Operation and Maintenance (O&M) expenses offset increased power costs. The favorable financial results and a decline in unrestricted reserves are primarily driven by a $2.1 million increase in inventory during the fiscal year and $6.1 million in encumbrances, representing commitments for future expenditures. Although unrestricted reserves decreased by approximately $4.8 million through March, the cash reserve balance complies with the Council's Financial Management Policy. In addition, it aligns with REU's five-year financial plan, which forecasts unrestricted reserves declining until proceeds from the bond financing are received and used to replenish reserves ($19,761,492 of bond proceeds were received subsequent to quarter -end on April 11, 2025). Report to Redding City Council May 27, 2025 Re: 9.5(b) --Electric Utility's Quarterly Report - 3rd Quarter Page 2 Revenue As of March, Billed Retail Revenue was $8,767,139 (8.7 percent) above budget, primarily driven by warmer weather that increased overall energy usage. Additionally, colder -than -average temperatures in January and early February contributed to higher-than-expected demand during those months. Total wholesale sales were $6,983,569 (61.9 percent) above budget. Overall, operating revenue was $1.7,364,689 (15.3 percent) above budget. Operating revenue after energy costs was $11,908,238 (21.3 percent) above budget. The primary drivers for increased wholesale sales were sales of excess energy into the California Independent System Operator (CAISO) due to our favorable hydro conditions. Expenses Power Cost (Cost of Energy) The combined costs for generation, purchases from the Western Area Power Administration (WAPA), Big Horn Wind Project, contracts, and the spot market were $5,456,452 (9.4 percent) above budget projections. The Redding Power Plant generation costs were higher than anticipated, due to increased wholesale sales. The total cost of energy decreased by $5,692,488 (8.3 percent) year over year. The Power Cost for the load (Power Cost less Wholesale Sales) increased by $2,008,423 year over year due to reduced wholesale sales (4.7 percent). System Operations & Maintenance (O&M) System O&M costs are aligned with budget projections. Debt Service and Capital Outlay Debt service payments and obligations through March totaled $10.8 million (on plan). Capital expenditures totaled $10.6 million (44.7 percent spent). The pace of capital expenditures remains delayed due to extended lead times for procuring high -demand items, particularly those requiring specialized materials. While the severity of supply chain challenges has eased somewhat, longer lead times, increased shipping costs, tariffs and trade policies, and raw material constraints continue to affect the timing of capital projects Special Fund Expenditures Special Fund Expenditures, which include spending for Public Benefit and Cap -and -Trade Programs, totaled $1,971,061 (representing 23.9 percent of the budget) through March. Electric Utility Unrestricted Cash Balance At the end of March, the unrestricted cash balance was $35.8 million, representing approximately 98 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. Director's Contingency Fund The REU Director's Contingency Fund was not utilized through March. Report to Redding City Council May 27, 2025 Re: 9.5(b) --Electric Utility's Quarterly Report - 3rd Quarter Page 3 Environmental Review This is not a project defined under the California Environmental. Quality Act, and no further action is required. Council Priority/City Manager Goals • Budget and Financial Management — "Achieve balanced and stable 10 -year Financial Plans for all funds." c: Finance Director Attachments Attachment 1 - Notes on Financial Operating Statement Attachment 2 - Electric Utility Financial Results for Mar 2025 Attachment 3 - Electric Utility Financial Dashboard for Mar 2025 Attachment 4 - Electric Utility Unrestricted Cash Balance Mar 2025 Attachment 5 - Electric Utility Industry Update 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; 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 Independent 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 IANC), 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 include selling natural gas and replacing it with less expensive electricity than burning the gas 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 and not on the net benefit to the Utility. 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 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 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, 2025 System Load (MWh) 593,491 551,821 7.6% 41,670 576,244 ey Performance Indicators Days Cash on Hand 98 Operating Revenues 107 Retail Sales 109,772,439 101,005,300 8.7% 8,767,139 99,181,760 Wholesale Sales 18,268,159 11,284,590 61.9% 6,983,569 25,969,070 Miscellaneous Incomes 3,057,334 1,443,353 111.8% 1,613,982 582,697 Total Operating Revenues 131,097,932 113,733,243 15.3% 17,364,690 125,733,527 Operating Expenses Power Cost 4,034,442 6,009,608 -32.9% (1,975,165) 3,593,704 Purchased Power 16,747,658 12,750,500 31.3% 3,997,158 13,885,983 Generation, Transmission and JPA (Variable) 24,688,441 23,431,875 5.4% 1,256,566 31,426,260 Generation A&G and O&M (Fixed) 21,847,375 21,644,648 0.9% 202,728 23,663,720 Subtotal Power Cost 63,283,475 57,827,023 9.4% 5,456,452 68,975,963 System O&M General & Administrative 4,034,442 6,009,608 -32.9% (1,975,165) 3,593,704 Interdepartmental (Incl. In -Lieu of Tax)Z 9,483,133 9,362,693 1.3% 120,440 9,983,045 Transmission & Distribution 24,042,860 22,754,689 5.7% 1,288,171 21,709,329 Customer & Field Services' 2,377,250 2,377,253 0.0% (2) 2,416,140 Subtotal System O&M 39,937,685 40,504,241 -1.4% (566,556) 37,702,217 Total Operating Expenses $ 103,221,160 $ 98,331,264 5.0% $ 4,889,896 $ 106,678,180 Net Operating Revenue $ 27,876,772 $ 15,401,979 81.0% $ 12,474,794 $ 19,055,347 Total Debt Service $ 10,791,423 $ 10,801,515 0% $ (10,092) $ 10,788,980 Capital Outlay Capital Outlay (Revenue Funded) 3,194,854 Capital Outlay (Bond Funded) 10,624,160 23,745,800 44.7% 13,121,640 2,991,987 Total Capital Outlay $ 10,624,160 $ 23,745,800 44.7% $ 13,121,640 $ 6,186,841 Special Fund Expenditures Public Benefit Programs 1,777,812 5,090,700 34.9% 3,312,889 1,762,193 Cap -and -Trade Programs 193,250 3,171,670 6.1% 2,978,420 515,170 Total Special Fund Expenditures $ 1,971,061 $ 8,262,370 23.9% $ 6,291,308 $ 2,277,363 Financial Results $ 4,490,128 $ (197,837) CHANGES IN FY2024/FY2025: ' Customer Services and Field Services are removed from the Electric Department's Financial Results, and an allocation of expenses is recorded. 2 Interdepartmental Allocations are not assigned to various divisions within the Electric Department as in previous years but recorded as its own category. ELECTRIC UTILITY FINANCIAL DASHBOARD - MARCH 31, 2025 ELECTRIC UTILITY FINANCIAL DASHBOARD - MARCH 31, 2025 REU UNRESTRICTED CASH BALANCE JULY 2023 - JUNE 2025 � j \ ) \ \ { ! City of Redding Electric Utility Industry Activities Update —3rd Quarter FY2025 Federal Update The Trump administration and congressional Republicans have proposed legislation to roll back key clean energy tax credits established under the Inflation Reduction Act (IRA), specifically credits 48E and 45Y. These credits have been instrumental in promoting investments in renewable energy projects. In Congress, a bipartisan group introduced the "Fix Our Forests Act," a legislative initiative to overhaul federal forest management to mitigate catastrophic wildfires, restore forest ecosystems, and enhance community safety. Introduced in both the House (H.R. 8790) and Senate, the bill is spearheaded by Representatives Bruce Westerman (R -AR) and Scott Peters (D -CA), along with Senators Alex Padilla (D -CA), John Curtis (R -UT), John Hickenlooper (D -CO), and Tim Sheehy (R -MT). In October 2024, FERC released Order 1977-A, addressing the siting of interstate electric transmission facilities. This order seeks to streamline the permitting process for critical transmission projects, potentially affecting how municipal utilities engage with regional transmission initiatives. Also, in April 2025, FERC issued Order 1920-13, refining its earlier directives on regional electric transmission planning and cost allocation. This order aims to enhance grid reliability and accommodate the growing electricity demand, particularly from renewable sources. Mayor Pro Tempore Erin Resner, Director Nick Zettel, and Assistant Director Joe Bowers represented the City of Redding and Redding Electric Utility (REU) at the 2025 Federal Policy Conference jointly hosted by the Northern California Power Agency (NCPA) and Northwest Public Power Association (NWPPA). The annual event brings together public power leaders from across the Western. United States to engage with federal policymakers on the most pressing energy and infrastructure issues facing their communities. While the conference covered a wide range of topics reflecting the broad and diverse membership of NCPA and NWPPA, REU focused its federal advocacy on several core priorities essential to maintaining affordable and reliable electricity for Redding's residents and businesses. Key issues included the protection of federal hydropower and CVP resources, workforce stability for generating agencies and power marketing administrations, wildfire risk reduction and liability reform, infrastructure financing and tax policy, and continued engagement with federal policymakers. State Legislative Update Between October 2024 and March 2025, several legislative developments in California have emerged that could significantly impact municipal electric utilities. Key areas of focus include grid modernization, renewable energy integration, rate structures, and energy equity. Senate Bill 797 seeks to exempt certain electric utility distribution and transmission system facilities from the California Environmental Quality Act (CEQA) when projects involve undergrounding and insulation. This measure aims to expedite grid hardening efforts to mitigate wildfire risks. The California Legislature is preparing to consider the reauthorization of the state's Cap -and -Trade program, which will be renamed "Cap -and -Invest." The goal is to extend the program beyond its current 2030 expiration while placing greater emphasis on how auction revenues are reinvested particularly in disadvantaged communities and clean technology. While the core cap -and -trade structure will remain, changes to allowance allocation, revenue use, and equity requirements are being discussed. REU is monitoring this closely to assess potential impacts on utility operations and customer programs. Senate Bill 647 focuses on equitable building decarbonization by enhancing low-income energy assistance programs. The bill aims to support under -resourced communities in transitioning to cleaner energy solutions. State Regulatory Update The California Air Resources Board (CARB) has indicated that the 45 -day public comment period for proposed Cap -and -Trade regulatory amendments is expected soon and will likely be announced in the coming weeks. Any updates to the 2025 regulation would have required board approval in October 2024; therefore, any upcoming regulatory amendments won't take effect until 2026. In October 2024, the California Energy Commission (CEC) issued a Notice of Proposed Scope for revisions to the Renewables Portfolio Standard (RPS) Eligibility Guidebook, which is now moving toward its 10th edition. This proposed scope includes 18 areas for potential updates to better align. the RPS with technological advancements and evolving grid needs. The RPS Guidebook is exempt from the full rulemaking process, which means the CEC can adopt changes to the Guidebook through a regularly scheduled business meeting. The California Municipal Utilities Association (CMUA) submitted comments on behalf of its members, which addressed concerns around energy storage and dynamically transferred facilities. A follow-up scoping meeting is scheduled in May to go over the proposed updates and address issues raised during the previous comment period. The California Air Resources Board (CARB) recently withdrew the Advanced Clean Fleets (ACF) waiver, meaning the regulation no longer applies to private fleets. This decision significantly shifts the regulatory landscape and raises questions about compliance expectations for public agencies. In response, NCPA and CMUA are actively engaging with the Legislature and the Governor's Office to advocate for regulatory changes that reflect the new reality and address the challenges utilities and public fleets may face as a result. REU is tracking these efforts to understand potential impacts on fleet planning and long-term compliance strategies. Senate Bill 1158, adopted on September 16, 2022, mandates that starting January 1, 2028, every retail seller in California must report hourly data on their electricity sources used to serve loss - adjusted load for each hour of the previous calendar year, including the associated greenhouse gas emissions. This legislation seeks to enhance transparency and accuracy in tracking renewable energy usage and emissions, thereby helping California achieve its climate goals more effectively. The Bill tasked the CEC with developing and adopting the reporting rules through an open process by July 2024. REU has been collaborating with the CMUA to provide feedback to the CEC, ensuring the reporting requirements are reasonable, not overly restrictive, and avoiding placing undue burdens on retail sellers and their customers. Conclusion REU staff, in close coordination with the Northern California Power Agency (NCPA) and the California Municipal Utilities Association (CMUA), are actively engaging with legislative staff to advocate for public power interests. This includes requesting and in some cases drafting amendments to ensure that emerging legislation protects our ability to deliver safe, reliable, and affordable service to our customers. As one of the lowest -cost electric providers in California, Redding Electric Utility remains committed to maintaining affordability while meeting state energy and climate goals. Ongoing legislative engagement is essential to preserving local control, operational flexibility, and rate stability for our community. Energy System Load (MWh)593,491 55,7. 7. 4.,670 576,744 Key Performance Indicators Days Cash on Hard 98 107 Operating even es Retail Saes 109,777,439 101,005,300 8.7% 8,767,139 99,181,760 Miscellaneous income' 31057,334 1,443,353 M.8% 1t6131982 582,697 Total Operating Revenues 131,097,932 113�733,243 15.3% 17,364,690 125,733�527 Operating Expenses Power Cost .► « • w Customer Field Services' 7,377,750 7,377,253 0.0% (2)2,416,140 Subtotal System O&M 39,; 37,685 40,504,241 -1 4 (566,556) 37,7 ?,7 7 Total Operating Expenses 103,221,160 •: 106,670,180 Net Operating Revenue 27�870,772 isAOI1979 8i.0% 120,474,794 • Net Operating Revenue 27,876,772 15,401,979 81.0% 12,474,794 19,055,347 TolLal Debt !(10j092) $ 10178$1980 Capital Fitly Capital Outlay (Revenge traded) 3,194,854 Capital Outlay(Bond Funded) 10,674,160 23,745,800 443% 13,172,640 2,991,987 Total : p t l Outlay 10,624,160 $ 23,745,800 44.7 $ 13,121,640 $ 6,186,841 EMenditures Public Benefit Programs 1,777,812 5,090t700 34.9%s « Cap-and4rade Programs 193250 3,1711670 6.1% 2,978,420 515,170 Total Special Fund Expenditures 1,97LO61 8,2620370 23.9% 6,291,308 $ 2,277t363 Financial Results a(197,837) CHANGES IN E 2 2 / Y20 Customer Services and Fie#d Services are removed from the Electric Department's ent's ire ra l Results, and an allocation of expenses is recorder. Interdepartmental Allocations are not assigned to various divisions within the Electric Department rtment s in previous years but recorded as its own category. 3 ( UtY 1 r tt t REU UNRESTRICTED CASH BALANCE JULY 2023 - JUNE 2025 0, 6 5. 0 n 0 55.0 50,0 z wrw.e^, 5, 0.,..i ,0 J d Minimum 0,0 r Policy #..0 ,o n,`p� �� h 2024-25 33,5 3 8, �=� 3 8, 9 am`��•,'u , ,c$� 3 3 .'2 32,6 *..SE �..;i . " ' 36,6 35,8 L }