Source: https://fr.scribd.com/document/56605778/Hedging-Oil-Revenue-Www-Dor-alaska
Timestamp: 2020-01-29 10:48:38
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Matched Legal Cases: ['§ 404', '§ 330', '§ 404', '§ 32', '§ 1', '§ 4', '§ 6', '§ 3', '§ 7', '§330', '§ 1']

Hedging Oil Revenue - Www. Dor.alaska | Futures Contract | Hedge (Finance)
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?
Wilson L. Condon, Commissioner October 21, 2002
Although farmers settled in Alaska long before oil was discovered at Prudhoe Bay, Alaska’s 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 don’t have a large savings account to cushion against bad years. That’s 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. It’s 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 opportunity
to 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 Alaska’s $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.
Alaska Department of Revenue – Hedging Oil Revenues - October 21, 2002
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, we’ve been draining the account to cover a structural gap in Alaska’s finances. As North Slope oil production declines, taking state revenues down with it, we’re spending more than we take in each year and we’re 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 Alaska’s 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, that’s 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 meeting Alaskans’ 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 a nd 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, it’s a reasonable place to start. But what if oil averaged just $10 a barrel one year. The sta te 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?
Without the CBRF to cover our fluctuating reve nues, 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 children’s 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 wo uld 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.
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 wouldn’t 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 isn’t 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 a reasonable 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.
What follows is a more detailed analysis of hedging and how it would work:
Section II is a general description of the state’s hedging opportunity.
Section III explores the benefits of hedging the state’s oil royalty and production tax revenue.
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 Revenue’s 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.
II. HOW WOULD HEDGING WORK?
The Department of Revenue expects that receipts from oil royalties and production taxes will provide two -thirds of the state’s 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 state’s 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 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 actual market 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” usually refers to a contract with standard terms for the future delivery of a commodity sponsored by an organize d exchange. The term “forwards” usually refers to a contract with negotiated terms for the future delivery of a commodity sold in the over-the-counter (OTC) market. See Section IX of this paper for a summary of the important differences between “futures” and “forwards.”
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 state’s ANS revenues:
1. The likely relationship between ANS and WTI prices.
2. The current prices for future deliveries of WTI.
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 $1.65 per barrel, the average WTI-ANS differential, from the monthly WTI futures prices. By entering into futures contracts for the sale of WTI at the prices set forth in Table 1, or by purchasing options to sell WTI at prices approximating those reflected in Table 1, the state could either set or put a floor under its royalty and production tax revenue at levels consistent with the ANS prices reflected in the table, subject to something called “basis risk” discussed in Section IV.
Figure 1 on Page 9 reflects the December 1990 through March 2001 monthly ANS spot prices for the West Coast deliveries, along with the equivalent ANS futures prices from Table 1 for May 2001 through December 2007.
Figure 1. ANS West Coast ( Actual, December 1990 - March 2001) and ANS-Adjusted Futures Market Prices
April 2001 Futures
Dec- Jun-
ANS-WC
60-Mon Moving Average
TABLE 1 NYMEX CLOSING PRICES FOR WTI AND EQUIVALENT ANS WEST COAST PRICE APRIL 12, 2001
Closing WTI Futures Price ($/bbl)
Equivalent ANS Futures (WTI Minus $1.65) ($/bbl)
$26.03 2
2 We use $26.00 exactly in examples later in this paper.
III. WHY WOULD THE STATE WANT TO HEDGE?
The contrast reflected in Figure 1 on Page 9 between ups and downs of the past decade’s 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 state’s 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 in demand 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 state’s 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.
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 state’s 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 state’s royalty and production tax revenue and the likely dependence of the state upon that 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.
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 state’s 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 state’s 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, the transaction 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 state’s 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 contract’s buyer. If, for example, WTI futures prices on average increased by $5 per
barrel, the increased margin requirement for such a price change o n 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 state’s 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 wouldn’t 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.
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.
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 program’s 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 futures contracts.
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.
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 state’s 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.
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 b ut 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 state’s economy.
If it looks as though the state is likely to completely spend its CBRF and the accumulated balance in the Permanent Fund’s 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.
Here’s 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
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).
WTI Actual Price and Weekly (Monthly Quote) 36-Month Forward NYMEX Futures Price from 36 Months Earlier
Actual WTI Price
WTI 36-Month Forward Futures Price
from 36 Months Earlier
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.
Figure 3. WTI Actual Price and Weekly (Monthly Quote) NYMEX Futures Price for Delivery in 12 Months and Delivery in 36 Months
WTI Futures for Delivery in 12 Months
WTI Futures for Delivery in 36 Months
VII. THE MARKETS
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 contracts for 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 in response 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 OPEC’s 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 Cotton Exchange failed due to problems standardizing quality of the underlying product. A contract in No. 6 residential fuel oil 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.
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.
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.
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 New York 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
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 the exchange, 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, with diminishing 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 with their 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.
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.
Whereas the holder of a futures contract has an obligation to perform, that is, the holder is committed to a price in advance, an option, as the name suggests, gives its holder a right to choose whether 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.
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)
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
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 exe rcised. The further out
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 vola tility, 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.
Figure 4. WTI ( Actual, December 1990 - March 2001) and NYMEX Futures Oil Prices
Average 60-Month Moving Average
October 1998 Futures
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 o f 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 year’s 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 won’t threaten new enterprises. Although hedging eliminates the risk of losses when prices move 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 oil reservoirs 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.
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 changes hands 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
Let’s 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 export ban was lifted in 1996, the differential has averaged about $1.65/bbl.
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 month’s 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 futures prices for an exemplary month of April 2002. Notice that, by using straight futures, the state’s 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 to the Permanent Fund (we are only hedging General Fund revenues), and a $4 per barrel differential (pipeline and shipping) between market price and wellhead price, taxes and royalties being predicated on 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 weighted average 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.
EXAMPLE 1: Straight Futures
Step 1: On April 12, 2001, the state contracts to sell 180,000 barrels a day of WTI for the next two years. On April 12, 2001 the WTI futures price for April 2002 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 actual ANS market prices in April 2002 are the same as the year-earlier futures prices, the state’s 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 and production 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 5.4 million barrels for a total of $43 million. On net, the state would receive $67 million in tax and royalty plus $43 million from the broker for a total of $110 million, the same amount it would have received under Step 2 if the actual delivered 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 and production 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 a total of $22 million. The state would be able to pay this from its tax and royalty revenue from the higher oil price. On net, the state would receive the $132 million 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 state’s 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.
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 sell crude 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 state’s 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.
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.
EXAMPLE 2: Straight Options
Step 1: On April 12, 2001, the state contracts to buy put options on 180,000 barrels per day (5.4 million barrels per month) of WTI at $2 per barrel below the futures price for the ne xt two years. On April 12, 2001, the WTI futures price for April 2002 delivery was $26 (see Table 1), so the strike price for the option is $24 per barrel. The average cost (premium) for the April 2002 option is $1.72 per barrel. The state pays $223 million to purchase put options that cover 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 the year-earlier futures prices, the state’s ANS royalty and production tax revenue would be $110 million less the $10 million cost of the unexercised options.
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 would receive royalty and production tax revenue of $67 million based on the ANS price.
Step 3: The state exercises its put option and receives from the broker the difference between the $24 strike price and the $18 April 2002 WTI market price ($6) on 5.4 million barrels for a total of $32 million. The state receives the $67 million in tax and royalty revenue plus the $32 million from the broker for a total of $99 million. The state nets this amount less the approximately $10 million cost of the options for the month.
Step 2: In April 2002 the price of WTI is $30, $6 above the strike price. The state neither receives anything from nor pays anything to the broker, but receives 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 of the put options, although in this case the options expire unused.
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 month’s premium of $1.35 per barrel and a premium of $2.07 for the last month i n the two-year period. The first year’s 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 the event 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 wo uld 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 most lose $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.
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 Collar 10
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 collar’s 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, ho wever, the state would sacrifice some of the 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 broker’s anticipated 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.
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 seller’s floor, there is a call option strike price with an identical fee establishing a purchaser’s 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 state’s 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 state’s net proceeds would be its royalty and tax revenue plus the difference between the strike price and the actual price for WTI.
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
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.
EXAMPLE 3: Zero-Premium Collar
Step 1: On April 12, 2001, the state contracts to buy put options on 180,000 barrels per day (5.4 million barrels per month) WTI at $2 per barrel below the futures 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 actual market 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 on 180,000 barrels per day (5.4 million barrels per month) WTI for the next two years. The call with a premium that would offset the fees for the put option has a strike price of $28.10 for April 2002.
Note: If the put strike price was $4 below the futures price the state could sell a 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, $6 below the strike price. The price of ANS is $16.35. The state receives royalty and 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 State would receive the $67 million in tax and royalty revenue plus the $32 million from the broker for a total of $99 million.
What would happen if actual prices fell between the put option strike price and the call option strike price?
Step 3: In April 2002, the price of WTI is $27, in-between the p ut option and call option strike prices. The ANS price is $25.35. The state neither receives anything from nor pays anything to the broker, but receives ANS royalty and production revenue of $115 million based on the increased market prices for ANS.
What would happen if actual prices exceeded the call option strike price?
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 state received the $142 million in royalty and production tax revenue less the $21 million to the broker for a total of $121 million. This revenue is equivalent to the revenue the state would receive at $26.45 ANS or $28.10 WTI, the effective ceiling price level of the collar.
D. Other Strategies: There are myriad other, more complex hedging strategies that
employ combinations of futures and options.
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 essentially the 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 to face, 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 participant’s 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
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 the upward 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.
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 state’s, negotiations could take months and could limit the number of possible counter-parties.
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. Depending upon 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.
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 state. Soon after buying the futures contracts from the state on an OTC basis, a broker would most likely hedge its risk through any number of transactions, thereby letting other market participants shoulder the risk. The broker would make its money as a true middleman. 12 Thus, when the contracts expire, should the broker owe money to the state, it would actually only be funneling money from other parties. Similarly, should the state have to pay, the broker would not get to keep any of the money (since it effectively gave up its final claim to the money when hedging its own risk), but it would suffer all the negative publicity when the check is handed over.
Credit risk is not an issue in NYMEX transactions because the exchange requires participants to pay money up front, called margin requirements, to cover potential losses. As with credit limit arrangements in OTC markets, this amount can increase as contract market fluctuations cause potential payments to the exchange to grow larger. As with OTC credit, while the state would ultimately have the money to meet its contract obligations because of higher oil revenues, large margin requirements may pose a problem for cash and asset management in the short run.
12 Brokerages would make money on arbitrage (the difference in prices of the same commodity in different markets) and possibly on market timing (having the price change favorably during the time they hold the contracts). In addition, transaction fees are embedded in the prices bid by the party seeking to buy contracts, or offered by parties seeking to sell contracts on the OTC market. In other words, OTC traders attempt to gain the money that NYMEX traders earn in brokerage fees by including it in their bid or offer.
Businesses and investors hedge to reduce volatility. The markets that make hedging possible also accommodate speculators who use the same instruments in an effort to make money. Some of these speculators make money but many do not. Business and entities like the State of Alaska should not hedge to make money. Rather, policy makers should only look upon hedging as a post-CBRF option to stabilize the state budget and, by implication, the state economy.
Right now, the state manages oil price volatility by relying upon the Constitutional Budget Reserve Fund to provide a buffer between a volatile revenue stream and a stable expenditure budget. The CBRF has worked extremely well so far to smooth out the bumpy path of oil prices. And unlike a hedging program that will likely cost money, the CBRF does not cost the state anything. In fact, the CBRF actually makes money. If we keep $2 billion in the fund, we can expect to earn $100 million or more annually. We would be foolish to not preserve the CBRF for the long run as our best insurance policy against sudden economic shock caused by low oil prices.
However, if the state is going to exhaust the CBRF prior to implementing a long-term fiscal plan, and especially if use of the earnings reserve of the Permanent Fund is restricted by the proposed constitutional amendment, hedging is something the state must seriously consider.
In the more immediate future, hedging would improve our ability to forecast when the CBRF will run out. Should the state enter into a hedging program solely for that purpose? Our judgment is no. The certainty of the CBRF exhaustion date is not worth the cost. Once the CBRF is gone, however, a hedging program becomes necessary, particularly if the Permanent Fund Earnings Reserve is not available.
§ 404.0245. Crude Oil and Natural Gas Futures Contracts
(a) In this section, "hedging" means the buying and selling of crude oil and natural gas commodity futures or options
on crude oil and natural gas commodity futures as a protection against loss due to price fluctuations. Hedging at all times shall comply with Commodity Futures Trading Commission regulations.
(b) Subject to the limitations of Subsection (c), the comptroller may determine and designate the amount of state
funds that shall be invested by the comptroller in hedging transactions in crude oil and natural gas futures contracts and options on crude oil and natural gas futures contracts that are traded on an established exchange regulated by the Securities and Exchange Commission or the Commodity Futures Trading Commission.
(c) The principal amount of state funds invested and outstanding in hedging transactions on any one day may not
exceed $500,000 with a maximum risk of loss of $5,000,000 in a biennium. The total principal amount of state funds
that may be invested by the comptroller in hedging transactions during any one biennium may not exceed the amount of money credited to the unclaimed money fund for that biennium and attributable to the remittance of mineral proceeds under Chapter 75, Property Code. Any premium incurred in connection with hedging transactions may be paid only from funds appropriated for that purpose.
(d) The comptroller shall invest state funds in crude oil and natural gas futures contracts or options on crude oil and
natural gas futures contracts under the restrictions and procedures for making investments that persons of ordinary prudence, discretion, and intelligence, exercising the judgment and care under the circumstances then prevailing,
would follow in the management of their own affairs, not in regard to speculation but in regard to the permanent disposition of their funds, considering the probable income as well as the probable safety of their capital. The investments may be made only for hedging purposes.
(e), (f) Repealed by Acts 1995, 74th Leg., ch. 426, § 32, eff. June 9, 1995.
Added by Acts 1991, 72nd Leg., ch. 871, § 1, eff. June 16, 1991. Amended by Acts 1993, 73rd Leg., ch. 939, § 4, eff. Aug. 30, 1993; Acts 1995, 74th Leg., ch. 426, §§ 6, 32, eff. June 9, 1995; Acts 1997, 75th Leg., ch. 891, § 3.09, eff. Sept. 1, 1997; Acts 1997, 75th Leg., ch. 1423, § 7.33, eff. Sept. 1, 1997.
RS 49:330
§330. Mineral revenue contracts by state treasurer
A. The state treasurer, on behalf of the state, shall contract with respect to contracts commonly known as commodity
or other swap agreements, forward payment conversion agreements, futures, or contracts providing for payments based on levels of or changes in commodity prices, contracts to exchange cash flows or a series of payments or contracts, including without limitation options, puts, or calls to hedge payment, rate, spread, or similar exposure and other devices in order to establish a firm price for all or part of the anticipated mineral production subject to state severance tax and royalty contract, subject to, and in accordance with, the following limitations, restrictions, and procedure:
Such action has been recommended by the Revenue Estimating Conference to the Joint Legislative Committee on the Budget.
The recommendation of the Revenue Estimating Conference has been reviewed by the Joint Legislative Committee on the Budget and the committee has recommended the state treasurer enter into such contracts based on criteria established by the committee which may direct that a portion of any revenue gain associated with a contract be set aside or used to purchase risk protection to cover any risk associated with the contract.
All swap agreements, forward conversion agreements, future contract, or other contract authorized in this Section have been selected by the state treasurer through a request for proposal or bid process and any swap bank selected is at least "AA" rated according to industry standards.
The proposed contract has been submitted for review and comment to the attorney general who for the purposes of this Section shall be considered and shall act as legal counsel for the Joint Legislative Committee on the Budget.
The Joint Legislative Committee on the Budget may require that appropriate insurance is purchased to ensure
C. In no event shall any contract authorized pursuant to this Section be for a period longer than one year, whether
calendar or fiscal.
Acts 1999, No. 817,§ 1.
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