The 60 kV Tax on Lodi
The 60 kV Tax on Lodi
How a Wheeling Charge Reveals a Deeper Transmission Problem
LodiEye Analysis — May, 2026
Summary
Six miles from downtown Lodi, the Northern California Power Agency operates the Lodi Energy Center — a 311 MW combined-cycle gas plant in which the City of Lodi holds a 30 MW (~10%) stake. For fourteen years that plant has been geographically adjacent to Lodi Electric Utility's customers but electrically distant from them, separated by a constrained PG&E 60 kV system that fails NERC contingency standards.
The Northern San Joaquin 230 kV Transmission Project, scheduled for energization in December 2029, will close that gap. The visible consequence is more than $8 million per year in eliminated transmission wheeling charges. The structural consequences — resource deliverability, congestion exposure, fast-ramp value capture, and incremental capacity for growth — are larger in aggregate and far less visible. After 2029, NCPA's biggest investment in Lodi and NCPA's biggest load served in Lodi will finally share one electrical system.
Adjacent geographically
Six miles southwest of downtown Lodi, on a 4.4-acre site adjacent to the city's wastewater treatment ponds at White Slough, sits one of the cleanest combined-cycle natural gas power plants in the United States. The Lodi Energy Center has been running there since November 2012. It generates roughly 1.6 million megawatt-hours per year — enough electricity to serve close to 300,000 California homes. Its participants include the cities of Santa Clara, Healdsburg, Ukiah, Lompoc, Azusa, Biggs, Gridley — and Lodi.
The Lodi Energy Center (LEC) is a 296-megawatt facility — recently upgraded to approximately 311 MW after the California Energy Commission approved new Siemens FX hot gas path components in March 2025 — operated by NCPA on city-owned land at 12745 Thornton Road. The plant was the first in the nation to deploy "fast-start" combined-cycle gas turbine technology, capable of going from cold start to full power in under an hour. That flexibility was designed from the outset to complement California's growing solar and wind fleet, ramping up when renewable output dips and standing down when it returns.
The geography is straightforward. LEC sits at White Slough, immediately west of the City of Lodi's Water Pollution Control Facility. To its west runs an existing PG&E 230 kV transmission corridor — the bulk transmission backbone that connects the Bay Area to the Sacramento region. Immediately adjacent is NCPA's older 49 MW Combustion Turbine #2 (the "STIG" plant), built in 1996, sharing the same 230 kV switchyard. When LEC was designed, NCPA chose the site specifically because it could tie directly into that existing switchyard with no new transmission required. The plant has co-existed with Lodi at a physical distance of about six miles for fourteen years.
NCPA's portfolio and Lodi's place in it
Understanding what the 230 kV reconnection means for Lodi requires placing LEC inside NCPA's full generation portfolio. The agency operates approximately 778 megawatts of generating capacity across geothermal, hydroelectric, and natural gas resources, providing roughly 57 percent of that capacity carbon-free. Lodi participates in each project class through its NCPA membership.
NCPA's 778 MW generation portfolio by resource class
Source: NCPA published portfolio descriptions and project disclosures. Geothermal resources are NCPA's two plants at The Geysers in Lake County. Hydroelectric capacity is NCPA's Calaveras / North Fork Stanislaus system. Natural gas capacity includes the Lodi Energy Center, NCPA Combustion Turbine #2 at Lodi, and additional combustion turbines at member sites.
LEU's retail power supply is roughly 68 percent carbon-free, which exceeds NCPA's portfolio average because Lodi layers renewable power purchase agreements on top of its NCPA project entitlements. The plant Lodi can see from Interstate 5 supplies one important but not dominant resource within that mix.
Who owns the Lodi Energy Center
Within LEC itself, capacity is allocated across thirteen project participants under the project's foundational financing agreements. The breakdown is publicly documented in Fitch Ratings' analyses of the LEC revenue bonds, where each participant's share of project cost and capacity is disclosed for the benefit of bondholders. Lodi's geographic proximity to the plant is not matched by its economic stake.
Lodi Energy Center participant capacity shares
Source: Fitch Ratings analyses of NCPA's Lodi Energy Center revenue bonds (Issue One and Issue Two). The remaining 20.5% spans nine smaller participants including NCPA members Healdsburg, Ukiah, Lompoc, Biggs, Gridley, and Plumas-Sierra Rural Electric Cooperative, and non-NCPA participants including the Bay Area Rapid Transit District, the Power and Water Resources Pooling Authority, and Azusa Light & Water. MW figures calculated against LEC's post-upgrade capacity of approximately 311 MW; entitlement percentages remain fixed per the original Project Agreements.
Two structural points emerge from this picture. First, Lodi's geographic proximity to LEC is not matched by its economic stake — Silicon Valley Power, headquartered 75 miles southwest in Santa Clara, owns 2.5 times Lodi's share of a plant that sits in Lodi's wastewater treatment area. Even more striking, the California Department of Water Resources holds the single largest stake at one-third of capacity.
The implications of who holds those shares are pointed. CDWR uses its 104 MW allocation primarily to pump water down the State Water Project aqueduct — the conveyance system that moves Northern California water south. Silicon Valley Power's 80 MW allocation helps meet Santa Clara's retail load, which is dominated by one of the largest data center clusters in the United States: Equinix, Digital Realty, CoreSite, Vantage, and dozens of other operators have built campuses in Santa Clara specifically because SVP offers public-power rates well below PG&E's. In entitlement-accounting terms, more of LEC's nameplate capacity is dedicated to powering Santa Clara's data centers than to powering the City of Lodi itself. The plant's electrons don't physically flow to Santa Clara — NCPA bids LEC into CAISO and the plant dispatches into the bulk grid wherever it clears — but the financial settlement structure ties the capacity to SVP, and the load that SVP is serving with it is unambiguously hyperscale and colocation data centers.
What changes after 2029 is not the entitlement math. Lodi will continue to hold 30 MW of LEC, NCPA will continue to manage scheduling and dispatch across the full portfolio, and LEU will continue to receive its allocated share of geothermal, hydro, and gas energy. What changes is the physical efficiency with which the local generation reaches local load — and the structural cost of every other megawatt-hour in LEU's supply that has to navigate the same constrained interconnection.
Distant electrically
The disconnection is not about distance but about voltage class. LEC and the NCPA CT #2 next to it both inject power into the bulk grid at 230,000 volts. PG&E's transmission system carries that power north and south along the Brighton-Bellota corridor. Approximately 12 miles to the east, PG&E's Lockeford Substation steps that 230 kV power down to 60 kV for local distribution.
Lodi Electric Utility's load takes service at 60 kV from PG&E's local system. The 60 kV network between Lockeford and the LEU Fred M. Reid Industrial Substation is the path by which power reaches Lodi homes and businesses. It is also, according to California Independent System Operator (CAISO) studies dating to 2012-2013 and reaffirmed in 2017-2018, a constrained and overloaded network that fails to meet North American Electric Reliability Corporation (NERC) reliability standards under specific contingency conditions.
So the physical path of electrons from LEC to a household refrigerator in Lodi today goes something like this: 230 kV switchyard at White Slough, then north along PG&E's Brighton-Bellota 230 kV corridor, into PG&E's Lockeford Substation, step down to 60 kV, ride PG&E's constrained 60 kV system roughly five miles west, into LEU's Industrial Substation, distribution to neighborhood feeders, and finally to the meter. The plant and the customer are geographically six miles apart. The electrons travel through twenty-plus miles of varied-voltage infrastructure and pass through two voltage transformations, both of which sit on PG&E equipment.
From a CAISO market-settlement perspective, the situation is even more entangled. Because LEU takes service at 60 kV, it pays CAISO's Low Voltage Wheeling Access Charge on top of the High Voltage Access Charge — bundling the cost of both the bulk transmission system and the lower-voltage transmission system into its bill. This is a structural feature of the CAISO tariff: utilities that take service at 200 kV and above pay only the high-voltage charge, while those that take service below 200 kV pay both. By accident of how LEU was historically interconnected to PG&E's system, Lodi ratepayers have been paying for transmission infrastructure on both sides of the Lockeford voltage transformation, even though their generation supply originates at the higher voltage.
The topology shift, before and after
The visual difference between the current arrangement and the post-NSJTP arrangement is easier to grasp as a diagram than as a description. Today's path requires a 60 kV detour through a network the CAISO has flagged as unreliable; the December 2029 path keeps the bulk power at 230 kV until it reaches LEU's own transformer at the new Guild Substation.
Electrical path from LEC to LEU load — current and post-NSJTP
Diagram is a simplified topology representation, not an engineering single-line. In the current arrangement, power from LEC and the adjacent STIG plant reaches LEU customers through PG&E's 60 kV system between Lockeford and Lodi — the segment CAISO has flagged for NERC contingency violations. After NSJTP, power stays at 230 kV all the way to LEU's new Guild Substation, where LEU's own transformer steps it down to 60 kV for distribution. The Low Voltage Wheeling Access Charge embedded in LEU's transmission costs goes away.
The diagram above shows the conceptual topology. The map below shows the same change geographically. From the Lodi Energy Center at White Slough on Lodi's southwest edge, power travels northeast through PG&E's bulk 230 kV system to PG&E's Lockeford Substation roughly 16 miles away, then must come back across the constrained 60 kV system to LEU's Industrial Substation on East Thurman Road. After 2029, that final leg is replaced by a new 10.6-mile double-circuit 230 kV line directly into the new LEU Guild Substation adjacent to the Industrial Sub.
Geographic routing — how power physically reaches Lodi today and in 2029
Map shows approximate facility locations and conceptual electrical routing. PG&E's Lockeford Substation is in the unincorporated community of Lockeford, roughly 11 miles northeast of central Lodi. LEU's Industrial Substation is on East Thurman Road in east Lodi; the new PG&E Thurman Switching Station and LEU Guild Substation will be built adjacent to it. The bulk 230 kV path from LEC to Lockeford remains unchanged after NSJTP — what changes is the Lockeford-to-Lodi return leg: a constrained 60 kV path today, a direct 10.6-mile double-circuit 230 kV transmission line in 2029. Tap or click any marker for facility detail. Open base route in Google Maps →
Why this geography matters: NCPA's joint-action model
The Northern California Power Agency was founded in 1968 by a consortium of municipal electric utilities to do collectively what none of them could do alone: build large-scale generation, finance it at favorable public-power rates, share operating risk, and access wholesale markets through a single sophisticated scheduling operation. Today NCPA has sixteen members, including the cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Redding, Roseville, Santa Clara, Shasta Lake, and Ukiah, plus the Bay Area Rapid Transit District, the Port of Oakland, the Truckee Donner Public Utility District, and Plumas-Sierra Rural Electric Cooperative.
The joint-action model rests on a basic premise: pool resources, share costs, share benefits, and use shared transmission to deliver power across the CAISO grid to wherever member load happens to be. NCPA operates as a CAISO-certified Scheduling Coordinator (since 1998) and runs its own twenty-four-hour scheduling and dispatch center. Crucially, NCPA participates in CAISO as a Load-following Metered Subsystem (MSS), meaning it submits an aggregated schedule for all member load and resources rather than dealing with CAISO market settlements city by city. The MSS structure gives NCPA strong financial incentives to balance load and generation internally and not lean on CAISO real-time markets — incentives that work when the underlying transmission system can actually deliver NCPA generation to NCPA load.
The model assumes, in other words, that the transmission grid is functional connective tissue between joint-action partners. When a piece of that tissue is constrained — when a 60 kV bottleneck stands between an NCPA plant and an NCPA city — the joint-action model continues to function on paper but degrades in practice. Settlement schedules net out correctly; physical electrons take longer paths; congestion charges accumulate inside the MSS pool and get allocated back to members.
The cost of the bottleneck
The visible costs of the current arrangement come in three forms.
First is the regulatory cost: NERC compliance. CAISO's transmission planning studies determined that five PG&E 60 kV lines between Lockeford and Lodi substations were experiencing thermal overloads and voltage deviations under standard contingency scenarios. These are the system events NERC calls Category P1 (loss of a single element — one generator, one circuit, one transformer) and Category P6 (loss of two non-simultaneous elements, such as a planned outage combined with an unplanned one). Failing those tests is a reliability violation regardless of whether customers notice in any given year.
Second is the operational cost: outages. The Lodi News-Sentinel reported in 2008, when an earlier iteration of the 230 kV solution was first contemplated, that Lodi's single 60 kV transmission line from PG&E's Lockeford substation had left the city in the dark four times in three years, costing local businesses tens of thousands of dollars in lost revenue. The Enchanted Rock 48 MW emergency backup plant constructed near Lodi Lake in 2023 exists precisely because the 60 kV intertie has proven inadequate during extreme weather events. As Lodi Electric Utility explained when that backup was announced, the facility was designed to mitigate power import constraints "until upgrades are completed to Lodi's transmission intertie with PG&E as part of the Northern San Joaquin 230 kV Transmission Project."
Third is the recurring financial cost: the wheeling access charges that LEU pays to CAISO every month under the low-voltage tariff classification. The City of Lodi has stated that elimination of those low-voltage transmission access charges will save more than $8 million annually once Guild Substation is energized — a number that more than covers the annual debt service on the city's $30 to $40 million share of the project.
What 2029 changes physically
The Northern San Joaquin 230 kV Transmission Project, on which PG&E filed its CPUC application in September 2023 and for which the Final Environmental Impact Report was published in 2025, is a coordinated re-engineering of the Lodi-area transmission system across three substation sites and approximately 10.6 miles of new overhead double-circuit 230 kV line.
At Lockeford, PG&E will loop its existing Brighton-Bellota 230 kV transmission line through an expanded Lockeford Substation, upgrading the 230 kV bus to a four-bay breaker-and-a-half configuration. From Lockeford, the new double-circuit 230 kV line will run roughly west-southwest, threading through farmland along Kettleman and Harney lanes, terminating at a new PG&E facility called the Thurman Switching Station, to be built at the site of LEU's existing Fred M. Reid Industrial Substation. Adjacent to Thurman, LEU will construct its own new facility — the Guild Substation, a 230/60 kV transformer station that will step the bulk power down to the voltage LEU's distribution system requires.
The 60 kV reconfiguration is the part of the project most easily overlooked but operationally most consequential. When Guild becomes operational, PG&E will disconnect its 60 kV system from LEU's 60 kV system at the Industrial Substation. LEU's 60 kV network will source power exclusively from Guild Substation, fed from the bulk 230 kV system. PG&E's local 60 kV system in the Lodi area will be reconfigured to serve PG&E's remaining customers without crossing into LEU's territory.
The result, for the first time since LEC was commissioned in 2012, is that NCPA's largest physical investment in Lodi and NCPA's largest load served in Lodi will sit on the same electrical system, separated by roughly seven miles of overhead 230 kV transmission and one set of transformers at Guild. The roundabout path through Lockeford disappears. The 60 kV bottleneck disappears. The low-voltage wheeling charge disappears.
The visible billing-line consequence
The $8 million in annual wheeling savings is the most concrete, immediate, and easily explained consequence of NSJTP. It is also the consequence most thoroughly documented in public materials, because municipal utilities are obliged to explain rate impacts to their councils and customers.
The arithmetic is direct. Under CAISO Tariff Section 26, a non-Participating-Transmission-Owner utility taking service at 200 kV or above pays only the High Voltage Wheeling Access Charge. The same utility taking service below 200 kV pays both the High Voltage and Low Voltage components. LEU today pays both, on every megawatt-hour delivered to its system. After Guild Substation energizes, LEU pays only the high-voltage component. The difference — roughly $8 million per year, based on LEU's current load and CAISO's published wheeling rates — flows back to the utility as reduced operating cost.
Set against debt service on $30 to $40 million in capital, even at conservative municipal-bond rates, the net annual benefit is meaningful. The exact split between rate stabilization, capital reinvestment, and General Fund transfer will be a political decision made by the Lodi City Council in the years following energization. The Electric Utility currently contributes approximately $7.4 million per year to the General Fund, supporting parks, police, fire, and other city services. The temptation to absorb a meaningful fraction of the NSJTP savings into a larger General Fund transfer — rather than passing them through to ratepayers as rate stability — will be real. Public scrutiny of that decision belongs in 2029 and 2030, not in 2026.
The structural consequences
Below the visible billing line are four structural consequences that compound over time and are largely absent from public coverage of the project.
Deliverability of Resource Adequacy. Under CAISO's Resource Adequacy program, NCPA as a load-following MSS must demonstrate annually that it has procured qualifying capacity sufficient to meet its members' peak load. "Qualifying" means deliverable — that is, the capacity must actually be able to reach load under stress conditions. Today, NERC P1/P6 violations on the Lockeford-Lodi 60 kV system represent deliverability constraints on Lodi-allocated capacity within NCPA's portfolio. Resolving those violations removes a constraint that has applied to every NCPA resource counted toward Lodi's RA obligation since the violations were first identified. The administrative benefit is real, even if it never appears as a line item on a rate sheet.
Congestion exposure. CAISO operates a nodal market in which electricity prices vary by physical location. When transmission is constrained, the Locational Marginal Price (LMP) at the constrained node diverges from the system reference price. Congestion costs are settled and allocated back to load. The Lockeford-Lodi 60 kV pocket is exactly the kind of constrained sub-network where summer peak congestion can become acute. The financial impact on NCPA's MSS pool — and Lodi's allocated share of that pool — is genuine but largely invisible inside aggregated NCPA settlement data. After NSJTP, LEU's load takes service at the 230 kV bulk system, where congestion is generally lower and more predictable than at constrained 60 kV terminals.
Fast-ramp value capture. LEC's central design feature is its fast-start capability, conceived in the late 2000s as a complement to California's rising solar and wind fleet. The plant ramps up rapidly when renewable output drops and ramps down again when it recovers. NCPA bids LEC into CAISO's energy, regulation, and spinning reserve markets to monetize that flexibility. The plant's wholesale-market revenue isn't directly affected by NSJTP, because CAISO pays based on system-wide LMPs. But NCPA's ability to use LEC as a real-time load-following resource for Lodi specifically — to dispatch local generation against local load in a way that meaningfully reduces NCPA's exposure to CAISO real-time market volatility — gets sharper when the transmission path between them is no longer constrained.
Imbalance and uplift costs. When NCPA's actual hourly load deviates from its day-ahead scheduled load, the imbalance settles at real-time prices that can be highly volatile in constrained pockets. The thinner the transmission, the more forecast errors translate into expensive imbalance settlements. A robust 230 kV connection should smooth NCPA's settlement variance for the Lodi portion of its load, with a corresponding reduction in the pool charges allocated back to LEU.
None of these four effects appears on a utility bill. None is easy to quantify without direct access to NCPA's internal settlement allocations. All of them are real, and over a multi-year horizon they accumulate into something economically substantial — likely on the same order of magnitude as the visible wheeling savings, though distributed across years and somewhat hidden in pool accounting.
What NSJTP unlocks
Beyond the immediate billing consequences and the structural settlement improvements lies a third category of effects: things that become possible after 2029 that are difficult or uneconomical today.
The most immediate is incremental capacity for multiple dimensions of growth. LEU Director Jeff Berkheimer told columnist Steve Mann of the Lodi News-Sentinel in September 2024 that the utility's load is approaching capacity — that anticipated growth within existing city limits has been factored in, but a large new annexation would be a challenge to supply on the 60 kV system as it stands today. After Guild Substation energizes, a 230 kV-connected LEU has headroom across multiple categories: residential development on the city's growth edges, electrification of existing residential and commercial customers (EV charging, heat pumps, expanded HVAC under hotter summers), expansion of the wine-industry and agricultural-processing customer base that historically anchors Lodi's commercial load, and high-density commercial loads if and when the City Council chooses to pursue them — including the data center development concepts that have surfaced in recent briefings, but not limited to those. A 60 kV-bottlenecked LEU has no meaningful headroom for any of these categories. The post-2029 question for Lodi is not whether there will be growth headroom, but which categories of growth the city chooses to prioritize for that headroom — a strategic decision rather than a technical one.
The second is battery storage colocation. The vacant land around White Slough — existing 230 kV interconnection, NCPA control of the site infrastructure, low community opposition compared to greenfield substations — is well suited to utility-scale storage. NCPA has not publicly announced storage development at the LEC switchyard, but the topology will make such a project meaningfully easier than it would be at most alternative sites in the region. Storage co-located with a fast-start gas plant and with LEU's bulk delivery point becomes a particularly versatile asset: capable of arbitraging wholesale prices, providing local voltage support, and serving as a contingency reserve for Lodi load.
The third is renewable PPA flexibility. When NCPA evaluates new utility-scale solar or wind power purchase agreements for member load allocations, the cost of delivering that energy to each member matters. Today, anything served to LEU has to navigate the 60 kV constraint. Post-NSJTP, NCPA's procurement options for Lodi-allocated renewables widen, because the deliverability constraint that has applied to Lodi for a decade simply goes away.
The fourth is no longer speculative: hydrogen at LEC. The Lodi Energy Center has already been upgraded to operate on a hydrogen-natural gas blend of up to 45 percent hydrogen, and the Lodi Energy Center Hydrogen Project — a partnership among the City of Lodi, NCPA, PG&E, and other entities under the federal Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) program — is moving forward as part of California's broader hydrogen hub effort. The project would produce hydrogen on-site at White Slough using excess renewable energy and treated wastewater from the city's Water Pollution Control Facility, blending that hydrogen back into LEC's fuel supply during periods of high California electricity demand. NCPA's retiring General Manager Randy Howard, recognized in a Lodi City Council proclamation in March 2026, was specifically credited with positioning LEC for the hydrogen transition. A future hydrogen-fired LEC with a robust 230 kV connection to LEU's Guild Substation represents something materially different from the gas-only plant of 2012: a low-carbon flexible peaking resource physically integrated with its largest geographically-adjacent customer.
The fifth is more open-ended: whether Lodi could grow its share of generation at White Slough. The 230 kV switchyard already accommodates LEC and the adjacent NCPA CT #2, with technical room on the site for additional generation or storage. The recent Siemens FX upgrade raised LEC's nameplate capacity from 296 to roughly 311 MW, and that increment flows pro-rata to existing participants, lifting Lodi's allocation from approximately 28 to 30 MW. Any larger expansion — a second LEC unit, a major storage adder colocated on the site, or eventual conversion to fully hydrogen-capable equipment — would be structured as a new NCPA project with its own participation schedule, set at financing rather than inherited from the original 2010 LEC project agreement. Lodi's structural position in any such negotiation is unusually favorable: the city owns the land, hosts the existing plant, will own Guild Substation as the local delivery point, and has growing load that could absorb a larger entitlement. Whether Lodi pursues that path, and at what cost, is a future City Council and LEU decision rather than a feature of NSJTP itself. But NSJTP makes the question more tractable than it would otherwise be, because deliverable additional capacity at White Slough — capacity that could go to Lodi's own load — now has a direct path home.
The reframed story
The conventional way to describe the Northern San Joaquin 230 kV Transmission Project is as a $137 million PG&E reliability project that will save Lodi ratepayers $8 million a year in transmission charges. That description is accurate. It is also the smallest version of the story.
The larger story is about the maturation of a joint-action model that has been waiting on transmission to catch up with its operational logic. For fourteen years, NCPA's biggest investment in Lodi has been physically next to NCPA's biggest load served in Lodi but electrically distant from it — close enough to walk to in two hours, far enough that the electrons take a half-hour detour through PG&E's constrained 60 kV system to get there. The visible wheeling-charge elimination is the billing-line consequence. The deliverability, congestion, fast-ramping, and resource-siting consequences are structural, larger in aggregate, and harder to see.
From an NCPA strategic-planning perspective, post-2029 Lodi looks meaningfully different from pre-2029 Lodi. The Lodi of today is a constrained 60 kV pocket served at arms-length, with a generation asset across town that exists in a parallel transmission universe. The Lodi of December 2029 is a fully integrated 230 kV node with co-located generation, a credible foundation for storage, an active hydrogen pathway, and the transmission headroom to support multiple dimensions of growth — from residential and commercial expansion through electrification load to new large industrial customers, if the City Council chooses to pursue them. This is what NCPA's joint-action model was originally designed to do when it was conceived in 1968.
The current sequence of events — CPUC permitting, vineyard land negotiations, route disputes, the procedural slog from EIR certification to construction notice-to-proceed — is the visible part of getting there. The harder part of getting there happened in the late 2000s, when CAISO planners first looked at the Lockeford-Lodi 60 kV system and said: this isn't going to work for the next twenty years. The conversation between that analysis and a physical 230 kV connection at Guild Substation has taken roughly two decades. December 2029, if it holds, will be when the conversation finally produces a result on the ground.
LodiEye is the investigative research arm of Lodi411.com, a citizen-run civic data and transparency platform serving Lodi, California and San Joaquin County. LodiEye is not a traditional news outlet. It does not employ professional journalists or reporters, and the people behind it do not hold journalism degrees or have professional newsroom experience. LodiEye is best understood as civic research and analysis — not peer journalism — and is not a substitute for the local and regional news organizations that do this work professionally. For traditional reporting on Lodi, San Joaquin County, and the broader region, readers are encouraged to consult the Lodi News-Sentinel, Stocktonia, The Sacramento Bee, CalMatters, and other established news outlets staffed by credentialed journalists.
This LodiEye investigative report was produced using artificial intelligence tools under the direction and review of the founder. Lodi411 uses multiple AI platforms in its research and publication workflow, including Anthropic's Claude (primarily Opus and Sonnet models) and Perplexity AI across a variety of large language models offered by each. These tools were used in the following capacities:
Source Discovery: Perplexity AI was used for initial source discovery and real-time retrieval of regulatory filings, including CPUC Application A.23-09-001 and the related Final Environmental Impact Report, the CAISO Tariff sections governing transmission access charges, NCPA's published portfolio and project descriptions, Fitch Ratings' analyses of NCPA's Lodi Energy Center revenue bonds, the City of Lodi Annual Comprehensive Financial Report for the fiscal year ended June 30, 2024, the Lodi News-Sentinel archive covering the plant's 2012 commissioning, and contemporaneous reporting on the Lodi Energy Center Hydrogen Project. Claude was used for deeper analysis of identified sources.
Credibility Validation: Participant capacity percentages were cross-referenced between Fitch Ratings disclosures, NCPA's public descriptions of the project, and contemporaneous news coverage of the plant's commissioning. The Lodi 30 MW figure stated in 2012 by the plant's general manager was reconciled to Fitch's 9.5% project share against current capacity. Tariff mechanics for the Low Voltage Wheeling Access Charge were validated against CAISO Tariff Section 26. Multiple AI models reviewed key claims independently.
Analysis and Synthesis: Claude Opus and Sonnet assisted in connecting the engineering specifics of the Northern San Joaquin 230 kV Transmission Project to NCPA's joint-action operating model, the CAISO Metered Subsystem settlement architecture, and the project's downstream implications for Resource Adequacy deliverability, congestion exposure, and post-2029 capacity for growth. The analytical framing centers on the structural reconnection between NCPA's largest local investment and NCPA's largest local load.
Presentation: Claude assisted with structuring the narrative arc, drafting prose, and specifying the two Kendo UI data visualizations (NCPA portfolio composition; LEC participant capacity shares) and one inline SVG topology diagram. Visualizations are simplified for general readers and are not engineering-grade single-line representations.
Final Review: Multiple AI models reviewed the completed draft for factual consistency, source attribution accuracy, and logical coherence. Multi-tool cross-checking serves as the primary error-reduction mechanism. All editorial judgments and publication decisions are made by the founder.
Lodi411/LodiEye believes transparency about AI use serves both readers and the broader information ecosystem. Readers who spot errors are encouraged to write editor@lodi411.com so corrections can be made.
References
- California Public Utilities Commission. Application A.23-09-001 — Northern San Joaquin 230 kV Transmission Project. CPUC Energy Division CEQA project page.
- California Public Utilities Commission. Final Environmental Impact Report for the Northern San Joaquin 230 kV Transmission Project. 2025.
- California Independent System Operator. CAISO Tariff Section 26 — Transmission Rates and Charges.
- City of Lodi. Annual Comprehensive Financial Report for the fiscal year ended June 30, 2024. lodi.gov/ACFR
- Northern California Power Agency. Generation portfolio and project descriptions. ncpa.com/about/generation/lodi-energy-center
- Northern California Power Agency. Bond disclosures filed on the MSRB Electronic Municipal Market Access system. ncpa.com/financials/bonds/lodi-energy-center
- Fitch Ratings. Affirms Northern California Power Agency's Various Project Revenue Bonds; Outlook Stable. 2016.
- California Energy Commission. Lodi Energy Center docket 08-AFC-10 (including 2025 Petition to Install Siemens FX Turbine Upgrade). energy.ca.gov
- Lodi News-Sentinel. "Lodi Energy Center will generate enough power for almost 300,000 homes." June 2012.
- Lodi News-Sentinel. "With temperatures soaring this summer, so are Lodi utility bills." September 2024.
- City of Lodi. Lodi Energy Center Hydrogen Project announcement. lodi.gov/CivicAlerts
- POWER Magazine. "TOP PLANTS: Lodi Energy Center, Lodi, California." September 2012.
- Lodi411. "Lodi City Council Meeting — March 4, 2026." Proclamation honoring retiring NCPA General Manager Randy Howard. lodi411.com