'In-kind' or 'in-value'? State may take gas instead of money.

When Alaskans finally get a chance to look at the gas pipeline deal Gov. Frank Murkowski has negotiated with the North Slope producers, they will have to weigh some fundamental questions regarding the state's potential involvement in the pipeline.

The basic question is whether the state should become a more involved partner in the project by investing in and owning part of the pipeline and taking its royalty and tax share of revenues "in kind," or in the form of gas.

While there are big profits that can be earned under these arrangements, there are also big risks. The alternative is to continue with the state's passive relationship with the industry, as a landowner receiving royalty payments and a sovereign government levying taxes. There also are risks in continuing with the status quo, however. If there is a downturn in markets, state revenues are directly affected. Owing a part of the project is seen as a way to partly mitigate this risk.

There are two major parts of the state's involvement in the gas project that will be the core of the deal, along with an agreement to keep taxes at current levels.

The first big step will be the state taking of its royalty gas and even its taxes "in-kind," or in the form of gas. This is a cornerstone of the plan for the state's involvement in the project, and one that is even more important than Alaska owning 20 percent of the pipeline.

The idea is for the state to take its one-eighth royalty share of gas and its production tax in-kind, or in the form of gas. Instead of being paid for royalty gas by the producers or taxes being paid, the state would take gas, including Natural Gas Liquids (NGLs)--like propane, butane and ethane--and market the gas and NGLs itself.

This isn't as unusual as it may sound. Alaska's oil and gas leases have always given the state the option of taking its royalty "in-value" (in money) or "in-kind" (in the form of oil or gas). Over the years, the state has always taken some of its royalty oil in value and some in-kind. The royalty in-value payment by the producers is a used as a value benchmark in the in-kind sales the state does because the producers' own sales of royalty oil is a test of what the market price actually is. Most of the state's royalty-in-kind oil has been sold to Alaska refiners. In recent years, the refiners have paid the state a premium on top of the "in-value" price reported by the producers for royalty oil they sold.

IN-KIND FOR LIFE?

In the case of the gas pipeline, however, the state would take all of its royalty share as wells as its production tax "share" in-kind for the life of the project. There would be no switching back and forth between in-value and in-kind. This is a critical part of the deal for the producers because the ability of the state to switch back and forth on its gas royalty under the current lease creates a serious problem for the companies. In their own planning for the capacity of the portions of the pipeline they would finance, under the current system they can never be certain whether they will be responsible for transporting and selling the royalty or not. Although there may be solutions for this, the easiest and simplest is for the state to make a decision one way or the other (in-value or in-kind) and to stick with it for the life of the project. In the pending deal, the state has opted to take the gas in-kind.

Taking the gas in-kind solves another important problem for the producers. If gas is taken in-value, with the royalty paid in cash by the producers, the state must constantly audit the sales transactions to insure the royalty is being properly reported. There is potential for big disputes over these, which the industry, and the state as well, would rather avoid if possible. In the years following completion of the oil pipeline in 1977, the state and producers were locked in complex lawsuits in which hundreds of millions of dollars were spent in legal fees. A simple way to avoid this is to have the state take responsibility for marketing its royalty and tax gas so there is no need for audits of the industry. For many of the same reasons, the U.S. Minerals Management Services takes federal royalty in-kind from U.S. Gulf of Mexico outer-continental shelf production, and the arrangement is said to work well.

STATE MUST MARKET ITS GAS

Having decided this to take royalty in-kind, the state also would be responsible for marketing its gas and for making arrangements to transport the royalty gas through the pipeline. To make those transportation arrangements, the state, like any other gas owner, must contract with one of the owners of the pipeline to purchase capacity, or space. This would be a "take-or-pay" contract, meaning the state would be firmly committed to pay for its space in the pipeline. Capacity contracts for the pipeline are concluded after an "open season" is announced by the pipeline owners. This occurs just as the project owners are beginning the design and engineering, and the supply commitments are needed so the owners can design the pipeline for the amount of gas committed and then go to financial markets to raise money for construction. To raise money, the owners must have firm contracts to ship gas.

STATE TAKES PARTIAL OWNERSHIP

The state also will consider separately becoming a part owner in the pipeline, probably taking a share equal to its in-kind gas so that the state, as a pipeline owner, ships its own gas and earns profits from the transportation instead of having one of the private pipeline owners ship the state's gas and earn the profits.

This kind of relationship between a producer and pipeline ownership is fairly common and can be seen with the trans-Alaska oil pipeline system, where the private oil producers have pipeline subsidiaries that own a portion of the oil pipeline usually similar to the amount of oil they own and ship.

This not only makes sense financially--the companies make profits on the shipping of their own oil, but it is also an important risk-protection strategy. By owning some of the pipeline, the producers protect themselves to some extent during downturns in oil markets.

When oil prices dip, the producer suffers reduced production profits, and sometimes even losses if the price dip is severe, but the effect is mitigated by continued profits from the pipeline investment as long as oil continues to be shipped. In 1998, oil prices slumped to less than $9 per barrel and some smaller North Slope fields actually operated in the red for a short period (prices gradually rebounded by mid-1999, (but the producers made enough profit from transporting the oil to mitigate the production losses).

The state's goal in owning part of the pipeline and shipping its own gas is similar. If Alaska is totally dependent on "upstream" revenues by selling its royalty gas either in-value or in-kind, it faces the risk of lower revenues if natural gas prices dip. If gas prices dip to the cost of transporting the gas through the pipeline, or even below, the state's revenues would be zero. But if the state owns part of the pipeline, it will continue to make profits on pipeline transportation by shipping either royalty gas or gas for other producers, and thereby mitigate some of the market risk.

OTHER OPTIONS

However, the decisions to invest in the pipeline and to take gas in-kind are not dependent on each other. The state could still take gas in-kind even if it did not own some of the pipeline, and it could also be a pipeline owner if it did not take gas in-kind. In this case the state would just ship gas for others.

There are other risks the state is exposed to, however. Interestingly, there is less risk in pipeline ownership because the risk is somewhat mitigated by Federal Energy Regulatory Commission rules that guarantee pipeline owners a certain level of profit on their investment. This guaranteed profit shields the state, to some extent, from the risk of cost overruns because the rate of return will be applied to whatever the capital cost ultimately winds up to be. The FERC guarantee, however, doesn't protect the pipeline investor from failure of the entire enterprise, for example if some catastrophic event were to damage the pipeline or a failure in the oil and gas fields were to prevent gas from being produced on the North Slope.

However, these risks will be faced by the state in any event, as they will by the producers. If the gas pipeline is damaged or gas fields fail to produce, the state's revenue stream will be severely disrupted whether the state takes in royalty in-kind or not. Risks like these are faced today, too. If there were some catastrophic failure in the oil fields, the state would experience extremely serious financial disruptions.

There is a more serious risk faced by the state in the royalty-in-kind decision, however. When the state takes responsibility for marketing its own gas, there is a risk that it may not do as well financially compared with what the producers, all large companies, could do if the state were to take its royalty in-value and the producers were given the responsibility for transporting and selling the state's royalty gas.

The question is whether the state could ever do as well in marketing gas as large companies like BP, ConocoPhillips or ExxonMobil, all in which maintain large, experienced gas marketing organizations and have deep contacts and relationships in the market. If the state enters into this arrangement, it could control up to 800 million cubic feet of royalty and tax gas per day, making Alaska one of the largest single gas suppliers in North America.

Obviously, the state would contract the actual marketing of its gas to an experienced firm much like the large stock and real estate portfolios of the Alaska Permanent Fund that is managed by agents under contract. But is it really possible that a contracted firm could do as well as the three large producers? If Alaska were not to do royalty-in-kind but were to take its gas in-value the state would automatically get the benefit of the marketing acumen of the big producers because the in-value price would reflect the sales price. In fact, the state could do even better because current law allows the state, when the state is paid for royalty in-value from multiple producers, to receive the "higher of" the several prices. For example, if in any month ExxonMobil gets a better price for its gas than BP or ConocoPhillips, the royalty payment BP and ConocoPhillips makes is based on the ExxonMobil sales price.

In judging the potential risk under this arrangement, what the state must weigh it against are the potential profits from owning a part of the pipeline and transporting the royalty gas itself.

While there are many other issues in the complex gas deal, the questions of royalty-in-kind and pipeline ownership are two of the biggest. They deserve an intensive examination by Alaskans.

Mike Bradner is publisher of the Alaska Economic Report and Alaska Legislative Digest, and is a former state legislator and Speaker of the House.