Tag Archives: California

“Fixed costs” do not mean “fixed charges”

Leave a reply

The California Public Utilities Commission has issued a proposed decision that calls for a monthly fixed charge of $24 for most customers. There is no basis in economic principles that calls for collecting “fixed costs” (too often misidentified) in a fixed charge. This so-called principle gets confused with the second-best solution for regulated monopoly pricing where the monopoly has declining marginal costs that are below average costs which has a two part tariff of a lump sum payment and variable prices at marginal costs. (And Ramsey pricing, which California uses a derivative of that in equal percent marginal cost (EPMC) allocation, also is a second-best efficient pricing method that relies solely on volumetric units.) The evidence for a natural monopoly is that average costs are falling over time as sales expand.

However, as shown by the chart above for PG&E’s distribution and transmission (and SCE’s looks similar), average costs as represented in retail rates are rising. This means that marginal costs must be above average costs. (If this isn’t true then a fully detailed explanation is required—none has been presented so far.) The conditions for regulated monopoly pricing with a lump sum or fixed charge component do not exist in California.

Using the logic that fixed costs should be collected through fixed charges, then the marketplace would be rife with all sorts of entry, access and connection fees at grocery stores, nail salons and other retail outlets as well as restaurants, car dealers, etc. to cover the costs of ownership and leases, operational overhead and other invariant costs. Simply put that’s not the case. All of those producers and providers price on a per unit basis because that’s how a competitive market works. In those markets, customers have the ability to choose and move among sellers, so the seller is forced to recover costs on a single unit price. You might respond, well, cell providers have monthly fixed charges. But that’s not true—those are monthly connection fees that represent the marginal cost of interconnecting to a network. And customers have the option of switching (and many do) to a provider with a lower monthly fee. The unit of consumption is interconnection, which is a longer period than the single momentary instance that economists love because they can use calculus to derive it.

Utility regulation is supposed to mimic the outcome of competitive markets, including pricing patterns. That means that fixed cost recovery through a fixed charge must be limited to a customer-dedicated facility which cannot be used by another customer. That would be the service connection, which has a monthly investment recovery cost of about $10 to $15/month. Everything else must be priced on a volumetric basis as would be in a competitive market. (And the rise of DERs is now introducing true competition into this marketplace.)

The problem is that we’re missing the other key aspect of competitive markets—that investors risk losing their investments due to poor management decisions. Virtually all of the excess stranded costs for California IOUs are due poor management, not “state mandates.” You can look at the differences between in-state IOU and muni rates to see the evidence. (And that an IOU has been convicted of killing nearly 100 people due to malfeasance further supports that conclusion.)

There are alternative solutions to California’s current dilemma but utility shareholders must accept their portion of the financial burden. Right now they are shielded completely as evidenced by record profits and rising share prices.

Opinion: What’s wrong with basing electricity fees on household incomes

7 Replies

I coauthored this article in the Los Angeles Daily News with Ahmad Faruqui and Andy Van Horn. We critique the proposed income-graduated fixed charge (IGFC) being considered at the California Public Utilities Commission.

Retail electricity rate reform will not solve California’s problems

1 Reply

Meredith Fowlie wrote this blog on the proposal to drastically increase California utilities’ residential fixed charges at the Energy Institute at Haas blog. I posted this comment (with some additions and edits) in response.

First, infrastructure costs are responsive to changes in both demand and added generation. It’s just that those costs won’t change for a customer tomorrow–it will take a decade. Given how fast transmission retail rates have risen and have none of the added fixed costs listed here, the marginal cost must be substantially above the current average retail rates of 4 to 8 cents/kWh.

Further, if a customer is being charged a fixed cost for capacity that is being shared with other customers, e.g., distribution and transmission wires, they should be able to sell that capacity to other customers on a periodic basis. While many economists love auctions, the mechanism with the lowest ancillary transaction costs is a dealer market akin a grocery store which buys stocks of goods and then resells. (The New York Stock Exchange is a type of dealer market.) The most likely unit of sale would be in cents per kWh which is the same as today. In this case, the utility would be the dealer, just as today. So we are already in the same situation.

Airlines are another equally capital intensive industry. Yet no one pays a significant fixed charge (there are some membership clubs) and then just a small incremental charge for fuel and cocktails. Fares are based on a representative long run marginal cost of acquiring and maintaining the fleet. Airlines maintain a network just as utilities. Economies of scale matter in building an airline. The only difference is that utilities are able to monopolistically capture their customers and then appeal to state-sponsored regulators to impose prices.

Why are California’s utility rates 30 to 50% or more above the current direct costs of serving customers? The IOUs, and PG&E in particular, over procured renewables in the 2010-2012 period at exorbitant prices (averaging $120/MWH) in part in an attempt to block entry of CCAs. That squandered the opportunity to gain the economics benefits from learning by doing that led to the rapid decline in solar and wind prices over the next decade. In addition, PG&E refused to sell a part of its renewable PPAs to the new CCAs as they started up in the 2014-2017 period. On top of that, PG&E ratepayers paid an additional 50% on an already expensive Diablo Canyon due to the terms of the 1996 Settlement Agreement. (I made the calculations during that case for a client.) And on the T&D side, I pointed out beginning in 2010 that the utilities were overforecasting load growth and their recorded data showed stagnant loads. The peak load from 2006 was the record until 2022 and energy loads have remained largely constant, even declining over the period. The utilities finally started listening the last couple of years but all of that unneeded capital is baked into rates. All of these factors point not to the state or even the CPUC (except as an inept monitor) as being at fault, but rather to the utilities’ mismanagement.

Using Southern California Edison’s (SCE) own numbers, we can illustrate the point. SCE’s total bundled marginal costs in its rate filing are 10.50 cents per kWh for the system and 13.64 cents per kWh for residential customers. In comparison, SCE’s average system rate is 17.62 cents per kWh or 68% higher than the bundled marginal cost, and the average residential rate of 22.44 cents per kWh is 65% higher. From SCE’s workpapers, these cost increases come primarily from four sources.

  1. First, about 10% goes towards various public purpose programs that fund a variety of state-initiated policies such as energy efficiency and research. Much of this should be largely funded out of the state’s General Fund as income distribution through the CARE rate instead. And remember that low income customers are already receiving a 35% discount on rates.
  2. Next, another 10% comes roughly from costs created two decades ago in the wake of the restructuring debacle. The state has now decreed that this revenue stream will instead be used to pay for the damages that utilities have caused with wildfires. Importantly, note that wildfire costs of any kind have not actually reached rates yet. In addition, there are several solutions much less costly than the undergrounding proposed by PG&E and SDG&E, including remote rural microgrids.
  3. Approximately 15% is from higher distribution costs, some of which have been created by over-forecasting load growth over the last 15 years; loads have remained stagnant since 2006.
  4. And finally, around 33% is excessive generation costs caused by paying too much for purchased power agreements signed a decade ago.

An issue raised as rooftop solar spreads farther is the claim that rooftop solar customers are not paying their fair share and instead are imposing costs on other customers, who on average have lower incomes than those with rooftop solar. Yet the math behind the true rate burden for other customers is quite straightforward—if 10% of the customers are paying essentially zero (which they are actually not), the costs for the remaining 90% of the customers cannot go up more than 11% [100%/(100%-10%) = 11% ]. If low-income customers pay only 70% of this—the 11%– then their bills might go up about 8%–hardly a “substantial burden.” (70% x 11% = 7.7%)

As for aligning incentives for electrification, we proposed a more direct alternative on behalf of the Local Government Sustainable Energy Coalition where those who replace a gas appliance or furnace with an electric receive an allowance (much like the all-electric baseline) priced at marginal cost while the remainder is priced at the higher fully-loaded rate. That would reduce the incentive to exit the grid when electrifying while still rewarding those who made past energy efficiency and load reduction investments.

The solution to high rates cannot come from simple rate design; as Old Surfer Dude points out, wealthy customers are just going to exit the grid and self provide. Rate design is just rearranging the deck chairs. The CPUC tried the same thing in the late 1990s with telcom on the assumption that customers would stay put. Instead customers migrated to cell phones and dropped their land lines. The real solution is going to require some good old fashion capitalism with shareholders and associated stakeholders absorbing the costs of their mistakes and greed.

In the LA Times – looking for alternative solutions to storm outages

1 Reply

I was interviewed by a Los Angeles Times reporter about the recent power outages in Northern California as result of the wave of storms. Our power went out for 48 hours New Year’s Eve and again for 12 hours the next weekend:

After three days without power during this latest storm series, Davis resident Richard McCann said he’s seriously considering implementing his own microgrid so he doesn’t have to rely on PG&E.

“I’ve been thinking about it,” he said. McCann, whose work focuses on power sector analysis, said his home lost power for about 48 hours beginning New Year’s Eve, then lost it again after Saturday for about 12 hours.

While the storms were severe across the state, McCann said Davis did not see unprecedented winds or flooding, adding to his concerns about the grid’s reliability.

He said he would like to see California’s utilities “distributing the system, so people can be more independent.”

“I think that’s probably a better solution rather than trying to build up stronger and stronger walls around a centralized grid,” McCann said.

Several others were quoted in the article offering microgrids as a solution to the ongoing challenge.

Widespread outages occurred in Woodland and Stockton despite winds not being exceptionally strong beyond recent experience. Given the widespread outages two years ago and the three “blue sky” multi hour outages we had in 2022 (and none during the September heat storm when 5,000 Davis customers lost power), I’m doubtful that PG&E is ready for what’s coming with climate change.

PG&E instead is proposing to invest up to $40 billion in the next eight years to protect service reliability for 4% of their customers via undergrounding wires in the foothills which will raise our rates up to 70% by 2030! There’s an alternative cost effective solution that would be 80% to 95% less sitting before the Public Utilities Commission but unlikely to be approved. There’s another opportunity to head off PG&E and send some of that money towards fixing our local grid coming up this summer under a new state law.

While winds have been strong, they have not been at the 99%+ range of experience that should lead to multiple catastrophic outcomes in short order. And having two major events within a week, plus the outage in December 2020 shows that these are not statistically unusual. We experienced similar fierce winds without such extended outages. Prior to 2020, Davis only experienced two extended outages in the previous two decades in 1998 and 2007. Clearly the lack of maintenance on an aging system has caught up with PG&E. PG&E should reimagine its rural undergrounding program to mitigate wildfire risk to use microgrids instead. That will free up most of the billons it plans to spend on less than 4% of its customer base to instead harden its urban grid.

Per Capita: Climate needs more than just good will

Leave a reply

I wrote this guest column in the Davis Enterprise about the City’s Climate Action and Adaptation Plan. (Thank you John Mott-Smith for extending the privilege.)

Dear Readers, the guest column below was written by Richard McCann, a Davis resident and expert on energy and climate action plans.

————

The city of Davis is considering its first update of its Climate Action and Adaptation Plan since 2010 with a 2020-2040 Plan. The city plans to update the CAAP every couple of years to reflect changing conditions, technologies, financing options, laws and regulations.

The plan does not and cannot achieve a total reduction in greenhouse gas emissions simply because we do not control all of the emission sources — almost three-quarters of our emissions are from vehicles that are largely regulated by state and federal laws. But it does lay out a means to putting a serious dent in the overall amount. 

The CAAP offers a promising future and accepts that we have to protect ourselves as the climate worsens. Among the many benefits we can look forward to are avoiding volatile gas prices while driving cleaner, quieter cars; faster and more controllable cooking while eliminating toxic indoor air; and air conditioning and heating without having to make two investments while paying less.

To better adapt, we’ll have a greener landscape, filtered air for rental homes, and community shelter hubs powered by microgrids to ride out more frequent extreme weather.

We have already seen that adding solar panels raises the value of a house by as much as $4,000 per installed kilowatt (so a 5 kilowatt system adds $20,000). We can expect similar increases in home values with these new technologies due to the future savings, safety and convenience. 

Several state and federal laws and rules foretell what is coming. By 2045 California aims to be at zero net GHG emissions. That will require retiring all of the residential and commercial gas distribution lines. PG&E has already started a program to phase out its lines. A change in state rules will remove from the market several large natural gas appliances such as furnaces by 2030.

In addition, PG&E will no longer offer subsidies to developers to install gas lines to new homes starting next year. The U.S. Environmental Protection Agency appears poised to push further the use of electric appliances in areas with poor air quality such the Sacramento Valley. (Renewable gas and hydrogen will be too expensive and there won’t be enough to go around.)

Without sales to new customers or for replaced furnaces, the cost of maintaining the gas system will rise substantially so switching to electricity for cooking and water heating will save even more money. The CAAP anticipates this transition by having residents begin switching earlier. 

In addition, the recently enacted federal Inflation Reduction Act offers between $400 and $800 billion into funding these types of changes. The California Energy Commission’s budget for this year went from $1 billion to $10 billion to finance these transitions. The CAAP lays out a process for acquiring these financial sources for Davis and its residents. 

That said, some have objected to the CAAP as being too draconian and infringing on personal choices. The fact is that we are now in the midst of a climate emergency — the City Council endorsed this concern with a declaration in 2019. We’re already behind schedule to head off the worst of the threatening impacts. 

We won’t be able to rely solely on voluntary actions to achieve the reductions we need. That the CAAP has to include these actions proves that people have not been acting on their own despite a decade of cajoling since the last CAAP. While we’ve been successful at encouraging voluntary compliance with easy tasks like recycling, we’ve used mandatory permitting requirements to gain compliance with various building standards including energy efficiency measures. (These are usually enforced at point-of-sale of a house.)

We have a choice of mandatory ordinances, incentives through taxes or fees, and subsidies from grants and funds — voluntary just won’t deliver what’s needed. We might be able to financially help those least able to afford changing stoves, heaters or cars, but those funds will be limited. The ability to raise taxes or fees is restricted due to various provisions in the state’s constitution. So we are left with mandatory measures, applied at the most opportune moments. 

Switching to electricity for cooking and water heating may involve some costs, some or most of which will be offset by lower energy costs (especially as gas rates go up.) If you have an air conditioner, you’re likely already set up for a heat pump to replace your furnace — it’s a simple swap. Even so, you can avoid some costs by using a 120-volt induction cooktop instead of 240 volts, and installing a circuit-sharing plug or breaker for large loads to avoid panel upgrades. 

The CAAP will be fleshed out and evolve for at least the next decade. Change is coming and will be inevitable given the dire situation. But this change gives us opportunities to clean our environment and make our city more livable.  

The fundamental truth of marginal and average costs

4 Replies

Opponents of increased distributed energy resources who advocate for centralized power distribution insist that marginal costs are substantially below retail rates–as little as 6 cents per kilowatt-hour. Yet average costs generally continue to rise. For example, a claim has been repeatedly asserted that the marginal cost of transmission in California is less than a penny a kilowatt-hour. Yet PG&E’s retail transmission rate component went from 1.469 cents per kWh in 2013 to 4.787 cents in 2022. (SDG&E’s transmission rate is now 7.248 cents!) By definition, the marginal cost must be higher than 4.8 cents (and likely much higher) to increase that much.

Average costs equals the sum of marginal costs. Or inversely, marginal cost equals the incremental change in average costs when adding a unit of demand or supply. The two concepts are interlinked so that one must speak of one when speaking of the other.

The chart at the top of this post shows the relationship of marginal and average costs. Most importantly, it is not mathematically possible to have rising average costs when marginal costs are below average costs. So any assertion that transmission marginal costs are less than the average costs of transmission given that average costs are rising must be mathematically false.

David Mitchell in the LA Times: As drought drives prices higher, millions of Californians struggle to pay for water

Leave a reply

M.Cubed Partner David Mitchell was interviewed for an article on rising residential water rates in California in this October 24 article:

Across the state, water utility prices are escalating faster than other “big ticket” items such as college tuition or medical costs, according to David Mitchell, an economist specializing in water.

“Cost containment is going to become an important issue for the sector in the coming years” as climate change worsens drought and water scarcity, he said.

The price of water on the Nasdaq Veles California Water Index, which is used primarily for agriculture, hit $1,028.86 for an acre-foot on Oct. 20 — a roughly 40% increase since the start of the year. An acre-foot of water, or approximately 326,000 gallons, is enough to supply three Southern California households for a year.

Mitchell said there are short- and long-term factors contributing to rising water costs.

Long-term factors include the replacement of aging infrastructure, new treatment standards, and investments in insurance, projects and storage as hedges against drought.

In the short term, however, drought restrictions play a significant role. When water use drops, urban water utilities — which mostly have fixed costs — earn less revenue. They adjust their rates to recover that revenue, either during or after the drought.

“So it’s not right now a pretty picture,” Mitchell said.

David Mitchell’s practice areas include benefit-cost analysis, regional economic impact assessment, utility rate setting and financial planning, and natural resource valuation. Mr. Mitchell has in-depth knowledge of the water supply, water quality and environmental management challenges confronting natural resource management agencies.

The real lessons from California’s 2000-01 electricity crisis and what they mean for today’s markets

1 Reply

The recent reliability crises for the electricity markets in California and Texas ask us to reconsider the supposed lessons from the most significant extended market crisis to date– the 2000-01 California electricity crisis. I wrote a paper two decades ago, The Perfect Mess, that described the circumstances leading up to the event. There have been two other common threads about supposed lessons, but I do not accept either as being true solutions and are instead really about risk sharing once this type of crisis ensues rather than being useful for preventing similar market misfunctions. Instead, the real lesson is that load serving entities (LSEs) must be able to sign long-term agreements that are unaffected and unfettered directly or indirectly by variations in daily and hourly markets so as to eliminate incentives to manipulate those markets.

The first and most popular explanation among many economists is that consumers did not see the swings in the wholesale generation prices in the California Power Exchange (PX) and California Independent System Operator (CAISO) markets. In this rationale, if consumers had seen the large increases in costs, as much as 10-fold over the pre-crisis average, they would have reduced their usage enough to limit the gains from manipulating prices. Consumers should have shouldered the risks in the markets in this view and their cumulative creditworthiness could have ridden out the extended event.

This view is not valid for several reasons. The first and most important is that the compensation to utilities for stranded assets investment was predicated on calculating the difference between a fixed retail rate and the utilities cost of service for transmission and distribution plus the wholesale cost of power in the PX and CAISO markets. Until May 2000, that difference was always positive and the utilities were well on the way to collecting their Competition Transition Charge (CTC) in full before the end of the transition period March 31, 2002. The deal was if the utilities were going to collect their stranded investments, then consumers rates would be protected for that period. The risk of stranded asset recovery was entirely the utilities’ and both the California Public Utilities Commission in its string of decisions and the State Legislature in Assembly Bill 1890 were very clear about this assignment.

The utilities had chosen to support this approach linking asset value to ongoing short term market valuation over an upfront separation payment proposed by Commissioner Jesse Knight. The upfront payment would have enabled linking power cost variations to retail rates at the outset, but the utilities would have to accept the risk of uncertain forecasts about true market values. Instead, the utilities wanted to transfer the valuation risk to ratepayers, and in return ratepayers capped their risk at the current retail rates as of 1996. Retail customers were to be protected from undue wholesale market risk and the utilities took on that responsibility. The utilities walked into this deal willingly and as fully informed as any party.

As the transition period progressed, the utilities transferred their collected CTC revenues to their respective holding companies to be disbursed to shareholders instead of prudently them as reserves until the end of the transition period. When the crisis erupted, the utilities quickly drained what cash they had left and had to go to the credit markets. In fact, if they had retained the CTC cash, they would not have had to go the credit markets until January 2001 based on the accounts that I was tracking at the time and PG&E would not have had a basis for declaring bankruptcy.

The CTC left the market wide open to manipulation and it is unlikely that any simple changes in the PX or CAISO markets could have prevented this. I conducted an analysis for the CPUC in May 2000 as part of its review of Pacific Gas & Electric’s proposed divestiture of its hydro system based on a method developed by Catherine Wolfram in 1997. The finding was that a firm owning as little as 1,500 MW (which included most merchant generators at the time) could profitably gain from price manipulation for at least 2,700 hours in a year. The only market-based solution was for LSEs including the utilities to sign longer-term power purchase agreements (PPAs) for a significant portion (but not 100%) of the generators’ portfolios. (Jim Sweeney briefly alludes to this solution before launching to his preferred linkage of retail rates and generation costs.)

Unfortunately, State Senator Steve Peace introduced a budget trailer bill in June 2000 (as Public Utilities Code Section 355.1, since repealed) that forced the utilities to sign PPAs only through the PX which the utilities viewed as too limited and no PPAs were consummated. The utilities remained fully exposed until the California Department of Water Resources took over procurement in January 2001.

The second problem was a combination of unavailable technology and billing systems. Customers did not yet have smart meters and paper bills could lag as much as two months after initial usage. There was no real way for customers to respond in near real time to high generation market prices (even assuming that they would have been paying attention to such an obscure market). And as we saw in the Texas during Storm Uri in 2021, the only available consumer response for too many was to freeze to death.

This proposed solution is really about shifting risk from utility shareholders to ratepayers, not a realistic market solution. But as discussed above, at the core of the restructuring deal was a sharing of risk between customers and shareholders–a deal that shareholders failed to keep when they transferred all of the cash out of their utility subsidiaries. If ratepayers are going to take on the entire risk (as keeps coming up) then either authorized return should be set at the corporate bond debt rate or the utilities should just be publicly owned.

The second explanation of why the market imploded was that the decentralization created a lack of coordination in providing enough resources. In this view, the CDWR rescue in 2001 righted the ship, but the exodus of the community choice aggregators (CCAs) again threatens system integrity again. The preferred solution for the CPUC is now to reconcentrate power procurement and management with the IOUs, thus killing the remnants of restructuring and markets.

The problem is that the current construct of the PCIA exit fee similarly leaves the market open to potential manipulation. And we’ve seen how virtually unfettered procurement between 2001 and the emergence of the CCAs resulted in substantial excess costs.

The real lessons from the California energy crisis are two fold:

  • Any stranded asset recovery must be done as a single or fixed payment based on the market value of the assets at the moment of market formation. Any other method leaves market participants open to price manipulation. This lesson should be applied in the case of the exit fees paid by CCAs and customers using distributed energy resources. It is the only way to fairly allocate risks between customers and shareholders.
  • LSEs must be able unencumbered in signing longer term PPAs, but they also should be limited ahead of time in the ability to recover stranded costs so that they have significant incentives to prudently procure resources. California’s utilities still lack this incentive.

That California owns its water doesn’t mean that the state can just take it back without paying for it

2 Replies

The researchers at the UC Davis Center for Watershed Sciences wrote an insightful blog on “Considerations for Developing An Environmental Water Right in California.” However one passage jumped out at me that has troubling economic implications:

The potential for abuse is particularly troubling when the State is using public funds to buy water, which technically belongs to the people of the state and which the State can already regulate to achieve the same aims.

It’s not helpful to refer to the fiction that the somehow the state can award water rights, on which entities make economic investments based on private uses, and then turn around and try to claim that the state can just take those rights back without any compensation. That’s a foolish perspective that will lead mispricing and misallocation of water use. It is reasonable to assert that the state can claim a right of first refusal on transactions or even that a rights holder can’t withhold sale of a water right to the state, but in either case, the rights holder does receive compensation. The state’s right can easily be interpreted as that of a landlord who has a long term lease agreement with a tenant, and the tenancy agreement can be terminated with compensation to that tenant.

Close Diablo Canyon? More distributed solar instead

4 Replies

More calls for keeping Diablo Canyon have coming out in the last month, along with a proposal to match the project with a desalination project that would deliver water to somewhere. (And there has been pushback from opponents.) There are better solutions, as I have written about previously. Unfortunately, those who are now raising this issue missed the details and nuances of the debate in 2016 when the decision was made, and they are not well informed about Diablo’s situation.

One important fact is that it is not clear whether continued operation of Diablo is safe. Unit No. 1 has one of the most embrittled containment vessels in the U.S. that is at risk during a sudden shutdown event.

Another is that the decision would require overriding a State Water Resources Control Board decision that required ending the use of once-through cooling with ocean water. That cost was what led to the closure decision, which was 10 cents per kilowatt-hour at current operational levels and in excess of 12 cents in more likely operations.

So what could the state do fairly quickly for 12 cents per kWh instead? Install distributed energy resources focused on commercial and community-scale solar. These projects cost between 6 and 9 cents per kWh and avoid transmission costs of about 4 cents per kWh. They also can be paired with electric vehicles to store electricity and fuel the replacement of gasoline cars. Microgrids can mitigate wildfire risk more cost effectively than undergrounding, so we can save another $40 billion there too. Most importantly they can be built in a matter of months, much more quickly than grid-scale projects.

As for the proposal to build a desalination plant, pairing one with Diablo would both be overkill and a logistical puzzle. The Carlsbad plant produces 56,000 acre-feet annually for San Diego County Water Agency. The Central Coast where Diablo is located has a State Water Project allocation of 45,000 acre-feet which is not even used fully now. That plant uses 35 MW or 1.6% of Diablo’s output. A plant built to use all of Diablo’s output could produce 3.5 million acre-feet, but the State Water Project would need to be significantly modified to move the water either back to the Central Valley or beyond Santa Barbara to Ventura. All of that adds up to a large cost on top of what is already a costly source of water of $2,500 to $2,800 per acre-foot.