Two-part real-time pricing reflects the two-part pricing found in other business sectors.
Georgia Power Co., Duke Power Co., and their customers have reaped the benefits of two-part real-time pricing (RTP) for nearly 10 years. In the regulated electric industry, two-part RTP pricing operates under the premise that: (1) the most efficient and least expensive price to charge for a volatile commodity is a spot price based upon the commodity's spot market or, in the absence of a spot market price, the commodity's marginal cost (one can also argue that the market price is the utility's marginal cost);1 and (2) under most circumstances, revenues received from this spot price are insufficient to satisfy the overall revenue requirements of the utility's embedded/financial cost, such that a second pricing component, besides the spot price, is necessary. This second component is an agreed-to fixed load shape of hourly kilowatt-hour usage, often referred to as a customer baseline load shape (CBL) and priced at the utility's standard rate, which will then recover cost obligations beyond the spot price. The bill can be thought of as a fixed load shape at standard tariff prices, and changes from this load shape priced at spot prices.
One could also consider the fixed load shape subject to the spot price and a settlement at the end of the billing period based upon the difference in the actual spot price and the standard tariff. This difference settled at the end of the billing period is referred to as ex-post, meaning it's not determined until the end of the billing period. This settlement also can be referred to as an access charge/credit, and it ensures that the customer pays only the standard tariff for the CBL amount.
This access charge/credit ends up serving two purposes. First, it ensures that the utility recovers the allowed revenue on the customer's CBL. Second, it provides a form of price protection for the RTP customer on the amount of load under the CBL. The amount of the charge or credit depends on the differences between the actual RTP prices in the month and the standard tariff prices; relatively low RTP prices result in an access charge, while periods of high RTP prices that exceed standard tariff prices result in implicit credits to the customer.
This structure has been a perfectly acceptable and efficient means to price electricity, but a second structure for pricing electricity can now be introduced. Either structure is sound and efficacious. Each methodology has its advantages, and utilities should consider which method best serves their needs.
A utility could offer both methods.
The fact that the access charge/credit is calculated at the end of the billing period and involves maintaining a historical load shape appears to some parties to represent an unattractive complication to the consideration of two-part RTP. The goal of this paper is to reveal how a properly constructed ex-ante access charge can perform as efficiently as an ex-post access charge, thereby enabling electric utilities, as well as other industry utilities, to offer spot pricing without continually tracking an hourly quantity component for access charge settlement purposes. Thus, the new model solves a hang-up that many utilities have with the ultra successful two-part RTP pricing found in Georgia and North Carolina.
It should also be noted that the benefits of both ex-ante and ex-post access charge/credits are not limited to the regulated arena. A non-regulated seller easily could adapt these products to competitive markets.
An access charge is a mechanism for the selling party to recover those costs from the buying party that may not be covered in an hourly (or periodic) spot price. From the buyer's perspective, an access charge may offer price stability, thereby avoiding the volatility of the spot price market. From the seller's perspective, an access charge may offer financial stability by ensuring cost recovery. In theory, the access charge also could be negative- i.e., the access charge makes up for the difference between the spot price and the financial requirements, which could be negative in periods of high spot prices.
For instance, the selling utility may have financial revenue requirements including fixed cost coverage and risk insurance cost totaling up to 5 cents/kWh on average for a particular load shape (load shape being the quantity per hour requested by the buying party).
The expected average marginal cost to the seller for supplying the product for the expected load shape might be 3 cents/kWh. The difference of 2 cents/kWh is necessary to cover non-marginal cost to serve the expected load shape. This 2 cents/kWh can be expected to be covered by the seller through a fee of 5 cents/kWh. Or, the seller can charge an upfront access fee of 2 cents/kWh plus hourly spot prices that may have significant volatility with an expected average of 3 cents/kWh.2
Should the 2 cents/kWh be collected upfront by considering the forecasted expected spot price of 3 cents/kWh (ex-ante), or based upon and collected after the actual spot prices are determined at the end of the billing period (ex-post)? There are formidable and separate ramifications for both the seller and the buyer depending upon employing ex-ante or ex-post development of the access charge.
Many commodity industries, which offer their product on a spot market, also offer financial instruments to reduce risk in these spot markets. These instruments are financial contracts with agreed-to terms stating quantity, time period, and price. The actual quantity purchased on the spot market is not an issue because the financial contract specifies the quantity upon which the settlement will be made. The price of the settlement of this financial instrument is the difference between the agreed-to price and the actual spot price. There are also physical instruments that specify delivery of the physical commodity for a fixed quantity as part of the contract, but so long as the buyer can sell the physical back into that spot market if he doesn't want it, the net effects of the financial instrument and the physical instrument are similar. For the sake of simplicity, we will focus our attention on the financial product.
A popular financial instrument is known as a contract-for-difference (CfD), or "swap." It specifies a quantity, time period to be covered, and settlement price. The difference in the settlement price and the actual spot prices over the specified time period is multiplied by the quantity specified, resulting in the overall settlement amount between buyer and seller. For instance, if the CfD agreement had been for 3.5 cents/kWh and the actual average spot price had been 4 cents/kWh over the contracted month of June for a contracted amount of 1,000 kW, then the seller of the CfD would pay the buyer of the CfD as follows:
[4 cents/kWh - 3.5 cents/kWh] x 30 days x 24 hours/day x 1,000 kW = $3,600
Had the buyer of the CfD also purchased actual kilowatt-hours on the spot market at the rate of 1,000 kW/hour for each hour of June, his spot priced bill would be:
4 cents/kWh x 30 days x 24 hours/day x 1000 kW = $28,800
Now the buyer can combine his financial bill, showing a credit of $3,600, with the metered electricity bill of $28,800 to show a net bill combination of $25,200 or 3.5 cents/kW. He has, therefore, effectively hedged his electricity cost via the CfD at 3.5 cents/kWh. Also, had the average spot price been 2.4 cents/kWh, his combined price of electricity with the CfD still would have been 3.5 cents/kWh.
When the seller of the CfD (and he doesn't have to be a seller of electricity on the spot market) is developing the price he is willing to offer a CfD, he must consider the various possibilities of prices on the spot market in order to develop an expected price, and then add a risk premium accounting for the fact that prices may actually be higher than the expected value. This effectively becomes his floor price for a CfD. If he can get more for his CfD, he will try to do so, but competitive forces of other CfD sellers and knowledge by the buyer of price expectations will minimize departures above this floor price for a CfD.
The algebra of the combined bill for the buyer would look as follows:
= Quantity specified in the CfD contract for each respective hour i of the contract price
= Quantity purchased through the meter for each respective hour of the billing period
= Spot price of electricity in each hour i of the billing period
= Agreed-to settlement price for the contract period
- Contract period for CfD equals billing period for metered consumption
- TB= Total Bill
Since Pi is unknown until the end of the billing period, this "access charge" is ex-post. Once could also rearrange the algebra with the given assumptions such that:
Also, one could define a contracted or "protected" load to be: Customer Baseline Load (CBL) =
Now let's focus upon two-part RTP pricing as demonstrated by such utilities as Georgia Power Company, Duke Power Company, Niagara Mohawk, and Central and Southwest. The first part of this innovative tariff is a CBL usually based upon historical consumption priced at a traditional standard tariff. This theoretically enables the seller recovery of embedded revenue requirements. The second part of the two-part RTP tariff is changes in load priced at hourly RTP usually based upon marginal or market cost. This enables the seller recovery of incremental cost of the incremental sale, but does not require any fixed-cost contribution on the incremental sale since fixed-cost requirements would have been satisfied in the first part of the tariff (there would be a moderate adder in the RTP price for profit and risk coverage that one might argue contributes slightly to fixed-cost coverage). Note that the buyer would pay RTP prices for increases above CBL and would be credited RTP prices below CBL.
The algebra would look as follows:
One can rearrange the algebra to read:
The "access charge" is computed at the end of the billing period, or ex-post. Notice the similarity of equations iii) and v). In other words, the is nothing more than the quantity contracted under a , or , and the spot price Pi is the same thing as the RTPi price in this analogy. The only major difference is between the standard tariff rate (Std) and the agreed to settlement price for the contract period (CfD). As mentioned previously, the CfD basically is the expected spot price plus a risk premium necessary to guarantee the price. The Std, on the other hand, can be thought of as (1) the expected marginal cost; (2) an inherent risk premium required when offering a guaranteed price like Std; and (3) a contribution to fixed-cost requirements. Also, because the Std contains the additional component of "contribution to fixed cost," the motivational forces are different from those of a CfD; basically a buyer wants as little CBL as possible. Even though it does provide price protection, it is at a cost above that of simple risk insurance. The buyer of CfDs however, may want to maximize his purchase of CfDs to minimize his price risk.
Now notice the similarity in equations ii) and vii). Each has an access charge that, once contractually entered into, the buyer cannot influence; all the buyer can now influence is total hourly purchase . These equations, which simply are transformations of equations iii) and v), make it clear why all quantity is subject economically to the spot price, whether below or above the CBL. This is why two-part RTP possesses such powerful price response attributes (see "Real-Time Pricing - Supplanted by Price-Risk Derivatives," Public Utilities Fortnightly, March 1, 1997).
So two-part RTP, with a few minor exceptions, is the same thing as a spot market coupled with a financial instrument called a or Swap. Both are conducted ex-post. The few minor exceptions are when:
- The cost of the CBL is higher than the cost of the CfD because of the seller's need to satisfy the fixed cost revenue requirements.
- The buyer of a CBL therefore wants as little CBL as possible, while the buyer of CfDs may want a little or a lot.
The Ex-Ante and Ex-Post Solution
Is there a way when pricing two-part RTP to reduce these exceptions and in the process remove the need for a CBL load shape which, as previously mentioned, buyers want to minimize anyway? And can this solution still enable the seller to cover his fixed cost revenue requirements.
Yes. The key is to unbundle the risk premium from the fixed-cost coverage requirement and offer it to the customer as an ex-post risk premium option in the form of a CfD; and to develop an ex-ante access charge for the fixed-cost requirement.
An ex-ante access charge is computed upfront based on a forecast of spot prices. An ex-ante access charge can better guarantee the seller recovery of fixed-cost requirements without the need for the seller to purchase a CfD or hedge for himself if the seller merely passes the spot prices on to the customer. If a seller is offering to the buyer an ex-post access charge, he may not obtain the fixed cost coverage that is required unless the seller purchases a CfD to protect himself from rising spot prices.
The customer, however, does not have an overall price guarantee with an ex-ante access charge like he does with an ex-post access charge. For this reason, the customer must be offered an ex-post risk premium price protection product in the form of a CfD. This will enable the customer to configure the same protection as offered by the current ex-post bundled access charge (See ).
When designing an RTP program, it is vital that one employ a two-part design. It is now possible to do so in two ways, both capable of achieving highly successful results: (1) spot pricing plus an ex-post access charge (or CBL); or (2) spot pricing plus an ex-ante access charge and the offering of financial products (CfDs).
Two-Part Real-Time Pricing in Action
A. Standard tariff rate = 5 cents/kWh and includes an inherent risk premium of 0.5 cents/kWh
B. Expected average RTP price = 3 cents/kWh
C. CfD Price = 3.5 cents/kWh; a risk premium of 0.5 cents/kWh over expected RTP in order to cover risk of guarantee; RTP customers (as well as the utility) can purchase a CfD at this price
D. Load in question is 100 percent load factor (i.e., constant in all hours); the methodology will work with any load factor. It merely requires that the prices in the assumptions above be load-weighted. Metered load exactly equals CBL load.
E. Fixed cost coverage requirement is 1.5 cents/kWh (i.e., 5 cents -3 cents - 0.5 cents= 1.5¢)
F. Net revenue stability (i.e., reduced volatility) is a desired goal of the utility, and cost stability is a desired goal of the RTP customer.