Claim: Risk of unsuccessful open season
Response: State is also focused on long-term economic Interests

Claim: Rolled-in pricing forces initial shippers to “subsidize” expansion costs
Response: Initial shippers benefit from expansions and expansion shippers pay their share

Claim: Reserves to make pipeline expansions economic have not been found yet
Response: Geologists agree that North Slope is awash in gas pockets

Claim: FERC allowed to mandate pipeline expansion
Response: Federal law does not guarantee exploration incentives

Claim: No guarantee that gas prices will be adequate to produce a profit
Response: The oil and gas business is risky

Claim: Holding pipeline capacity through long-term contracts harms customers balance sheet
Response: Firm Transportation commitments are not reflected onbalance sheets and can improve company financial position when noted

Claim: AGIA's rolled-in rate provisions for expansions are not in the state's interest
Response: The state will benefit from rolled in rates

CLAIM: Anything that increases risk of an unsuccessful open season such as the requirement for the pipeline company to file for rolled-in pricing for expansions should be eliminated from AGIA.

RESPONSE: While all parties obviously share the goal of an open season that attracts sufficient commitments to support the pipeline project, the state must be equally focused upon a pipeline system that will be managed to support the state's long-term economic interests.

To achieve this latter goal, the licensee must agree to expand the pipeline when demand requires and must agree to use rolled-in pricing for expansions, so long as the rolled prices do not cause a rate increase to existing shippers of more than 15%. These are among the AGIA “must haves.”

AGIA critics also routinely misunderstand another important point: Because the AGIA licensee must commit to obtaining a FERC or RCA certificate (as appropriate for the particular project), one unsuccessful open season is NOT fatal to the project. Pipeline companies often conduct two, three, sometime even more open seasons before a project is finally proposed to the FERC. Multiple open seasons may be required for a number of reasons, such as to accommodate more shippers than originally planned, to downsize a project or simply to allow more time to allow market demand to build to match gas supply to pipeline capacity. AGIA contains inducements to increase the prospects for a successful open season. But even if the inducements are not taken, AGIA keeps the process going so that success is eventually secured.

AGIA's provisions are essential to the state's long-term interest. They balance the state's long-term need for a robust gas-based economy with concerns for the risks that the first shippers will face when they bid for or contract for capacity on the pipeline.

CLAIM: Rolled-in pricing amounts to nothing but forcing existing shippers to “subsidize” the costs of expansion by other companies.

RESPONSE: The short answer is that this is not the case. At the outset it must be recognized that the value of federal and state government contributions to the project (loan guarantees, accelerated depreciation, federal income tax credits for the GTP and the AGIA grant) result in the initial rates for the project being reduced to a level that is below what they would have been without these governmental contributions or “subsidies.” The value of these subsidies is more than 15% of the projected initial rates.

AGIA requires the licensee to commit to file for rolled-in treatment, but only to the extent that existing rates are increased by the 15% that reflects governmental contributions to the project.

Thus, AGIA reflects a balancing of interests between the need of original shippers to have some certainty in the rates they will be required to pay and the need of explorer companies to have assurance as to how expansion capacity to serve their needs will be priced. AGIA does not require unlimited roll-in-only up to 15%. This caps the exposure of original shippers. To the extent that the licensee seeks to roll-in expansion costs beyond the 15%, the shippers (who will be the parties who receive the tax certainty and royalty relief contained in AGIA) are free to protest and oppose the roll-in above 15%.

At the end of the day, however, the FERC will decide how the costs of expansion are recovered; whether on an incremental or a rolled-in basis. AGIA does not intrude on FERC's exclusive jurisdiction to decide such matters. AGIA merely sets out the obligation that the licensee file for and support rolled-in rates to the extent discussed above.

The claim that rolled-in pricing for expansion capacity would amount to a subsidy by initial shippers for expansion shippers has already been made to the FERC and rejected by that agency.

FERC promulgated its orders pursuant to the mandate of Congress in ANGPA that its regulations must “promote competition in the exploration, development and production of Alaska natural gas.” (ANGPA § 103(3)(2)(b)). Accordingly, FERC was mindful of the impact that its policies on the pricing of expansion capacity would have on development of Alaska's gas resources. As a result, FERC adopted a rebuttable presumption in favor of pricing expansions using rolled-in pricing because it concluded that, “incremental pricing of expansions . . . could discourage exploration, development and production of Alaska natural gas”-which would be contrary to the Congressional mandate. (See, Order No. 2005 at P 123).

While it is current FERC policy in the lower-48 to require new facilities to be priced on an incremental basis, in Order No. 2005-A FERC stated:

Current policy [in the Lower-48] primarily considers whether the expansion project will result in a rate higher than the existing transportation rate for existing customers. An alternative consideration or definition of subsidization could be whether the expansion rate is no higher than the actual initial rate or of an initial rate without built in subsidies. (Order No. 2005-A at P 49).

The reference to “built in subsidies” relates to the facts noted above that initial shippers are benefiting from substantial subsidies through the federal government's $18 billion loan guarantee and allowance for the use of 7-year accelerated depreciation of an Alaskan gas pipeline. (See, Order No. 2005 at P 113).

According to the FERC, “Whether a rolled-in expansion rate that is higher than original rates is a 'subsidy' is a question that would have to be reviewed in the context of a future NGA section 7 filing. At that time … arguments relating to whether the federal government's loan guarantees and accelerated depreciation amount to a subsidy of initial shippers' rates may be raised.” (Order No. 2005 at P 124).

FERC has stated that in determining whether to require rolled-in or incremental pricing for expansions:

The Commission intends to harmonize both … rate predictability for initial shippers and reduction of barriers to future exploration and production … in designing rates for expansions of any Alaska natural gas transportation project. It is consistent with our guiding principle that competition favors all of the Commission's customers, as well as with the objectives of [ANGPA] to adopt rolled-in rate treatment up to the point that it would cause there to be a subsidy of expansion shippers by initial shippers, if any subsidy were to be found. (Order No. 2005 at P 125, emphasis added).

Under the FERC's analysis, there could be no impermissible “subsidy” of expansion shippers until the initial shippers' rates were increased first to the level of the initial rates to which the initial shippers agreed (and which assumes one or more interim expansions have resulted in rate decreases) and then increased to a level above the value of the original governmental subsidy (which is roughly 15%).

Thus, requiring rolled-in pricing to be used for expansions, even though doing so will raise existing rates by 15 percent, reflects FERC's analysis of the issues and places existing shippers where they would have been at the outset without governmental contributions to the project. Importantly, AGIA's level of rolled-in treatment allows a second, or perhaps even a third, generation of shippers (expansion shippers) to share in some of the benefits of those governmental contributions which would otherwise be available only to the original shippers.

Rolled-in pricing of expansions is absolutely critical to explorers. While some expansion of the line may result in rate reductions to all shippers, at some point, more expensive expansion will result in rate increases. It is at that point that the state reaches a critical fork in the road. If incremental pricing is required for an expansion, that expansion will almost certainly not happen. This is because the producers whose gas would support the expensive expansion will most likely not do the drilling in the first place. They will know that their rate will be substantially higher than everyone else's, thus placing them at a competitive disadvantage and could be so high as to make their drilling program uneconomic. This has been recognized by the FERC:

Incremental pricing of expansion could put expansion shippers at a significant rate disadvantage with initial shippers, and accordingly could discourage exploration, development and production of Alaska natural gas. Having markedly different rates for similar service could be in conflict with one of the chief objectives of the [2004 Federal] statute, which is to encourage further exploration and development of Alaska natural gas. (Order No. 2005 at P 123).

By setting the roll-in level at 15% above the initial shippers' rates, AGIA effectively gives future generations of shippers the same benefit that the initial shippers received at the outset. Only to the extent that rolled-in rates exceed the rates that were set and approved for initial shippers, plus the value of governmental contributions that kept those rates as low as possible can governmental contributions be spread as broadly as possible amongst all system users.

CLAIM: It takes trillions of cubic feet of new gas reserves to make pipeline expansions economic, and those reserves have not been found yet.

RESPONSE: Geologists agree that the North Slope is awash in gas pockets of varying size, waiting to be discovered and commercialized. Obviously, the lack of guaranteed rolled-in rate treatment, and uncertainty over whether the gasline will be built in the first place, serve as disincentives for explorers to spend the millions of dollars required to explore for new these gas deposits. For this reason, nearly all known natural gas reserves have come about incidental to oil exploration, rather than exploration for gas itself, oil discoveries can be transported to the market through TAPS, but without a separate gas pipeline, natural gas cannot be transported to market. Thus, getting a gas line will make it economic for explorers to drill for gas in the more gas prone areas of the North Slope. Conversely, natural gas exploration will have the incidental benefit of resulting in new oil discoveries. In short, profitable natural gas exists on the North Slope, and the financial impetus to actively explore for it rely upon forward progress on the gasline, and commitment to rolled-in rate treatment for the costs of getting that new gas into the line.

CLAIM: The federal law that allows FERC to mandate a pipeline expansion solves the problem of expanding the pipeline.

RESPONSE: There are a number of major problems with the federal law (which is Section 105 of ANGPA). First, the law requires that a party requesting an expansion must sign a firm transportation contract if the expansion is mandated by the FERC. While this is an entirely reasonable requirement, it puts the cart before the horse with respect to an explorer. An explorer must know how big its reserves are before it could have any reasonable idea as to how much capacity it needs and would contract for. In order to know that, however, the explorer would have had to drill a number of wells to delineate and later develop its reserves. One exploration well can cost as much as $30 million.

A prudent explorer can't afford to drill to delineate and develop its reserves, though, without knowing when it can start producing and selling its gas. And that is the rub. The hypothetical explorer can't know when the FERC is going to act. Presumably, if the pipeline owner is resisting efforts to expand the pipeline and has forced the explorer to litigate the issue at FERC, the pipeline owner is going to resist that litigation. That means delay and expense and uncertainty (since the explorer cannot know for sure if its litigation will even be successful).

And even once the FERC is done, the pipeline company can appeal that decision to the U.S. Court of Appeals for the District of Columbia Circuit. While the 2004 federal statute requires that the court expedite any appeal arising under ANGPA. However, 26 months after FERC's original order was issued we are still waiting for a court decision on the Producers' appeal. This kind of delay would be fatal to an explorer's project economics.

Further, under Section 105 the FERC can only order an expansion if it finds that there is adequate downstream, take-away capacity for the explorer's gas. In addition, it must find that the rates resulting from the expansion would not result in a “subsidy” by existing shippers for the new shipper. The explorer would thus have to make a case not only that it has gas and is willing to sign a firm transportation agreement, but must also show how its gas could flow to markets and that the rates would not result in a “subsidy.” This is a heavy burden, and involves what may be a vague standard-whether the expansion causes a subsidy. This could invite litigation and add uncertainty to the process.

In the court the explorer would also face the risk that Section 105 of ANGPA would be ruled unlawful. Section 105 is unprecedented since nowhere else is the FERC empowered to mandate that a pipeline owner invest new capital to expand its pipeline. A court could find that this is unlawful.

Thus, reliance on Section 105 to assure expansion of the line is unwise and risky. AGIA mandates that the licensee undertake expansions when they are commercially reasonable-but it provides all stakeholders with the assurance that commercially reasonable expansions will be undertaken by the pipeline owners.

CLAIM: There is no guarantee that gas prices will be adequate to produce a profit, but the charges for holding capacity in the pipeline will go on for decades.

RESPONSE: The Producers have testified that they are quite willing to take the risk of commodity price changes. Indeed ExxonMobil's SEC Form10-K recites that price risk related to oil and gas commodities is among the risks that they normally take. So, the claim that it might not be possible to make a profit on every cubic foot of gas produced is nothing new or notable with respect to the Producers-they are in a commodity business and the price risk is something they manage on a daily basis.

As to the pipeline charges, it is true that once a shipper signs up for firm transportation capacity on the pipeline that shipper will have to pay its bills. Right now, FERC's policy is that virtually all of the pipeline's costs must be recovered through what is called a “reservation charge” or a “demand charge.” This charge is fixed based on the amount of capacity the shipper reserves. But nothing prevents the Producers from trying to enter into what are called “negotiated rates” under which FERC accepts what a willing seller of capacity and a willing buyer of capacity are able to work out an arms-length deal. Negotiated rates can take any form the parties agree. In some cases negotiated rates are fixed for the life of a contract-and the shipper is insulated from any rate changes over the life of the agreement. In other cases, it is possible for shippers to negotiate rates that would be higher or lower depending on the quantity actually shipped each month. In the world of negotiated rates (which have been allowed by the FERC since the 1990s) anything is possible. So, it is not a certainty that all of the pipeline costs must be paid regardless of whether gas is shipped or not.

In addition, one has to ask why the concept of paying for pipeline capacity that a Producer reserves for its use on the pipeline is even notable in this context. First, they are paying to “reserve” the capacity-and that capacity cannot then be sold by the pipeline to any other shipper on a firm basis. Thus if the pipeline company can't count on getting paid by the party reserving the capacity, its not going to get paid. Thus paying for capacity that has been reserved for a particular customer's use is entirely fair.

Moreover, it is notable that each of the Producers holds firm pipeline capacity on Lower-48 pipelines. BP and ConocoPhillips each have very large contracts for firm capacity on the Rockies Express pipeline that is now under construction to move gas from Wyoming to Ohio. BP holds 100,000 Dth/day of firm capacity on the line and ConocoPhillips holds 400,000 Dth/day. In each of those instances they have to pay for capacity regardless of whether they ship gas or not. So, the question becomes, if they sign up for firm capacity and agree to pay demand charges in the Lower-48, why not here?

In this regard it is notable, too, that both BP and ConocoPhillips' commitments on Rockies Express are “negotiated rates” and are not the pipeline company's cost-based “recourse rates.” According to the FERC certificate application both companies' rates are fixed for the entire duration of their contract-which appear to be at least ten-years (the contracts themselves are not public at this time to allow confirmation of the duration of the commitments). Inasmuch as these shippers rates are fixed for the life of the contract, they will clearly bear no risk of having to pay for any cost overruns that are experienced in the construction of the pipeline.

CLAIM: Holding pipeline capacity through a long-term transportation contract harms the balance sheet of pipeline customers since it is reflected as debt.

RESPONSE: This assertion is incorrect. Although the firm transportation (“FT”) capacity commitment that is associated with monetizing the North Slope reserves shows up in financial reports as a footnote, the obligation is not reflected on a corporation's balance sheet. More importantly, the footnoted obligation is not typically viewed as a debt-equivalent. There are indeed risks associated with holding FT - namely the requirement to ship or pay in the face of periodic negative netback risk, or inadequate reserves. However, holding the FT commitment also confers rewards - namely, the right to transport gas reserves that currently cannot be monetized. Any rational company making an FT commitment does so under the expectation that the risks of holding the FT rights are more than outweighed by the benefits. Credit and equity markets recognize this. Put differently, holding FT should actually improve a company's ability to access credit markets, because it permits a company to book valuable reserves that cannot currently be booked because they have no value. Meanwhile, a firm transportation commitment does not require payment in any and all circumstances. Exceptions include project non-completion, unplanned outages, and force majuere.

CLAIM: The AGIA's rolled-in rate provisions for expansions are not in the state's interest. This is because rolling in expansion costs could hurt the state in the event that the gas reserves supporting the expansion are offshore or otherwise not on state lands since the rolled-in rates will reduce the netback on all of the state's royalty gas and tax gas.

RESPONSE: It is correct that if: a) rolled-in treatment of the costs of an expansion causes rates for pre-existing shippers to rise; and b) the gas flowing in the expansion is not taxable and contains no royalty (as would occur for reserves more than 6 miles off shore), then the value of the state's royalty and production tax will decline.

However, it is incorrect to suggest, because there may be an instance in which rolled-in rates diminish state revenue, that the state's revenue interests are not served by rolled-in rates.

The fact is that no one knows where gas that enters the more expensive, later expansions will come from. It may come from beyond 6 miles in federal waters, but it could just as easily come from state lands. If gas from a later, more expensive expansion were to come from state lands, then the state would be significantly better off with rolled-in rate treatment. The value to the state of the expansion gas - even if it is from federal lands which generate a reduced state royalty share - more than off-sets the modest reduction of state royalty and tax value that rolled-in rate treatment imposes. Meanwhile, AGIA's rolled-in rate provisions provide any party looking for gas the comfort that their finds can enter the pipeline on reasonable economic terms. This ensures that companies will look for the gas in the first place. Conversely, without rolled-in rate treatment it is unlikely that companies will have economic incentive to look for gas and expand the pipeline beyond the first “cheap” expansion. If off-shore federal gas uses up the early “cheap” expansions, then the state may have to wait 15-20 years before there is room in the pipe for new gas from state lands to enter the pipe.

The state's interest in a competitive, level playing field for exploration and development opportunities in the state, and the robust economic activity and increased gas production that will result, are clearly in the state's interest. Although individual scenarios can be drawn in which the state earns less revenue because of rolled-in rates, on average the state's interests are much better served by AGIA's rolled-in rate provisions.