Hedging Oil Revenue - Www. Dor.alaska

8/6/2019 Hedging Oil Revenue - Www. Dor.alaska

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Hedging Oil Revenues

What is it?

When should Alaska do it, if at all?

Why should Alaska consider it?

Alaska Department of Revenue

Wilson L. Condon, Commissioner

October 21, 2002


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Alaska Department of Revenue Hedging Oil Revenues - October 21, 2002 Page1

I. INTRODUCTION AND OVERVIEW

Although farmers settled in Alaska long before oil was discovered at Prudhoe Bay,

Alaskas economy is far more dependent on oil prices than farm prices. There is,

however, one similarity between farming and oil that probably escapes most Alaskans.

Most farmers, who are perennially in debt, cannot tolerate price volatility. Weather can

kill their crop, market swings can kill their business, and they dont have a large savings

account to cushion against bad years. Thats why many farmers sell their crop before it

is harvested. They are willing to lock in a predictable price to at least cover their costs,

even if it means giving up the opportunity to make more money if prices rise. Its called

trading in futures, or simply hedging.

The State of Alaska is in much the same position with oil. Market swings in oil prices

can dramatically cut into our revenues and could impair our ability to cover the fixed

costs of schools, roads, law enforcement and the other public services that are part of

the daily lives of 630,000 Alaskans.

Hedging essentially comes in two flavors:

1. Selling in advance to lock in a price and, in exchange, giving up the opportunityto make more money if prices rise (e.g., hedging with futures).

2. Paying a premium to ensure a minimum future price for oil, while retaining the

opportunity to make more money if prices rise (e.g., hedging with options).

Unlike the farmer, we have not yet needed to pay the costs or take the risks of

hedging because our cushion against fluctuating oil prices for the past decade has been

the Constitutional Budget Reserve Fund (CBRF). Farmers, too, could avoid the costs of

hedging their future income if they had a cushion similar to Alaskas $2.15 billion CBRF

(market value as of October 21, 2002). Voters established the fund in 1990 for exactly

that purpose to fill the gap between a fluctuating revenue source and a constant

need for public services.


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The Budget Reserve Fund is a marvelous tool when used properly. We have

strayed, however, from its original intent. Instead of simply covering temporary revenue

shortages as oil prices move up and down each year, weve been draining the account

to cover a structural gap in Alaskas finances. As North Slope oil production declines,

taking state revenues down with it, were spending more than we take in each year and

were relying solely on the CBRF to fill that gap. Similar to an oil field, the Budget

Reserve Fund is a non-renewable resource. The large oil and gas tax and royalty

cases and subsequent investment earnings that filled the fund with $7 billion over

the past decade have all been settled, and the Department of Revenue projects the

fund will run out of money in the next two to three years.

Considering how important the CBRF is to Alaskas fiscal health, and how it can

allow us to survive times of low oil prices, it would be irresponsible to empty the CBRF.

Unless we do something soon, thats exactly what will happen. And when that

cushion goes flat in two or three years, we will be in even worse trouble than the farmer

with heavy debt and low prices. The farmer has just one family to worry about, whereas

unless we have a fiscal plan in place we will be unable to provide the necessary public

services for an entire state. Even with a fiscal plan, we risk falling short of meetingAlaskans needs unless we maintain an adequate balance in the CBRF or, as a more

costly alternative, have a hedging program to protect our revenues in years of below-

average oil prices.

For example, what if the state adopted a fiscal plan of taxes and other increased

revenues that covered spending needs with $18-a-barrel oil. Since this is close to what

North Slope crude has averaged for the past decade, its a reasonable place to start.

But what if oil averaged just $10 a barrel one year. The state would fall short by more

than $500 million of being able to cover its checks for schools, roads and prisons. If the

CBRF is still around, it could cover the shortage. But without it, where would we turn?


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Without the CBRF to cover our fluctuating revenues, neither a fiscal plan nor a

hedging program will solve the problem alone.

Alaskans cannot talk about long-term fiscal health without the CBRF unless there is

something to replace the Budget Reserve Fund in those inevitable years of low oil

prices. Alaskans could find ourselves in a similar situation to the farmers who take from

their childrens college funds to save their farms. We could be pushed into taking from

the Permanent Fund or the dividends to save essential public services. Not only

pushed, but pushed very quickly. Drawing from the Permanent Fund earnings reserve

or dividend account would be the quickest way to get money, considering that it could

take a year or more to pass new tax laws and start collecting the new revenues.

Assuming a life without the CBRF, and assuming few want to use the Permanent

Fund as a cushion against low oil prices, hedging becomes the preferred alternative.

Looking ahead to the day when the CBRF hits empty if that is the plan we need to

start soon to get a hedging program in place. Hedging would work best when you pay

to lock in revenues at least two and preferably three years into the future. So if Alaska

is going to need the stable revenue of a hedging program in 2005, it ought to start

working on it today. That means we would need to adopt the following timetable:1. The Department of Revenue would have to begin consultations immediately with

the Department of Law to determine if there are any constitutional issues at

stake in establishing a hedging program.

2. Assuming there are no constitutional problems, the departments would have to

work together to draft legislation for the 2003 session to set in place the state

statutes needed to operate a hedging program and to cover its costs.

3. Legislative approval would be required in 2003.

4. The state would need to have its hedging program under way before mid-2003 at

the latest if it is to be prepared to deal with the revenue problems that would

occur when the Budget Reserve Fund runs out.


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There is one other reason to consider hedging: If we want to know with more

certainty exactly when the CBRF will hit empty. By starting a hedging program

immediately, the state could lock in oil revenues for the next few years. This would

provide the public and elected officials with a timetable for draining the CBRF. We

would know our revenues each year and how much we would need to withdraw from

the fund. We wouldnt need to speculate how oil prices would speed up or slow down

the death of the CBRF. The outcome would be essentially the same, only without the

uncertainty of when. We do not recommend this option since we believe the certainty of

knowing when the CBRF will run out isnt worth the cost.

Our best option is keeping the Budget Reserve Fund alive to serve its original

purpose, which is to provide a cushion against a drop in oil revenue caused by below-

normal oil prices. The Department of Revenue is raising the issue of hedging to make

Alaskans think about the real problem, which is the lack of a long- term fiscal plan. The

CBRF can serve as our hedging tool only as long as it exists. It can exist only if the

state adopts a fiscal plan that, in years of normal oil prices, covers our spending needs

and retains a buffer for years when oil prices drop.

We could avoid the costs of hedging entirely if we maintain the CBRF at areasonable balance where it could do the job for which it was originally intended. We

believe a reasonable balance for the CBRF of $1 billion would preserve public services

even if the state suffered through a period of below-average oil prices. This assumes

we have a solid fiscal plan that balances state spending at normal oil prices.

We offer this opinion, backed up by this report, because oil prices are up, which

means some say this would be a good time to pay the cost of locking in future oil royalty

and tax revenues at higher prices. Concerned Alaskans ask about hedging whenever

oil prices significantly exceed the long-term average. But what could the state gain or

lose? What would be the cost? This report attempts to answer those questions.


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What follows is a more detailed analysis of hedging and how it would work:

Section II is a general description of the states hedging opportunity.

Section III explores the benefits of hedging the states oil royalty and production taxrevenue.

Section IV summarizes the costs and risks of a hedging program.

Section V catalogs the constitutional and legislative issues that must be addressed

before the state could initiate such a program.

Section VI summarizes the Department of Revenues recommendations with

respect to oil revenue hedging.

Section VII provides a description and history of the markets the state might use for

a hedging program.

Section VIII provides a detailed review of the mechanics of several different

strategies the state could employ in a hedging program.

Section IX summarizes the differences between the hedging opportunities available

on the New York Mercantile Exchange (NYMEX) and the hedging

opportunities available in the Over-the-Counter (OTC) market.Section X reviews the credit risks the state would face if it undertook a hedging

program.

Section XI restates our conclusions.


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II. HOW WOULD HEDGING WORK?

The Department of Revenue expects that receipts from oil royalties and production

taxes will provide two-thirds of the states unrestricted general-purpose revenue for the

next five years. These revenue sources depend directly on the price of oil. For each $1

per barrel change in the price of oil, the states annual royalty and production tax

revenue will rise or fall by about $65 million. The question is how to protect those

revenues and the public services they pay for from falling oil prices.

Active futures and options markets for crude oil provide the state an opportunity,

during periods of high oil prices, to put a floor under or a range around that is to

hedge its anticipated royalty and production tax revenue. Because these markets

anticipate oil prices to remain above the historical average for the next several years,

the state could take advantage and for a price secure a more stable revenue

stream for the next few years. There are two primary instruments used to hedge:

futures and options.

Futures contracts provide for the future delivery of West Texas Intermediate crude

oil at a specified price.1

Any profit or loss from the agreed upon price vs. the actualmarket price on the delivery date is usually settled on the delivery date. For example, in

mid-April 2001, the state could have contracted to sell WTI at $23 a barrel for delivery in

December 2003. If the market price is below $23 a barrel in December 2003, the state

would still receive its $23 because the buyer of the futures contract would pay the state

the difference between the market price and $23. But if the price goes up, and WTI is

worth $25 a barrel in December 2003, the state would have to pay the difference

between the market price and the $23 price in its futures contract. Of course, if prices

are up, the state could use its higher revenues to pay the bill. However, that could be

1 Throughout this paper, the term futures includes both futures and forward contracts. The term futures usuallyrefers to a contract with standard terms for the future delivery of a commodity sponsored by an organized exchange.

The term forwards usually refers to a contract with negotiated terms for the future delivery of a commodity sold inthe over-the-counter (OTC) market. See Section IX of this paper for a summary of the important differencesbetween futures and forwards.


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expensive. In summary, the state would be protected if prices fall but could lose out on

a lot of extra revenue if prices rise. Although the up-front cost for the futures contract is

minimal, the state could be faced with a significant liability if oil prices rise above the

futures contract. (This is explained further in Section VIII.)

Options are more like an insurance policy, with the premium paid up front. For a

per barrel fee paid in advance, an options contract gives the party on one side of the

contract the opportunity but not the obligation to buy or sell WTI oil to the other

party at a prearranged price. For example, the state could pay the up-front options

premium to sell WTI at $23 a barrel in December 2003, locking in that price. This would

be buying an option to sell oil called a put in the trade jargon. If the price is below

$23 in December 2003, the state would exercise its option and the party that sold the

put would have to make good to the state on the difference between the market price

and $23 a barrel. And if the price in December 2003 were above $23, the state would

gain additional royalty and production tax revenue from the higher price. In summary,

the state is guaranteed at least $23 either way, but that guarantee would come at the

up-front cost of the options contract. The cost of buying put options is substantial,

although there would be no downside risk or additional costs at the end of the contract.

There is no futures or options market specifically for Alaska North Slope (ANS)

crude oil, but there is a way around that. Because the prices for different crude oils

around the world generally move up and down together, entering into futures contracts

to sell WTI or buying options contracts to sell WTI would provide a means for the state

to hedge its ANS royalty and production tax revenue. As the WTI futures prices rise or

fall, the prices for ANS will rise and fall as well, although the spread between WTI and

ANS can vary. We would need to know two things to use the market for WTI to hedge

the states ANS revenues:

1. The likely relationship between ANS and WTI prices.

2. The current prices for future deliveries of WTI.


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Over the past 15 years the price for WTI at its contractual delivery point, Cushing,

Oklahoma, has averaged about $1.65 per barrel higher than the spot price for ANS

delivered to West Coast refineries. The April 12, 200l NYMEX prices for future

deliveries of WTI are presented in Table 1 on Page 10. Table 1 also reflects a

corresponding set of equivalent ANS futures prices calculated by subtracting $1.65 per

barrel, the average WTI-ANS differential, from the monthly WTI futures prices. By

entering into futures contracts for the sale of WTI at the prices set forth in Table 1, or by

purchasing options to sell WTI at prices approximating those reflected in Table 1, the

state could either set or put a floor under its royalty and production tax revenue at levels

consistent with the ANS prices reflected in the table, subject to something called basis

risk discussed in Section IV.

Figure 1 on Page 9 reflects the December 1990 through March 2001 monthly ANS

spot prices for the West Coast deliveries, along with the equivalent ANS futures prices

from Table 1 for May 2001 through December 2007.


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April 2001 Futures

$7

$10

$13

$16

$19

$22

$25

$28

$31

$34

Dec-

90

Jun-

92

Dec-

93

Jun-

95

Dec-

96

Jun-

98

Dec-

99

Jun-

01

Dec-

02

Jun-

04

Dec-

05

$ / Barrel

ANS-WC 60-Mon Moving Average Futures

Figure 1. ANS West Coast ( Actual, December 1990 - March 2001)and ANS-Adjusted Futures Market Prices

ka Department of Revenue Hedging Oil Revenues - October 21, 2002 Page 9


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TABLE 1NYMEX CLOSING PRICES FOR WTI ANDEQUIVALENT ANS WEST COAST PRICE

APRIL 12, 2001

Delivery Closing WTI Futures Equivalent ANS FuturesDate Price (WTI Minus $1.65)

($/bbl) ($/bbl)

May 2001 $28.25 $26.60June 2001 $28.59 $26.94July 2001 $28.73 $27.08August 2001 $28.59 $26.94September 2001 $28.25 $26.60October 2001 $27.89 $26.24

November 2001 $27.53 $25.88December 2001 $27.18 $25.53January 2002 $26.87 $25.22February 2002 $26.57 $24.92March 2002 $26.29 $24.64April 2002 $26.032 $24.38May 2002 $25.79 $24.14June 2002 $25.56 $23.91July 2002 $25.33 $23.68August 2002 $25.12 $23.47September 2002 $24.91 $23.26

October 2002 $24.70 $23.05November 2002 $24.51 $22.86December 2002 $24.33 $22.68January 2003 $24.16 $22.51February 2003 $24.00 $22.35March 2003 $23.86 $22.21June 2003 $23.54 $21.89July 2003 $23.45 $21.80August 2003 $23.36 $21.71September 2003 $23.28 $21.63December 2003 $23.07 $21.42December 2004 $22.67 $21.02December 2005 $22.35 $20.70December 2006 $22.05 $20.40December 2007 $22.05 $20.40

2 We use $26.00 exactly in examples later in this paper.


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III. WHY WOULD THE STATE WANT TO HEDGE?

The contrast reflected in Figure 1 on Page 9 between ups and downs of the past

decades ANS prices and those prices potentially available from a hedging program

illustrate two reasons state policy makers might elect to hedge. First, the volatility in

state revenue could be substantially reduced. Second, with a long-range fiscal plan in

place, the state could ensure its ability to meet its public service obligations during short

periods of very low oil prices. Hedging is not expected to increase royalty and

production tax revenue over the long term but, at some cost, it can substantially

increase the year-to-year consistency of royalty and production tax revenue to the state.

Although the futures prices on any given day generally reflect a smooth path from

current price levels back to the long-term expected price, the real path of oil prices, as

Figure 1 illustrates, is chaotic. This chaotic behavior is often referred to as volatility.

Most hedging is done to remove or reduce the uncertainty associated with a volatile

revenue stream.

The states revenue stream is volatile because it depends heavily on oil prices. Oil

prices are volatile for a number of reasons: weather, Middle East politics, changes indemand and supply forces, to name a few. Whatever the cause, volatility is undesirable

to the state, especially if the consequences are a suddenly reduced revenue stream and

an inability to meet obligations.

Fortunately for the state, we are buffered from the detrimental effects of volatility by

our reserves for at least the near term. For now, any shortfalls in revenue are funded

from the states Constitutional Budget Reserve Fund. These shortfalls can be

anticipated, such as the long-term fiscal gap, or unanticipated, such as those caused by

volatile oil prices. The Budget Reserve Fund was created to address the later but is

being rapidly depleted by the former.


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But how much longer will the CBRF last? The inability to provide an answer to that

question has complicated the search for a long-term solution to the states financial

problems and forestalled serious consideration of a replacement for the reserve fund. A

significant part of the answer depends upon oil prices. Hedging our royalty and

production tax revenue would allow us to more accurately predict when our reserves will

run out. Reducing volatility would improve financial management, enhance fiscal

planning and reduce the risk of sudden financial loss. These desirable outcomes have

economic value, so it should come as no surprise that they are gained at a price. The

question becomes whether we are willing to pay that price to gain the benefits of

hedging. That is, would the benefits of knowing how long the CBRF will last be worth

the cost? We do not believe it would.

The CBRF makes it possible for the state to self-insure against short periods of very

low oil prices. As long as a significant balance remains in the CBRF, the state can

always turn to that funding source to continue paying for vital public services in times of

low oil prices. Even after the CBRF is exhausted, under current law the Earnings

Reserve Account of the Alaska Permanent Fund is legally available to pay for public

services. However, if neither of these reserves were available, the volatility of the

states royalty and production tax revenue and the likely dependence of the state uponthat revenue would create a high risk that the state would not be able to fund vital

services. That is not a hole the State of Alaska would want to dig itself into.


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IV. REASONS NOT TO HEDGE

There are several reasons why state officials might be reluctant to initiate a hedging

program.

First, the state already has a means for paying for vital public services when oil

prices are low the CBRF. But if the state continues its current fiscal habits, the

CBRF will not last forever. When it is exhausted, the state will be forced to significantly

restructure its public finances. Because oil prices are so volatile, using the CBRF as the

states insurance against low oil prices makes it impossible to precisely forecast when

the CBRF will be exhausted. This uncertainty, no doubt, contributes to the

unwillingness of state policy makers and the public to take any significant steps,

including hedging, in anticipation of the need to restructure the states public finances.

If the state had a fiscal plan that balanced its budget at normal oil prices and retained a

sufficient balance ($1 billion) in the CBRF, the Budget Reserve Fund could continue to

fill this role indefinitely. Money would be deposited into the fund in years of high oil

prices and withdrawn in years of low oil prices.

Second, a hedging program would cost money. When considered alone, thetransaction costs for entering into futures contracts seem very reasonable; they would

cost something on the order of $0.10 per barrel for each barrel of WTI futures sold. To

hedge all the states royalty and production tax revenue using futures would require

contracts to sell 180,000 barrels per day (5,400,000 barrels per month) of WTI futures.

At $0.10 per barrel, a three-year futures program of this magnitude could cost $18

million to $20 million in up-front transaction fees.

But, if during a three-year hedging program based on futures contracts, WTI futures

prices increased significantly, the state would be required to fund a margin requirement

that is, pay up to cover the higher price. Remember, in a futures contract, the state

would be guaranteed a minimum price but would owe anything over that price to the

contracts buyer. If, for example, WTI futures prices on average increased by $5 per


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barrel, the increased margin requirement for such a price change on a three-year

futures contract would be over $950 million. If oil prices actually stayed that high for the

three-year period, the state would recoup that amount through higher than anticipated

oil revenue. If the price of oil dropped back to the hedged price, the margin required

would be reduced and the states payment returned. If the state entered into a futures-

based program, it would need to be able to come up with sums of money of this

magnitude or larger on relatively short notice. This could be politically and financially

difficult for the state.

The per barrel up-front costs of an options-based program would vary widely. For

example, a $0.75 per barrel fee would put a floor under near-term prices at a level about

$1.00 per barrel under the futures prices for the upcoming month only. However, it

wouldnt do the state that much good to lock in an oil price for just one month ahead.

Like all insurance, the longer the protection you buy, the greater the cost. An option

similar to the one above, covering a one-month period three years from now would cost

close to $3.00 a barrel. An options-based hedging program covering three years would

cost something like $300 million. Although the up-front cost would be more than a

hedging program using futures, an options-based program would allow the state to

retain any additional revenue if oil prices move higher than the hedged level.

A third reason policy makers might be reluctant to launch a full -scale ANS royalty

and production tax hedging program is something called basis risk. Basis risk is the

possibility that the price of the proxy used in a hedge (in this case WTI) does not

behave exactly like the price of the item being hedged (ANS). While the average

difference between WTI and ANS has been about $1.65 per barrel, the difference

fluctuates. The fluctuations for the most part widen this differential. If, for example, the

state had hedged its royalty and production tax revenue on the basis of an average

$1.65 per barrel differential, and then WTI increased by $3 while the ANS price

remained unchanged, the differential would increase to $4.65 per barrel. The state, in

this example, would actually lose something over $15 million in its hedging program for

each month the differential remained this wide.


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Finally, some policy makers will be reluctant to take the political risks of a hedging

program. If a program succeeded, it is unlikely the policy makers who took the initiative

to create the program would be rewarded with public congratulations. On the other

hand, if the state lost significant sums because the differential between ANS and WTI

widened from its long-term average for a significant period of time, or if prices increased

significantly and the state had sacrificed that upside to reduce or eliminate the volatility

in its royalty and production tax revenue, the conventional wisdom is that public criticism

would be harsh.


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V. LEGISLATIVE AND CONSTITUTIONAL ISSUES

Before the state could initiate an oil-revenue hedging program, the legislature would

have to pass a law that authorized and spelled out the programs parameters. Two

states currently have oil-revenue hedging programs on the books, although neither state

does any hedging: Texas and Louisiana. The legislative authority for those programs

are: Texas V.T.C.A., Government Code 404.0245, Crude Oil and Natural Gas

Futures Contracts, (West 2001); Louisiana La. Rev. Stat. Ann. Title 49, 330 A (4),

(West 2001). Copies of both statutes are attached as Appendix A. (See Pages 49-50)

Some aspects of a hedging program clearly would require specific appropriations.

For example, if Alaska embarked upon a program that involved the purchase of options,

it would need appropriated funds to purchase the options. We are not certain which

elements of a futures-based hedging program would require appropriations; certainly

appropriations would be necessary for any fees or commissions associated with the

program. If the state were required to put up large amounts from time to time to cover

margin requirements in a futures-based program and on occasion that could be

hundreds of millions of dollars it is not clear if appropriations would be required. The

same issue arises with respect to the payments required when closing out futurescontracts.

The uncertainty about the need for appropriations for a futures-based program also

raises questions about the constitutional prohibition of dedicated funds. Would

contractual commitments to cover margin requirements or to close out contracts two or

more years in the future violate that prohibition? We have discussed the appropriations

question and the constitutional issue with the Department of Law, and they are not now

prepared to provide definitive answers.


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VI. DEPARTMENT OF REVENUE RECOMMENDATIONS

The department recommends against initiating a hedging program if the state

adopts a stable long-range fiscal plan and if the CBRF balance is expected to remain

above $1 billion. There is no need to pay for a hedging program when an adequately

funded CBRF does the same job. If it becomes apparent that state policy makers

intend to spend substantially all of the CBRF before they restructure the states finances

eliminating our self-insurance fund against low oil prices then we believe a state

oil revenue hedging program may become necessary. Because a hedging program

may become necessary, preliminary work ought to begin now.

The principal benefit of an oil revenue hedging program would be to significantly

reduce fluctuations in the state's year-to-year oil royalty and production tax revenue.

With this reduction in revenue volatility, policy makers would know much more precisely

both when the state would exhaust its CBRF and how large the subsequent year-to-

year revenue gap is likely to be. Would these benefits be worth the costs of a hedging

program? Our judgment is that they would not, but it is just that a judgment call.

Reasonable, prudent decision-makers could easily conclude that the benefits of

instituting such a program now is worth the costs.

Although our department recommends against instituting an oil revenue hedging

program now, we can foresee a time when circumstances could make a state oil

revenue hedging program to dampen oil revenue volatility necessary.

Since the early 1990s, volatility in the state's oil royalty and production tax revenue

has been absorbed by our Constitutional Budget Reserve Fund. In Fiscal 1999, the

average wellhead price for ANS was $8.47 per barrel. The state's unrestricted oil and

gas tax and royalty revenue that year was $913 million. To balance the budget the

state withdrew almost $1 billion from the CBRF.


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By contrast, just two years later in FY2001, the wellhead price for ANS averaged

$20.06 an increase of almost $12 from two years earlier. As a result of this dramatic

price turnaround, the state's FY2001 unrestricted oil and gas tax and royalty revenue

was $1.875 billion and the state actually deposited $8.6 million of surplus revenues into

the CBRF.

Now look at what might happen in a typical year after the state exhausts its CBRF.

Assume that, by the time the CBRF is exhausted, the state has implemented fiscal

measures that close the gap at average oil prices. Doing this would require additional

revenue of about $1 billion to make up the difference between current annual recurring

unrestricted revenue (mostly oil) and the annual general fund budget (currently more

than $2.4 billion). Assume further that the CBRF has been completely exhausted and

that the accumulated excess earnings in the Permanent Fund Earnings Reserve

Account are unavailable. Assuming these facts, if oil prices fell to their 1999 level the

state would face a $500 million to $600 million shortfall with no reserves. If the state

has taken no other steps, it would have no option but to substantially and suddenly

cut the budget or enact some kind of emergency tax measure. Both of these

measures could have disastrous effects on the states economy.

If it looks as though the state is likely to completely spend its CBRF and the

accumulated balance in the Permanent Funds Earnings Reserve Account is

unavailable or spent, oil hedging may be the best tool available to protect essential

public services in times of low oil prices. However, even that will only work if the state

has a long-term fiscal plan to balance the budget in years of average oil prices. To

ensure the success of such a hedging program, the state should initiate the program at

least two years (and preferably three) before it exhausts the CBRF.

Heres why hedging works best if set up two or three years in advance:

The information presented in Figure 2 on Page 20 compares the monthly WTI

prices (blue line) with the futures price available 36 months earlier (the red line) for that


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same month. For example, you can see that the actual WTI price for March 2001 was

$28.50 per barrel; on March 2, 1998 the futures price for March 2001 was $18.17 per

barrel. Notice that the red line, the three-year forward futures price (based on the

futures price three years before), is much less volatile than the month-to-month

delivered price for WTI. In fact, the three-year forward price has usually been within $2

of the apparent long-term average WTI price. Consequently, by using a 36-month

futures hedge, the state could, subject to the basis risk described in Section IV, insure

its royalty and production tax revenue at a price level close to the apparent long-term

average price level. In Figure 2, when the actual delivered WTI price (blue line) fell

below the three-year forward futures price (red line), the state would have received

additional revenue from such a hedging program. The state would have foregone the

upside revenue when the delivered prices (again the blue line) exceeded the three-year

forward futures price (red line).


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Figure 2. WTI Actual Price and Weekly (Monthly Quote) 36-Month ForwardNYMEX Futures Price from 36 Months Earlier

6

11

16

21

26

31

36

Nov-96

Mar-97

Jul-97

Nov-97

Mar-98

Jul-98

Nov-98

Mar-99

Jul-99

Nov-99

Mar-00

Jul-00

Nov-00

Mar-01

Jul-01

Nov-01

Mar-02

Jul-02

Nov-02

Mar-03

Jul-03

Nov-03

$ /Barrel

Actual WTI Price

WTI 36-Month Forward Futures Price

from 36 Months Earlier



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Figure 3 on the next page reflects actual delivered WTI prices (blue line) together

with the contemporaneous one-year (yellow line) and the three-year (red line) forward

prices. The data reflected on this figure clearly show: 1) one-year forward prices are

more volatile than three-year forward prices; and 2) very low (1998) and very high

(2000) current WTI prices seem to lower or raise, respectively, the levels of one-year

and three-year forward prices. This data suggests that initiating a hedging program to

protect royalty and production tax revenue three years in the future might well succeed

in securing average revenue no matter whether current WTI prices were high or low.

On the other hand, this data also suggests that a program initiated to protect royalty and

production tax revenue just one year in the future would probably fall well short of

securing average revenue if the program was initiated when WTI prices were low.

Consequently, if it is clear that state policy makers are likely to exhaust the CBRF

before they put state finances on a firmer base, the state should seriously consider a

hedging program in Fiscal 2002 or 2003 while there is still time to hedge three years in

the future.


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Figure 3. WTI Actual Price and Weekly (Monthly Quote) NYMEX Futures Pricefor Delivery in 12 Months and Delivery in 36 Months

6

11

16

21

26

31

36

Nov-93

Mar-94

Jul-94

Nov-94

Mar-95

Jul-95

Nov-95

Mar-96

Jul-96

Nov-96

Mar-97

Jul-97

Nov-97

Mar-98

Jul-98

Nov-98

Mar-99

Jul-99

Nov-99

Mar-00

Jul-00

Nov-00

Mar-01

Actual WTI Price

$ /Barrel

WTI Futures for Delivery in 36 MonthsWTI Futures for Delivery in 12 Months



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VII. THE MARKETS

A. History

Oil futures markets developed initially to facilitate the buying and selling of crude oil

and crude oil products for actual delivery at a future time. Later, markets developed to

handle buying and selling of contractsfor future delivery of crude oil and various oil

products. A futures contract is a firm commitment to deliver or receive a specified

quantity and grade of a commodity at a specific location within a specified month.

In the early 1970s the producer nations in the Organization of Petroleum Exporting

Countries (OPEC) undertook to control and increase the price for their crude oil

production by establishing an official price. As the production base expanded inresponse to rising prices, and with the development of spot markets, producer nations

found it increasingly difficult to maintain the price they had agreed to. In 1986 OPEC

abandoned its strategy of defending a price.

As OPECs price strategy began to disintegrate, the markets in crude oil and crude

products came to behave more like those of other commodities. Individual pricing

services emerged that report detailed place and time transactions, increasing market

transparency. Price volatility came to characterize oil markets as prices responded

more quickly to supply and demand pressures. In addition, these new market

conditions led to a large increase in energy commodity trading.

The first successful futures contract was for No. 2 heating oil introduced on the New

York Mercantile Exchange (NYMEX) in 1978, followed by a contract for leaded gasoline

in 1981.3 At the same time the International Petroleum Exchange (IPE) in London

opened for trading gas-oil futures.

3 Two early energy futures did not endure. A crude oil contract introduced in 1974 on the New York CottonExchange failed due to problems standardizing quality of the underlying product. A contract in No. 6 residential fueloil introduced in 1978 failed because utilities, the major purchasers of this product, did not need futures to manage

risk; they could usually pass escalating prices on to customers through fuel adjustment charges.


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A crude oil futures contract was introduced by NYMEX in 1983, using West Texas

Intermediate (WTI), a light sweet crude, delivered at Cushing, Oklahoma as the

benchmark. IPE introduced a similar contract for Brent in the United Kingdom in 1988.

The NYMEX introduced an options contract for WTI in 1986. By 1990, 10 active futures

contracts relating to crude oil and crude oil products were traded on commodities

markets worldwide, with a combined equivalent of over 150 million barrels purchased

and sold each day. Today, NYMEX alone handles that much.

B. Futures and Options

Today, there are two basic types of hedging instruments available: futures and

options. We describe each in more detail here. In Section VIII we explain how these

products might be used to hedge Alaska royalty and production tax revenue.

1. Futures

A futures contract is a firm commitment to deliver or to receive a specified quantity

and grade of a commodity at a specified location within a specified month.

In markets today, physical delivery usually does not occur; futures transactions are

paper transactions. All terms of the exchange-traded futures contract, except for

price, are set by the rules of the exchange where the futures are traded. These terms

include contract unit, quality specification and geographical delivery area. In petroleum

futures, the contract unit is 1,000 barrels (42,000 gallons). Only cash changes hands,

and then only the difference between the purchase or sales amounts in the futures

contracts and the market value of 1,000 barrels on the delivery date not the oil itself.

The NYMEX futures market for WTI takes place under the auspices of the NewYork Mercantile Exchange where buyers and sellers establish a price each day for

crude oil for sale or purchase for any time period in the future from one month to six


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years ahead.4 Prices fluctuate as a result of ordinary supply and demand forces based

upon market expectations for the corresponding future time periods.

NYMEX markets are supported by a strong financial system backed by members of

the Exchange. All transactions are disclosed as a critical part of price setting but the

identities of customers remain anonymous and the Exchange maintains confidentiality.

With large numbers of oil companies actively trading futures contracts, the prices

have become a standard by which to value cash market contracts. Economists point to

this market activity as a way to discover the price of a commodity. Futures prices are

unambiguous, rapidly disseminated, widely used and representative of the majority of

transactions during a given period of time. Spot prices are now so linked to their

respective near-month futures prices that the two markets function interchangeably.

A very active over-the-counter (OTC) market operated by large brokerage houses

parallels the NYMEX market. When handled on an OTC basis, transactions between

buyers and sellers occur directly and do not involve an exchange. Based on

discussions with several brokers, it appears that OTC transactions account for about 80

percent of oil traded in futures. Although OTC transactions do not involve theexchange, such transactions reflect the prices established on the NYMEX that are

visible to both buyers and sellers.

The NYMEX requires margin and brokerage fees payable on standard terms to the

Exchange. The OTC market, on the other hand, allows purchasers with sufficient credit

to negotiate lower margin requirements and customize how those requirements will be

imposed. While there are no expressed commissions, similar transaction fees are

embedded in the price of OTC contracts.5

4 In actual practice, most trading in exchange-traded futures is done in contracts closest in time to the present, withdiminishing activity the further distant the contract date. Practically speaking, relatively little trading takes place on

the exchange in futures more than a year away from expiration.5 Most firms offering OTC contracts make extensive use of various exchange-traded contracts in conjunction withtheir OTC contract. The firms may use several exchange-traded contracts as part of their r isk control strategy. In

pricing the OTC contracts, the offering firm will include the exchange fees they are likely to incur.


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Perhaps the most significant distinction between the two markets is their

organization. While NYMEX trades are standardized and market activity is transparent,

OTC markets are flexible and market activity is less immediately obvious. The state, if it

wishes to hedge large amounts of oil, would probably see an advantage in the ability to

customize transactions and to execute trades on an OTC basis discretely through one

or more brokerage houses.

2. Options

Whereas the holder of a futures contract has an obligationto perform, that is, the

holder is committed to a price in advance, an option, as the name suggests, gives its

holder a right to choosewhether or not to perform. Instead of committing in, say,

September to a price in January, the holder of an option can lock into the futures price,

but wait until January to decide if entering into the contract is a good deal.

Buyers of options pay a one-time, up-front cost, stated as a cost per unit of the

underlying commodity, in this case a barrel of oil. Because the holder of an option can

decide whether or not to go through with the deal, options function as an insurance

policy against prices moving in an unfavorable way. The one-time cost of the options

contract can therefore be thought of as an insurance premium. By paying the premium,the options buyer avoids the potential large pay-outs faced by holders of futures

contracts. The options cost is known and paid in advance, whether or not the holder

has to fall back on the policy (i.e., exercise the option), just as with any other insurance.

Note that when options are purchased as an insurance policy against unfavorable price

changes, the buyer of the option is hedging. And as with futures contracts, speculators

also buy and sell options in anticipation of market prices changing.


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There are two kinds of options: (1) a right to enter into a futures contract to sell,

referred to as a put; and (2) an option to enter into a futures contract to buy, known as

a call. Traders can buy or sell either kind of option. Just as buyers pay a premium,

sellers receive a premium. As with futures trading, speculators and money managers

can use options to manage financial positions independently of their desire or ability to

buy or sell actual barrels of oil since options contracts are usually cash-settled.

Additionally, as with futures, there are exchange-traded and OTC options markets.

The price of an option depends upon:

Strike price (the purchase or sale price of the commodity in the contract)

Price of underlying commodity (the current futures price for the specific month

the option covers)

Time to expiration

Interest rates

Volatility

The following are prices per barrel for NYMEX-traded crude oil options as reported

in the Wall Street Journal on April 13, 2001, for contracts executable in May, June, and

July 2001.

Strike Calls PutsPrice May June July May June July

27.50 0.89 1.86 2.32 0.14 0.77 1.1028.00 0.55 1.57 2.03 0.30 0.98 1.3028.50 0.30 1.30 1.76 0.55 1.21 1.5329.00 0.16 1.06 1.50 0.91 1.47 1.7729.50 0.07 0.86 1.29 1.32 1.77 2.06

30.00 0.04 0.70 1.10 1.79 2.10 2.36

On April 12, 2001, the May WTI futures price was $28.25 per barrel; June, $28.59;

and July, $28.93. The further away the strike is from the trading price, the lower the

option cost because there is less likelihood the option will be exercised. The further out


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in time, the more an option at any given strike price costs because of increased price

uncertainty and the longer period of time the option holder is protected from adverse

price movements.

C. Mean Reversion

Despite day-to-day volatility, average oil prices have remained remarkably steady

over the past 10 years. You can see this in Figure 4 on Page 29. Whereas in the past

10 years prices have ranged from under $10 per barrel to over $30, the 60-month

moving average at any point in time has been a fairly consistent $19 per barrel.

At any point in time, futures prices exhibit mean reversion; i.e., prices in contracts

for delivery many months in the future converge to the long-term expected price.


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$7

$10

$13

$16

$19

$22

$25

$28

$31

$34

Dec-90 Jun-92 Dec-93 Jun-95 Dec-96 Jun-98 Dec-99 Jun-01 Dec-02 Jun-04 Dec-05

$ / Barrel

April 2001 Futures

October 1998 Futures

Figure 4. WTI ( Actual, December 1990 - March 2001)and NYMEX Futures Oil Prices

Average Price

Average 60-Month Moving Average

ka Department of Revenue Hedging Oil Revenues - October 21, 2002 Page 2 9


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VIII. THE MECHANICS OF SPECIFIC HEDGING STRATEGIES

The state could hedge its royalty and production tax revenue because these

revenue streams are directly tied to oil prices. Because futures contracts are based on

barrels of oil, the state would need to determine the correct number of barrels to hedge

to protect this anticipated revenue. The treasury currently takes in or loses $65 million

per year for every $1 change in the price of ANS. An ideal hedge would exactly offset

that risk. That is, for every drop of $1 in the price of oil, the state would get $65 million

back from its ideal hedge. So if the state hedges 65 million barrels over a years time

(180,000 barrels per day or 5.4 million barrels per month), it could, in a perfect hedge,

recover its loss dollar for dollar. If the price drops $1, it loses $65 million on royalties

and production taxes but recovers $65 million from the hedge. If the price drops $2, it

receives $130 million from the hedge, and so on.6

Why do parties hedge? Hedging makes business planning more dependable and

reduces the risk of losses from unanticipated price swings. By making income streams

more predictable, hedging increases credit worthiness and improves financial planning.

Businesses also use hedging to reassure financial backers that price volatility wont

threaten new enterprises. Although hedging eliminates the risk of losses when pricesmove in an unfavorable direction, depending on the specific strategy, hedging can take

away the potential for greater profits when prices move in a favorable way.

It is worth noting that none of the major North Slope oil producers hedge to protect

their North Slope revenue stream. Those that hedge do so only to protect their realized

price on specific cargoes of crude oil.

6 The Department of Revenue predicts that oil price sensitivity will begin to decline in future years as large oilreservoirs are depleted and smaller fields, paying proportionately less production tax because of the Economic Limit

Factor (ELF), become a larger and larger percentage of oil production.


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When evaluating specific hedging strategies, keep in mind that futures contracts are

tied to a standard commodity. In the case of crude oil, that standard is West Texas

Intermediate (WTI). That is, the oil price that the contract is based upon is the price of

WTI. Hedging Alaska North Slope oil (ANS) revenues using WTI futures contracts

requires the hedger to rely on a relatively stable relationship between WTI and ANS

prices. In recent years, the price difference between these two has averaged $1.65 per

barrel. However, it is important to remember that from time to time this varies

significantly. 7 The risk associated with that potential variation is called basis risk. The

basis risk would be an important consideration in actual hedging operations (see

discussion in Part IV above). However, for purposes of simplifying our illustrations, we

have in this section assumed a standard price difference between ANS and WTI of

$1.65 per barrel.

Following is a detailed explanation of several possible hedging strategies using the

basic hedging instruments. In the examples we have used to describe these strategies,

we have presented the basic economic results. We have not distinguished between

exchange-traded and OTC instruments. Neither have we addressed the margin or

credit issues, which are covered in Sections X and XI. Again, remember that in these

transactions, the purchases and sales of WTI are paper only only cash changeshands for the difference between the sales prices or strike prices for WTI in the futures

or options contracts and the current market value of WTI.

A. Straight Futures

Lets say that on April 12, 2001 the state decided to contract to sell on the futures

market 180,000 barrels per day of WTI 5.4 million barrels per month for the next

two years starting in April 2001. The objective of this strategy would be to lock into the

prices available in the futures market. The prices available at the close on April 12 are

set forth in Table 1 on Page 10.

7 Since 1987 the difference between WTI and ANS has fluctuated from $1/bbl to $5.75/bbl. Since the ANS exportban was lifted in 1996, the differential has averaged about $1.65/bbl.


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To explain the mechanics we have broken the activity associated with hedging

using straight futures into three steps.

First, the state would contract to sell WTI by entering into futures contracts for

each pertinent future month at the available futures prices.

Second, each month the state would receive tax and royalty revenue from ANS

production based on the ANS market price. 8

Third, as time passed, the value of the WTI futures contracts based on each

months actual spot price would be compared to the locked-in price for that

month in the applicable futures contract. If the market price turns out to be lower

than the contracted price, the state would receive the difference from a broker. If

the market price were higher, the state would pay the difference to the broker. In

the latter case, the state would have the money to pay the broker from the higher

royalty and production tax revenue it received as a result of rising oil prices.

Example 1 displays the mechanics of hedging using straight futures by showing

what would happen if oil prices increased or decreased from the April 12, 2001 futuresprices for an exemplary month of April 2002. Notice that, by using straight futures, the

states net revenue would be the same whether prices go up or down. This example is

based on the April 12, 2001 WTI futures price for the April 2002 example month.

8 The projected royalty and production tax revenues for this and all subsequent examples are based on the following

assumptions: For royalties, one million barrels per day of gross production, 30 days in a month, one-eighth royalty,of which 25% goes tothe Permanent Fund (we are only hedging General Fund revenues), and a $4 per barreldifferential (pipeline and shipping)between market price andwellhead price, taxes and royalties being predicatedon the latter. For taxes, one million barrels per day of gross production, 30 days in a month, seven-eighths non-royalty portion, a $4 per barrel differential between market price and wellhead price, a 15% tax rate, and a weightedaverage economic limit factor (ELF) of 0.65. On net, the total monthly revenue is 18% of the market ANS price less

$4 on 30 million barrels. This is equivalent to the total revenue from 5.4 million barrels of ANS.


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EXAMPLE 1: Straight Futures

Step 1: On April 12, 2001, the state contracts to sell 180,000 barrels a day ofWTI for the next two years. On April 12, 2001 the WTI futures price for April2002 deliveries was $26 a barrel (see Table 1). Based on a $1.65 differential

to WTI, this implies a $24.35 per barrel market price for ANS. If the actualANS market prices in April 2002 are the same as the year-earlier futuresprices, the states royalty and production tax revenue would be $110 million.9

What would happen if actual prices were lower than futures prices?

Step 2: The April 2002 delivered price of WTI is $18 down $8 from the

year-earlier futures price. ANS is $16.35. The state would receive royalty andproduction tax revenue of $67 million based on the ANS price.

Step 3: The state would receive from the broker the difference between the

$26 WTI futures price and the $18 April 2002 WTI market price ($8) on 5.4million barrels for a total of $43 million. On net, the state would receive $67million in tax and royalty plus $43 million from the broker for a total of $110million, the same amount it would have received under Step 2 if the actualdelivered prices had been the same as futures prices from one year earlier.

What would happen if actual prices were higher than futures prices?

Step 2: The April 2002 delivered price of WTI is $30, up $4 from the year-earlier futures price. ANS is $28.35. The state would receive royalty andproduction tax revenue of $132 million based on the ANS price.

Step 3: The state would pay the broker the difference between the $30 WTI

market price and the $26 WTI futures price ($4) on 5.4 million barrels, for atotal of $22 million. The state would be able to pay this from its tax and royaltyrevenue from the higher oil price. On net, the state would receive the $132million in tax and royalty revenue less the $22 million to the broker for a total of$110 million. However, to get the downside protection from the lower prices,the state gives up the opportunity for revenue from higher prices.

The process above, also called a swap, is the simplest form of hedging. If the

futures price today for a particular month in the future is $25 per barrel, the state would

receive revenue as if the price were $25 regardless of the actual price in the future.

9 For this and the following examples, the states ANS royalty and production tax revenue may be estimated using

the following formula: (ANS - $4) x 18% x 30 million bbl = (ANS - $4) x 5.4 million bbl. See also Footnote 8.


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B. Straight Options

Recall that an option is a right, but not an obligation, to buy or sell at a certain time at

a given price. One of the simplest hedging strategies is to simply buy options to sellcrude oil (put options). For example, if an oil producer purchased put options, it would

be able to guarantee a minimum price for its oil. With straight futures, the hedger locks

in a price. With options, the hedger pays a fee to guarantee a minimum price, while

retaining the possibility of receiving the revenue from higher prices.

Suppose that on April 12, 2001 the state wanted to ensure a minimum price (the

strike price) each month for 180,000 barrels per day over the next two years. Again we

have broken our analysis down into three steps:

First, the state would buy put options for each of the next 24 months and pay a

per-barrel up-front fee. The higher the strike price (the guaranteed minimum)

and the longer the time to expiration, the higher the fee.

Second, each month the state would receive tax and royalty revenue from ANS

production based on the ANS market price.

Third, in any month when the WTI price fell below the strike price, the state would

exercise the option. The state would receive the difference between the higher

strike price and lower actual price. The states net proceeds would be the ANS

royalty and production tax revenue, plus the difference between the strike price

and the actual price for WTI, less the cost of the option.

In any month when the WTI price is above the strike price the state would not

exercise the option. The net proceeds would be the royalty and production revenue

(based on the higher market price), less the cost of the option.


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In summary the process would work as follows: For a put option with a strike of $20-

per-barrel, if WTI prices fell below $20 the state would receive revenue as if the WTI

price were $20 per barrel. If WTI prices were above $20, the state would receive royalty

and production tax revenue based on the actual ANS market price. In either case, the

state would pay an up-front fee for the option. Example 2 illustrates the mechanics of

hedging using the straight options strategy by showing what would happen with price

changes up or down for an exemplary month of April 2002.


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EXAMPLE 2: Straight Options

Step 1: On April 12, 2001, the state contracts to buy put options on 180,000barrels per day (5.4 million barrels per month) of WTI at $2 per barrel belowthe futures price for the next two years. On April 12, 2001, the WTI futures

price for April 2002 delivery was $26 (see Table 1), so the strike price for theoption is $24 per barrel. The average cost (premium) for the April 2002 optionis $1.72 per barrel. The state pays $223 million to purchase put options thatcover the two-year time period. The cost attributable to April 2002 is about$10 million. If the actual market prices in April 2002 were the same as theyear-earlier futures prices, the states ANS royalty and production tax revenuewould be $110 million less the $10 million cost of the unexercised options.

What would happen if actual prices were lower than futures prices?

Step 2: In April 2002 the actual delivered price of WTI is $18 down $8 from

the year earlier futures price. The price of ANS is $16.35. The state wouldreceive royalty and production tax revenue of $67 million based on the ANSprice.

Step 3: The state exercises its put option and receives from the broker thedifference between the $24 strike price and the $18 April 2002 WTI marketprice ($6) on 5.4 million barrels for a total of $32 million. The state receivesthe $67 million in tax and royalty revenue plus the $32 million from the brokerfor a total of $99 million. The state nets this amount less the approximately$10 million cost of the options for the month.

What would happen if actual prices were higher than futures prices?

Step 2: In April 2002 the price of WTI is $30, $6 above the strike price. Thestate neither receives anything from nor pays anything to the broker, butreceives tax and royalty revenue of $131 million based on the higher oil prices.The state nets this amount less, again, the approximately $10 million cost ofthe put options, although in this case the options expire unused.


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Purchasing put options to cover 180,000 barrels per day would be expensive. For

example, the $2 below the futures price strategy used in Example 2 would require a first

months premium of $1.35 per barrel and a premium of $2.07 for the last month in the

two-year period. The first years total premium would be $91 million, increasing to $132

million in the second year for a total of $223 million.

Hedging at $4 under the futures price would cost less because the state would be

insuring at a lower price. For the first year the premium would be $0.82 per barrel, and

for the second year it would be $1.36 per barrel.

As with any insurance plan, the cost will vary depending upon the likelihood of theevent the state is insuring against. A hedge at $4 below the futures curve would cost

less than one at $2 below. This is because the lower the strike price, the less likely it is

that we would exercise the option. So while a hedge far from the current futures curve

would cost less, our potential losses would be much greater before our insurance policy

began to provide protection. (This is similar to having an insurance policy with a higher

deductible.)

Options-based hedging strategies the state could implement include:

Purchase put options at strike prices at some level below the futures price for

each month. For example, we could elect to hedge at $2 below futures prices,

thus ensuring that we would at mostlose $2 per barrel (plus the cost of the

options) from what the futures market predicts we should earn, while still

maintaining full upside price potential.

Determine a minimum oil price to protect with a hedge and pay whatever the cost

of options for that strike price.

Budget the amount the state would be willing to pay for an insurance policy and

select the strike price that would exhaust this amount.


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Simply buying put options eliminates the uncertainty of costs associated with other

strategies, such as straight futures trading, or swaps, described earlier in this section.

The cost is known in advance. At the end of the hedge period, the state would be out of

pocket only the cost of the puts it had purchased.

C. Zero-Premium Collar10

Whereas an option for a fee guarantees a minimum price and provides the

possibility of unlimited upside potential, a zero-premium collar requires no up-front fee

but imposes a ceiling on the upside potential. When using a collar strategy, the hedger

pays for some or all of the options (e.g., puts) it buys by selling the opposite option (e.g.,

calls). If the hedger buys a put option, it sells a call option. When the purchase and

sale prices for those options exactly offset each other, the collar has no premium and no

exchange of money is required up-front. Although the hedger pays no up-front

premium, the strategy is not really costless since the hedger would owe money to the

broker if prices increased above the collars ceiling.

If the state employed a zero-premium collar strategy, it could avoid the out-of-pocket

cost of purchasing put options. To do so, however, the state would sacrifice some ofthe potential revenue from higher oil prices. Under this strategy, the money the state

would receive from selling a call option to set an upper limit on its oil revenue would pay

the cost of buying a put option to set a lower limit on oil revenues.

Suppose that on April 12, 2001 the state wanted to ensure revenue based on a

minimum price (the strike price of the put option) each month for the equivalent of

180,000 barrels per day over the next two years, and would be willing to sacrifice the

possibility of higher revenue to do so. The process is almost the same as that of the

10 Zero-premium collars are often referred to as costless collars since there is no up-front cost or premium. Since

such collar strategies can result in a back-end cost to the hedger, the term zero -premium collar will be used here.Note also that, while brokers receive no payment up front, the strike prices of the put and call reflect the brokersanticipated transaction fees (required for the broker to hedge its risk) and profit margin. Thus, the broker earns a fee

that is imbedded in the options prices even though the collar may have no up-front premium for the hedger.


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straight option strategy, but it has one more step: Instead of paying a fee for the put

options, the state sells a call option. The call option places a ceiling on the total

revenue the state could receive from the combination of royalties, tax and the hedge.

Here are the basic steps involved in a zero-premium collar strategy:

First, just as with the straight option strategy, the state would buy a put option,

with a strike price establishing a WTI minimum price.

Second, instead of paying an out-of-pocket charge for the put option, the state

would sell a call option. Just as one pays a fee for a put option to guarantee a

minimum sales price, one receives a fee for selling a call option to guarantee the

purchaser of that call option will pay no more than a maximum purchase price.For call options, the lower this strike price the higher the fee. For any put option

strike price with a fee establishing a sellers floor, there is a call option strike price

with an identical fee establishing a purchasers ceiling. Consequently, the state

could sell a call option guaranteeing it would sell WTI at an upside strike price for

a fee that exactly offsets the fee it must pay for the downside put option.

Therefore, in exchange for sacrificing the upside revenue potential from higher

prices, the state would receive the guaranteed minimum revenue associated with

the put strike price. These prices do not move symmetrically, however.

Third, each month the state would receive royalty and production tax revenue

from ANS production based on the ANS market price.

Fourth, in any month when the WTI price is below the strike price of the states

put option, just as with the straight option strategy, the state would exercise the

option. The state would receive an amount based on the difference between the

higher strike price and lower actual price for WTI. The states net proceeds

would be its royalty and tax revenue plus the difference between the strike price

and the actual price for WTI.


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In any month when the WTI price is between the strike price of the put option the

state purchased and the strike price of the call option it sold, none of the parties would

exercise its option, and the state would realize royalty and production tax revenue

based on the market value for ANS.

In any month when the WTI price exceeds the strike price of the call option the state

had sold, the buyer would exercise the call option and the state would remit to the

broker an amount based on the difference between the higher actual WTI market price

and the lower call strike price. The state would have funds available to make this

payment from the higher royalty and production revenue resulting from the higher oil

prices. The state, therefore, would get to keep some, but not all, of the revenue from

higher prices.

In summary, if the put option for the minimum WTI price were $16 and the call option

for the maximum WTI price were $25, the strategy would work as follows:

When the actual WTI price is below $16 per barrel, the state would realize royalty

and production tax revenue on the basis of an ANS price equivalent to WTI at$16.

When the actual WTI price is between $16 and $25 per barrel, the state would

realize royalty and production tax revenue based on the actual ANS market price.

When the actual WTI price exceeds $25 per barrel, the state would realize

royalty and production tax revenue based on ANS prices equivalent to a WTI

price of $25 per barrel.

Example 3 illustrates the mechanics of what would happen with price changes up or

down for an exemplary month of April 2002.


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EXAMPLE 3: Zero-Premium Collar

Step 1: On April 12, 2001, the state contracts to buy put options on 180,000barrels per day (5.4 million barrels per month) WTI at $2 per barrel below thefutures price for the next two years. On April 12, 2001 the price for April 2002

was $26 (see Table 1), so the strike price for the option is $24. If the actualmarket prices in April 2002 were the same as the year-earlier futures prices,the ANS royalty and production tax revenue would be $110 million.

Step 2: On April 12, 2001 the state also contracts to sell call options on180,000 barrels per day (5.4 million barrels per month) WTI for the next twoyears. The call with a premium that would offset the fees for the put optionhas a strike price of $28.10 for April 2002.

Note: If the put strike price was $4 below the futures price the state could sella call with a $30.80 strike price.

What would happen if actual prices were lower than the put strike price?

Step 3: In April 2002, the actual delivered price of WTI is $18 per barrel, $6below the strike price. The price of ANS is $16.35. The state receives royaltyand production tax revenue of $67 million based on the ANS price.

Step 4: The state receives from the broker the difference between $24 and

$18 ($6) on 5.4 million barrels, for a total of $32 million. On net, the Statewould receive the $67 million in tax and royalty revenue plus the $32 millionfrom the broker for a total of $99 million.

What would happen if actual prices fell between the put option strikeprice and the call option strike price?

Step 3: In April 2002, the price of WTI is $27, in-between the put option and

call option strike prices. The ANS price is $25.35. The state neither receivesanything from nor pays anything to the broker, but receives ANS royalty andproduction revenue of $115 million based on the increased market prices forANS.


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What would happen if actual prices exceeded the call option strikeprice?

Step 3: In April 2002 the actual delivered price of WTI is $32, $3.90 above the

call option strike price. The ANS price is $30.35. The state receives $142

million royalty and production tax revenue based on the ANS price.

Step 4: The state remits to the broker the difference between $32 and $28.10($3.90) on 5.4 million barrels for a total of $21 million. On net the statereceived the $142 million in royalty and production tax revenue less the $21million to the broker for a total of $121 million. This revenue is equivalent tothe revenue the state would receive at $26.45 ANS or $28.10 WTI, theeffective ceiling price level of the collar.

D. Other Strategies: There are myriad other, more complex hedging strategies that

employ combinations of futures and options.


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IX. Over-the-Counter and Exchange Markets

Throughout the paper we have made reference to hedging instruments traded on

exchanges and in over-the-counter (OTC) markets. These instruments are essentiallythe same, but there are important differences that would affect the implementation of

any state hedging program. The two markets differ in four areas: transparency,

flexibility, financial issues and legal issues.

The first important difference between OTC and exchange-based markets is

transparency. Trades on an exchange are immediately obvious to market participants.

We have all seen the pictures of a stock market or commodity market where hundreds

of people buy and sell face toface, calling out and frantically waving their arms while an

overhead scoreboard displays the latest price. In this environment everyone knows

who is in the market and what trades they are making, and the current price reflects that

information. In contrast to exchange trading, OTC transactions are privately negotiated.

However, initial pricing and settlements of OTC instruments are based on exchange

prices since they are observable. Because OTC transactions are not publicly observed,

a market participant is able to execute large-volume trades discretely, thereby reducing

the potential for an adverse movement of price that undermines the participants own

position. The volumes discussed in this paper would be large enough to have such an

effect on price, perhaps as much as $0.30 to $0.40 per barrel. The exchange-traded

market has great transparency that is critical to good price discovery, but the privacy of

the OTC market has an advantage for execution of large orders.

The second major difference between the markets is flexibility. The contracts traded

on formal exchanges such as NYMEX offer standardized terms. In the case of NYMEX

WTI futures contracts, oil is traded in units of 1,000 barrels of WTI, delivered at

Cushing, Oklahoma, in a month specified in the contract. The contracts clearly set out

the terms and conditions as well as the legal and financial responsibilities of the contract

holder. This standardization reduces the administrative burden and allows parties to act

quickly, because everything in the contract except the price is already set. The


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exchange guaranties the contract, and parties of the contract can remain anonymous to

each other. OTC market contracts are private agreements drawn up between two

parties and, as such, can be customized to meet the individual needs of market

participants. The flexibility of the OTC market could be important to an Alaska hedging

program. Should the state seek to achieve the average oil price for a given month, for

example, using exchange based futures contracts, it would need to settle contracts daily

throughout the month to receive the monthly average price. The terms of an OTC

contract, on the other hand, could be explicitly based on the monthly average price,

simplifying program management. In addition, an OTC contract could be written to

average the price over several months, or to settle less frequently, further reducing

overhead costs.

The third difference is in the financial or cash management implications of the two

markets. Exchange traded contracts are guaranteed by the exchange. This guaranty is

backed by the combined financial strength of the exchange members and, more

importantly, by strict margin requirements. The margin requirements are a standardized

part of all exchange-traded contracts. As discussed earlier, margin calls for exchange

based trades can be considerable, and would require the state to come up with large

amounts of money potentially hundreds of millions of dollars immediately upon theupward movement of the price of oil. By contrast, there is no third party to guaranty an

OTC contract. As we will discuss in Section X on credit, the state would be exposed to

the potential default of the counter-party in an OTC contract just as the counter-party

would be exposed to the state. The state would want to provide some measure of

protection by having something like a margin requirement. Similarly, the counter-party

would also want some protection against credit risk; the flexibility of OTC trades allows

the parties to craft mutually agreeable terms for that protection.

Finally, hedging with OTC contracts would require more legal work than hedging

with exchange-based instruments. As noted previously, exchange-traded contracts are

completely standardized with no flexibility. As such, little up-front legal work on the

contracts is required and no specific protections can be incorporated into the contracts.


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With OTC contracts a substantial amount of up-front legal work is required before a

hedge could be put in place. Terms and conditions can be customized to meet specific

legal requirements, but these would have to be negotiated with the counter-party. For a

program of the size and possible complexity of the states, negotiations could take

months and could limit the number of possible counter-parties.


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X. CREDIT RISK

Some hedging strategies in OTC markets, notably straight futures trading and zero-

premium collars, may result in large obligations when contracts come due. Dependingupon the amount hedged, and the difference between the contract price and the actual

price of oil at that time, one party could find itself owing large sums to the other. In that

case, the receiving party runs the risk that the party that owes could not pay its debt.

Given the amounts we have discussed as possible in this paper, those obligations could

amount to hundreds of millions of dollars. In all but the most unlikely circumstances,

such as a sudden and unexpected shutdown of Alaska oil production, the state would

face no financial threat from having to make such a large payment, because the high oil

prices that would cause us to pay would also increase state revenues.

Market participants, in light of the recent Enron financial failure, more than ever do

not want to be exposed to large potential losses as a result of the counterparty in an

energy contract not paying. Additionally, as a result of the bankruptcy filing by Enron,

some contracts have been selectively voided in that bankruptcy. This has resulted in

changes in the general level of collateralization required by some firms involved in

energy trading.

Although it may seem unlikely that a large brokerage would default on the debt, it is

not inconceivable.11 There was concern that the Enron bankruptcy could cause other

energy trading firms or brokers to fail. Similarly, financial institutions might be reluctant

to face a large credit risk from a government. Both the broker and the state would likely

impose limits on the amount of potential losses they would expose themselves to. As

market prices fluctuate and give rise to potentially large payments at the expiration of a

contract, the receiving party would require that potential payments in excess of those

credit limits be paid in advance. As with an escrow account, that money would generate

interest for the payer but the principal would serve as a bond to guarantee payment.

11 Spreading the business between several houses would reduce credit risk, but that tactic raises other questions

about strategy and timing in the OTC market.


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Posting such a bond in advance of actually receiving the revenues may pose difficulties

for financial management if the CBRF is no longer available.

In addition, both parties could have trouble dealing with negative public perceptions

when the state pays that much money to private financiers. Ironically, a broker might

actually prefer to pay the state rather than face the negative publicity of receiving

payment from the st

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