Should Homeowners with PV Get Paid Retail or Wholesale Prices for their Excess Electricity?

I've been doing some research, trying to get my arms around the problem of the longterm sustainability of renewable energy in the Unites States. Here's one big challenge as I see it.

Many customers with PV pay retail prices for electricity they buy from their utility, and get retail prices when selling their extra energy to the utility. Seems fair until you consider that the utility has to pay for generation of electricity (at wholesale prices), distribution, public benefit charges, and other fixed costs. All these costs figure in the retail price. Wouldn't it be fairer and more sustainable for the utility to pay wholesale prices for the extra electricity they buy from their PV-owning (or renting) customers? After all, the customer is acting like a supplier of energy, not a retailer, since it doesn't have to pay the kinds of fixed costs mentioned above that the utility does have to pay.

Utilities say that they end up paying more for the customer-generated energy than they receive from the customer, even though the customer benefits from receiving energy from the grid when their PV panels aren't producing electricity.

Solar PV advocates say that the prices utilities charge represent too big of a profit margin to begin with (which is really a whole another question), and paying PV customers for their excess energy supports a growing solar industry that produces jobs and lots of other societal benefits, including environmental ones that don't usually get quantified in the buying and selling of electricity.

Utilities also say that, since their PV customers tend to be high-end customers, the money they loose on these customers ends up being made up for with higher rates to their low-end customers. 

Solar advocates (this one at least) also say that the utility rate structure for residential and commercial customers is very complicated and allows the utility to tweak the structure so that they make plenty of money to cover their costs and get a prophet. This could be done in a way that was fairer for everyone but still supported solar and other renewable energies.

If you want to get a much more nuanced look at the issue, I suggest you take a look at a report commissioned by the California Public Utilities Commission, which had a study done to explore the issue. (Confession: I read the executive summary and skimmed the rest).

Here is a link to the report:

I'm going to go out on a limb and say that, taking away the problem of whether the retail prices the utilities charge are fair, for the sake of the long term viability of solar, given that we will probably always need some kind of distribution system that needs to be maintained, as well as a variety of sources to meet our energy needs, and on behalf of a basic sense of fairness, I think that customers who sell excess electricity back to the utility, from any renewable source, should pay wholesale prices.

What do you think?

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Jim, I agree, but the problem is really a rate structure issue.  Since distribution is billed per KWH that is distributed, rather than a fixed charge, you absolutely have to change net metering laws to the wholesale rate.  People with PV need to pay for the availability of the grid, which they still use often at night or in wintertime.  On the other hand, if people paid a fixed fee per household for access to the grid, then you could allow net metering at the retail price since retail at this point represents cost plus profit for supply only.  The problem is that a fixed cost would probably mean that poor/elderly might pay significantly more for access than they do today, so the politics are problematic even if a fixed cost might actually be the most accurate/fair way to pay for fixed infrastructure running to peoples' homes.  As homes and businesses start to take advantage of distributed generation (wind, solar, etc.), this problem will become more severe and could put the ability of utilities to maintain infrastructure at risk.

There already is a fixed cost on most utilities built in. It's called the customer/meter charge.

I recommend this primer from the Solar Electric Power Association (SEPA):

Here's a quote from the primer on increasing customer-sited generation: "This transition will only be effective when utilities, the solar industry and customers collaborate to create a sustainable solar distributed generation marketplace."

The answer to "who benefits, who pays and what's a fair price" varies from region to region. California's rate structure is unique (and complicated), so what's fair in California may not apply to the rest of the country. 

If you really want to get into arcana, try to figure out and rationalize utility rates! It's a complicated process even if you TRY to keep it simple. (How much SHOULD you pay today for the plant that was built 20 years ago, financed with 30-year bonds?) And, quite frankly, it's in utilty execs' interests to make it as complex as possible -- the more complicated the system, the easier it is to game the system and charge unfair rates, cross-subsidize large customers with revenue from the little fish, etc.

But, with that said, you can make a very good case that residential PV customers should be paid retail rates. After all, the energy produced by a rooftop PV system is not going back to a substation to be re-distibuted to some other region halfway across the state. It's going into the local grid and being used by the lights in the store just down the block. The distribution cost is nominal, and it's almost all happening on grid that was paid for LONG ago. You don't need that fancy new 700 kV mega-transmission line to use distrbuted PV.

In A/C-dominant climates, local PV power should probably be paid retail plus a sizable bonus. That generation coincides with the peak load, which is the most expensive load of all to generate. Even in Wisconsin, the last marginal kWH produced at 3 PM in August costs around 10 times more to generate than the marginal kWh needed to satisfy the last kWh of demand at 2 AM in May. (The last time I looked at these numbers, four or six years ago...) It's sort of silly -- the very first use of general distribution electricity was for lighting, which ought to be low when the sun is brightest. Now, it's generally true that the brighter the daylight, the higher the electric consumption.  

Brian, utility rate structures are not all the same. In Wisconsin, many residential tariffs bill a fixed (per day) meter charge for distribution, not a per-kWh charge. It makes some sense -- you have to pay the same to maintain your existing grid, whether it's at 80% capacity or 5 percent. One utility here in Wisconsin actually got permission to do BOTH.

The upshot of fixed meter charges, though, is that the less you use, the higher the cost per unit. I am supplied by the utility that charges distribution on both levels; the result is that my relatively low usage ends up costing almost 20 cents/kWh. Which sort of encourages me to conserve even more -- as long as I don't think about the per-unit cost too deeply! But if I paid only a per-kWh distribution charge, I'd see the full savings from my conservation efforts.

Variable peak pricing for electric service is taking care of that afternoon peak charge vs. off peak. With the increased use of smartmeters, charging customers different rates for different times of day is be... Customers could be credited @ peak rates for peak power sold to the grid. The utility wins in the long haul by delaying building power plans/upgrading infrastructure.



Nice questions Jim!  

These questions of value always make me think people are distorting natural markets in an attempt to gain advantage for their special interest, creating friction and choke points that hold everyone back.  

The current utility structure is fairly perverse.  One problem is attempting to cover fixed costs through variable sales rather than fixed fees.  The lines and pipes and infrastructure must be maintained irrespective of volume, "free" or "service charge built in" simply doesn't apply costs where they occur, and this distorts things.  Some pay more for less, and some pay less for more.  That perversity is being corrected as decoupling makes it apparent that monthly service charges will have to grow.  

Ultimately I suspect we will have a market that values excess production based upon the shed costs.  Time of use will have significant impact here.  It's likely we'll see solar panel orientation change as this occurs:

I guess as long as the way we pay for and support the deployment of renewables seemingly keeps developing, it will be an open question for a while what is the best way to go. The CPUC is asking for comments on the report linked above in my post and there are no doubt opportunities across the country to influence how we regulate the interconnection of PV and other renewables with the traditional electricity grid, while we also make efforts to make the grid "smarter". Let's stay in the discussion. 

Thanks everyone for your comments, which reflect a lot of thought and care.

It is worth noting that the CPUC study cited is for "investor owned utilities"  not the California co-ops or municipals.  Investor owned utilities generally expect to make a profit and business decisions are based on long term investment goals.  The same can be said about the small residential customer that adds solarPV to their roof top.  I would therefore dispute the "fairness" of Jim's comment when he says: "on behalf of a basic sense of fairness, I think that customers who sell excess electricity back to the utility, from any renewable source, should pay wholesale prices."

Let's look at some of the basic issues and then at the CPUC report.

1) First a disclaimer - there are fifty states,  about 3500 entities that provide the service equivalent of electric utilties.  That means that there are a very diverse mixture of net-metering rules.  If you want reasonably coherent discussions you need to include information that includes the net-metering policy you operate under.  For example:

* some net-metering attempt to convert the solar production at the time of generation and record it as a money value.  APS in Arizona is trying to change to this and use an average wholesale price when the record the value generated - even if the market day ahead wholesale pricing is 100X.

* other states simply take the excess generated and add the kWh equivalent to running customer tab,  then in the eveings the load is subtracted from the running tab.  At the end of a monthly billing period a couple of things can happen -- one nothing - the tab keeps running for a year,  possibly the customer is paid out at the wholesale rate.  If the tab is kept running for a year - a variety of things can also happen.  In Washington State - any excess in the account is zeroed out.  No payout. Simply said it doesn't pay to over produce.  In other states the excess may be paid out at the wholesale or retail rate.

Not all net metering agreements are equal...

2) The roof top residential customer that installs solarPV is taking on risk.  They also have made a long term investment with an expectation of earning a payback.  The solarPV customers typically expect a useful life of 20 years.  The investment  was based on previously published net-metering agreements.  Changing the net-metering agreement to new wholesale prices during the 20 year period should be viewed as no different than changing the allowed capital expense recovery options for the utility.  Certainly rate payers in the San Diego area would appreciate it if CPUC were to declare that the cost recovery for the SONGS plants must be fully absorbed by the utility from their profits and not passed onto the present or future rate payers.

3) There have been lots of discussion about roof top solar not providing power during peak needs, HOWEVER if you read the WECC 2011 10 Year Regional Transmission Plan ( ) page 80 table 9. SolarPV  is available 60% of the time to meet the peak loads.  Wind on the other hand is only available 10% of the time.  The transmission losses average about 1%/100miles,  during those HOT summer hours California imports considerable amounts of power via transmission lines from Oregon, Washington and British Columbia.  Those transmission lines all are experience losses and the corridor would need additional capacity if California does not self produce electricity for the peak hours.

4) Roof top solar is closer to the residential loads than the remote hydro dams,  natural gas peaking generators or nuclear power plants.  Between the local substations and the larger central generation points are many switch yards, subtransmission lines, etc.  all with additional losses and capital cost to build more capacity.

In the CPUC study they try to address some of the costs by looking at the "avoided costs" required if solarPV was absent.  Those cost include, acquiring additional land,  building/enlarging substations, additional subtransmission lines,  transmission lines,  generating resources, and fuel.   If the generating requires water (natural gas, hydro, coal, nuclear) then you should be including cost of water or the impact of the use of the water also.  The CPUC study doesn't include the costs outside of the California area (from what I saw).  It does include an estimate for CO2 tax.  It does not include a common or public good...  In any case the price for solar would not drop to the wholesale rate!  It might perhaps drop slightly below the retail rate.

5) Now here is one real interesting point - the argument that PV customers tend to be the high end customers... what isn't real clear at first is that the customer base has rolled all residential customers into one big group.  Small condo users, small appartment users,  mega-mansions, the 1500 sqft house.. makes no difference. 

But the California net-metering agreement also includes the large box stores, farms that use pumps for the food we eat, they use the solarPV to offset the costs for the pumps and machinery.   It is easy (and perhaps fun) to assume that a price shift is going only happening between the mega-mansions to the very small residential customers -- and certainly some of the utilities would like to promote that belief.  But in some cases the price shift (when it happens) is also going to the producers and stores that we buy goods and services from.  It could be argued that they are also offering lower prices on their products because their cost of energy is also lower.  The arguments of course get quite complex.

6) from the CPUC study in Jim's link, page 47, table 12.   Look at the diagonal line, the installations above the line are producing more than they use over the year. There are a couple of REALLY big producers.  Small residential loads - but they are being paid out $ for their energy production.  Same net-metering customers under the Washington State net metering laws would see ZERO pay out for that surplus.      The point is the solution to the net metering problem in California may be as simple as restricting the payout on future systems to their consumption in the year, paying all customers at wholesale may be as unfair as the current method.

But remember those commercial box stores and farmers -- they are also benefiting from net-metering -- are we benefiting from their lower energy costs?

Realize there is more markup on electricity for commercial customers than residential. If a utility pays retail for the electricity at commercial rates it would cost a lot more than purchasing at residential rates. This would give commercial more incentive to build/install solar energy.

Combined with Variable Peak Pricing and solar could get a decent payback time, even if it's only to reduce the use on a commercial building. Solar may not make sense @ 15 cents per KWH, but it's a different game at 30 cents during peak hours (2-7pm for our area). VPP pricing is what is going to help solar get decent payback times, and it's just a matter of time before all utilities bill based on peak/off peak.

I disagree that it is only a matter of time before all utilities bills are based on peak/off peak.  

Time of Use billing is generally implemented in regions that utilities must buy power on the spot markets (merchant generators) or pay added price for the location marginal pricing (LMP).  LMP is in part designed to place a value on the transmission line congestion.  Local distributed generation (roof tops) has the ability to push spot market prices down and ease future transmission line congestion.

We'll see. The more a local utility can curb peak use the longer they can delay building a power plant and upgrading infrastructure. Back in the day of analog meter utilities had no easy way to charge different rates based on time of use. Things are different with smartmeters, it's no harder to bill TOU than the old flat rate pricing.

Our local utility experimented with TOU about eight years ago.  The back away from it because they didn't see consumption reduction as many people propose,  the billing processes become more complex, customer services become more complex... and the price of electricity in the NW was low enough that savings just didn't pan out.   In Hawaii or North East US it certainly would be different - but that is because of resource constraints.

Electric consumption in the NW (MT, ID, OR, WA) is flat or negative growth over the last ten or fifteen years.  That is still with an increase in population. But we've had VERY strong energy efficient / conservation programs (similar to California) and the result is that demand has been dropping.  Meanwhile we've added more generation from wind and solar.  The value of TOU is not their for our region.

In addition to the smartmeters the utilities also need the billing system upgrades and approvals from their regulators.  That is also very dependent on the region of the country.

FWIW,  utilities really would rather build power plants. Unless their rates have been decoupled from the volume sales - the reduction in sales actually hurts their bottom line a lot.  That is really what is behind the net-metering battles.  SolarPV and energy efficiency improvements both reduce the kWh sales.   If you carefully read the referenced CPUC report - the method they used to calculate the transfer of cost from a net-metering customer to a non-metering customer --- was to effectively calculate the total drop in energy by the net-metering customer, then using that drop by all net-metering customers to calculate how much fixed cost needed to be recovered from the non-solar customers.   Not just the energy exported to the grid.  A person that did a deep energy retrofit without solar would have seen a similar drop --- and as calculated by the CPUC they would have had their energy savings subsidized by their neighbors.  It is a flaw in their method of calculating and it has been pointed out to them by the DOE.  That was also pointed out to our state utility commission by DOE representative.



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