Options are products which give the purchaser the right, but not the obligation, to buy or sell something at a set price. In the context of electric power, they are typically contracts which give the purchaser the right to purchase generating capacity at a fixed price. For this right, the purchaser pays a fee called a "premium". To date, option transactions have been the exception. However, for reasons which will be evident as this article progresses, this category is ready to boom along with that new class of players, the independent power marketers.

First, why haven’t there been more option transactions? To understand, let’s look at one transaction which took place.

The Minnesota Power & Light / Wisconsin Power & Light Option Agreement

Last year, MP&L sold WP&L an option to purchase 75 MW of firm, coal-fired capacity for the period commencing January 1, 1998 and ending December 31, 2007. The option was to be exercised within one year of its signing. For this right to purchase, WP&L paid $250,000 down, plus an additional $25,000 per month until the option expired, or until it was exercised. (These payments are called "premiums".)

WP&L entered into this agreement because it was really hoping that generating capacity from another, planned plant would become available to it. But it wasn’t sure, because the other plant still had to survive the regulatory review process. Thus, to hedge its bets, WP&L purchased the option.

As things turned out, WP&L was lucky. The original plant was not approved, so it needed the MP&L power, and after paying out more than $500,000 in premiums, it exercised its option, taking a contract for the coal-fired capacity.

Afterwards, with time to reflect on the transaction, it became clear to those involved that there was a problem. Not that WP&L didn’t get a good deal. It was happy with the terms of the capacity purchase agreement, although not so happy as it would have been if its original plans had come to fruition. WP&L’s ratepayers were protected, but what about its shareholders?

For shareholders, no up-side, only down-side

As things worked out, the $500,000 premium became a down payment on some well- priced coal fired capacity. But what if WP&L had not exercised the option? The premium payment would likely be a shareholder expense, as it would not have resulted in a useful contract for the ratepayers.

This places WP&L in an uncomfortable position. By doing what was right for its ratepayers, it took an uncompensated risk for its shareholders. That is, when the option is exercised, as it was, the ratepayers come out ahead, and the shareholders are kept whole. When the option is not exercised, the ratepayer is kept whole, but the shareholder is penalized. For the shareholder, option purchases are thus a no up-side, potential down- side transaction.

This explains why in the five years I’ve tracked every interutility transaction at the FERC, this is the only option contract I’ve found. It also helps to explain why, shortly after this transaction, WP&L formed an independent power marketing affiliate: Heartland Energy, and why the WP&L employee who signed the option contract now works for Heartland.

Options: A Role for Independent Power Marketers

Electric utilities are generally not very good at managing risks. Because of their regulated status, and their remaining monopoly powers, they have no reason to hedge, and as pointed out in the above example, significant disincentives to doing so. Thus, for example, unlike other major fuel purchasers, electric utilities rarely do anything but pay current market prices. If they were to lock in long-term fuel prices, they would take the risk that for some period those prices would be above market rates, and the state utility commission would “disallow” a part of the payment. It is much easier to ride the market prices up and down, and simply pass through the volatility to the ratepayers through fuel adjustment clauses. Similarly, with generating capacity, utilities have ceded the construction of greenfield plants to independent power producers, continuing to be involved in new powerplant construction primarily through their own IPP affiliates, because only in that fashion can the risks of construction be balanced by appropriate, unregulated rewards.

However, recently, electric utilities have entered a new phase in risk-averse behavior. Prodded by the debt rating agencies to reduce their long-term exposures, electric utilities have all but ceased offering the long-term power sales agreements which were the foundation for project financing for IPPs in the 80’s. Simultaneously, perhaps to justify the failure to either buy or build, utility forecasts are showing little or no need for new generating capacity for the foreseeable future. Right or wrong, such forecasts allow electric utilities to defer the painful choice between adding to rate base or buying under long-term contract.

However, at least one utility, Jersey Central Power & Light, has pointed out that with the advent of open transmission access, there is a marketplace for energy and capacity, and in a marketplace, shortages tend to be self-correcting. Based upon this rationale, JCP&L has moved to cancel its long-term procurements and replace them with short and mid-term contracts.

JCP&L’s approach is clearly the wave of the future. However, the question then becomes: How does one create this new marketplace? Utilities tend not to be very quick players. They are not constituted to operate in a market environment. Actual power users are not yet permitted to buy and sell power, and while this will undoubtedly change, it does not permit much activity by the ultimate customers today.

This leaves the independent power marketers. In this new field, many of the IPMs are experienced natural gas marketers--- Natural Gas Clearinghouse, Enron, Howell, CVE, and others have established affiliates to exploit their experience in the deregulation of natural gas to the new competitive power markets.

Natural gas has been a treated as a commodity for several years now, with an active futures market made by NYMEX, and over-the-counter trade in forward contracts, swaps and options. Thus, for the gas marketers, taking these products into electricity is a natural step.

However, options have a particularly valuable role, because of the oddities of electric power regulation and the need to exert leverage in order to be a player in this most capital- intensive of all industries.

Most importantly, IPM’s can pay option premiums, and for the risk they take, receive commensurate rewards -- just like the independent power producers before them, and unlike hapless pioneers such as WP&L.

Examples: Using the Option Mechanism Today

(1) Calls:

Many utilities perceive themselves to be "long" on generating capacity. That is, they have more of the stuff than they need for the foreseeable future. If the capacity is in a region which is glutted, there may be no utility customers willing to pay a reasonable price for the surpluses, so it either lays fallow, or the plant is operated with the energy being sold into the short-term power markets with no premium for capacity value.

A role power marketers can play to alleviate this problem is by paying the long utilities a premium for the right to purchase generating capacity at a specified price, called the "strike" price. For this, the IPM pays the utility a fee, called a "premium". This premium revenue, because it has not been considered previously by utility commissions, becomes additional shareholder profit, going right to the bottom line.

From the IPM’s perspective, purchasing this type of option, known as a "call", has several advantages:

• It differentiates them from the hoi polloi of consultants and power marketers who wish to be paid to assist the utility in finding new customers for its surplus capacity.

• It provides an affordable mechanism for taking a position in substantial amounts of generating capacity.

• It provides the leverage needed to make substantial profits without having to take inordinate risks.

To understand the value of an option, lets again go back tothe MP&L/WP&L example. In that case, the "premium" was roughly $500,000, for the right to purchase 75 MW of firm, coal-fired capacity for ten years, from January 1, 1998 through December 31, 2007. The "strike price" was $7.52/kW/Mo, escalating to $10.71/kW/Mo by the year 2007.

However, say that during the option period, (which was over a year long), the mood of the country changed. Say we left the recession, oil prices increased, and suddenly coal-fired capacity was in great demand. Replacement cost for coal capacity runs about $25/kW/Mo. However, say that during the year, other utility customers began to change their minds, and while they weren’t ready to commit to construction, they were interested in purchasing coal -fired capacity at a discount from replacement costs.

With our option in hand, we are in a position to offer coal-fired capacity at that discount. Imagine that we could exercise the option at $7.52 escalating, and mark it up by $5/kW/Mo. It would still be a substantial discount from replacement costs, and for our $500,000 investment, we could turn a tidy profit.

At $5/kW/Mo. x 75 MW x 10 years, the profit on this transaction would be $45 million. Less, of course, the half million dollar premium, and the overhead of a power marketing operation.

It is thus easy to see the attractiveness of the use of calls. For utilities selling calls, it is immediate additional profit. To the extent it is perceived as being an "out-of-the-money" call, the utility perceives itself to be selling something of little value.

For the IPM, even out-of-the-money calls which are not exercised can be profitable.

Today, IPMs are being formed rapidly. In many ways, the industry is very much like the early cogeneration business, with mom and pop operations springing up, and refugees from other industries rushing in. These new IPMs are hungry for product, and calls are the perfect addition to a portfolio for the optimistic IPM. Profits can thus be made by an IPM which originates a call, simply by reselling all or part of it to another IPM at a profit. Only when the call expires must it be exercised in order to avoid losing all value. And calls such as the WP&L/MP&L option contract, with provision for extension by the payment of additional fees, need not even include a final termination date. It could go on, producing more revenue for the selling utility, forever.

(2) Puts

With utilities dropping out of the game of purchasing power from IPPs under long-term contract, project financing has gotten more difficult. Now, a project may have sufficient guaranteed income to cover a part of its debt service, but still not have sufficient revenue to support project financing. If the developer has enough faith in the market, it might be willing to invest more equity in the project in order to allow it to go forward, taking the risk that there will be a market there. Or, in the alternative, the IPP can purchase a "put".

A put, in contrast to a call, gives the purchaser the right, but not the obligation, to sell capacity at a specific price. Thus, the IPP can use a put to place a "floor" under the price at which it will be able to sell capacity.

Necessarily, the floor will generally be just high enough to allow financing to go forward. The higher the floor, the more expensive the put. If all goes as it should, the put will never be exercised. Instead, the IPP will use it to support financing, and afterwards, seek a buyer which will be willing to pay a more attractive price for the capacity.

For the independent power marketer, the put provides immediate income, as it is paid for taking on the potential liability of a capacity purchase. However, the IPM does face potentially substantial liabilities. If the market goes against it, and the put is exercised, almost by definition it is because the IPP has been unable to find a buyer at a better price. The IPM will have to take a loss. Just as the call creates tremendous upside leverage, the put creates vast downside leverage.

Because of this enormous risk, puts can be inordinately expensive. However, one way of "buying-down" the put is through the simultaneous sale of a call. The call creates a price ceiling for the capacity, as the IPM can require delivery at the call strike price. The call/put combination creates what is called a "collar". The price of the capacity can vary, but only between the floor (put price) and the ceiling (call price).

Done in this fashion, the result can be a "no-cost collar". That is, no money changes hands when the agreement is signed, and the call price is set by reference to the desired put price.

A no-cost collar would be particularly desirable to an electric utility seeking to offload downside risk, because there is no premium payment. Also, because of the potential upside from the call component of the collar, there is a greater likelihood that the company desirous of a put will find a supplier.

Conclusion

The key question one might ask is: "Why now?" Why are independent power marketers being formed today at a rate of one each week? The answer is that the FERC is implementing open transmission access under the EPAct of 1992. With transmission access, we for the first time have liquidity, so that capacity purchased in one region can be sold in another. That liquidity is providing the means by which independent power marketers can create new value by taking on risks which would be uncompensated if taken by utilities. This is merely another aspect of the commoditization of electric power.