State offers 70 percent of Prudhoe Bay, Point Thomson royalty gas

Phillips and BP tell state that sales of royalty gas to companies wanting to bid in pipeline open season will hurt economics of gas pipeline

Kristen Nelson

Editor-in-Chief

The Commissioner of the Alaska Department of Natural Resources has determined that it is in the best interest of the state to solicit competitive bids for a portion of the state’s royalty share of the natural gas which would be produced from Prudhoe Bay and Point Thomson upon completion of a natural gas pipeline.

But existing gas producers — Phillips Alaska Inc. and BP Exploration (Alaska) Inc. — have told the state purchases of royalty gas to companies wishing to participate in a gas pipeline open season can hurt the economics of a gas pipeline project.

Because of the possibility of a 2002 open season for a proposed gas pipeline, DNR said Dec. 26, selling royalty gas now ìresponds to a commercial opportunityî to improve future royalty revenues from natural gas and to promote new private investment.

The state will be offering up to 70 percent of its royalty gas from the Prudhoe Bay and Point Thomson units. Bids will be accepted through Jan. 31 and opened and announced Feb. 1. The bids will then be evaluated and gas sales contracts will be negotiated.

DNR said the dates for the rest of the process are tentative: awarding successful proposals (Feb. 15), convening a Royalty Board hearing (March 1) and submitting executed gas sale contracts to the Legislature for approval (March 15).

Why a royalty gas sale now?

DNR said potential buyers are motivated to bid on royalty gas now in order to be able to nominate gas during an open season for the proposed pipeline. Because a nomination is a ship or pay commitment, companies which are still exploring for gas have told the state they would like to buy royalty gas to ship until they have their own gas in production. The gas could also be sold in-state or in the Lower 48 or used it in-state for petrochemicals. And there is a proposal to use gas to fuel a large Internet center on the North Slope.

DNR said a royalty gas sale could contribute to earlier commercialization of ANS gas and a gasline project by bringing additional participants to the open season.

The preliminary finding for the royalty gas sale was issued in October when DNR believed an open season could occur in the first quarter of 2002. Since then, the Division of Oil and Gas has met with the Alaska Natural Gas Pipeline Project Team — the North Slope producers group of BP, ExxonMobil and Phillips which has been evaluating a pipeline project — and the team said an open season will not be held in the first quarter of 2002.

DNR then extended some of the deadlines. But because a royalty sales contract must be approved by the Legislature, which ends its 2002 session in May, DNR said any gas sales contracts submitted to the Legislature must be negotiated by the end of the first quarter.

Minimum cash requirements

Potential purchasers must also offer a base price, which will be the higher of a fixed dollar per-volume unit price or the volume-weighted average of the amounts paid by the lessees on royalty gas left in-value.

Buyers may also offer a price premium over the base price, structured as a flat, per-unit addition to the base price or a percentage of the base price added to the base price.

An option price could be offered for the ability to increase or decrease the quantity the buyer would purchase during the life of the contract.

Special commitments may also be offered: to be given weight in the bid evaluation process, they must be quantifiable. DNR said examples of special commitments could include in-state processing, in-state use, in-state investment or local hire.

Concerns from potential bidders

DNR said it will award one or more contracts based on the merits of the proposals and will allow withdrawals: “If the award is for volumes insufficient to the winning proposal’s requirements, the buyer may withdraw its proposal.”

Producers object to backstopping

Phillips recommended to the state that capacity allocation and expansion procedures be achieved through Federal Energy Regulatory Commission processes and said that future North Slope gas producers will have access to the pipeline.

DNR said BP also commented on the proposed sale, and that its letter mirrored many of Phillips’ comments. BP asked the state to refrain from taking steps that would jeopardize the commercial viability of the pipeline project.

BP said it is not opposed to the state marketing its royalty gas, and said it might bid in the sale. BP also suggested to the state that the royalty in-kind sale might address some industry concerns about fiscal certainty by providing clear and transparent pricing for royalty gas.

DNR said that, depending on the price structure adopted for the royalty gas sale, the state “may choose to refer to the RIK gas price in its evaluation of the value of RIV gas.”

In-state demand growth depends on gas price

Kristen Nelson

The Department of Natural Resources said Dec. 26 that the study, done by Econ One Research, was expected to be finalized at the end of December.

Natural gas usage in the state is approximately 227 billion cubic feet a year and growth of an additional 140 Bcf a year over the next two decades is possible, the study found. Econ One said three assumptions underlie that growth: relative energy prices in the future must be consistent with current levels; the state’s economy must continue to grow at the rates observed in the last five years; and in-state access to Alaska North Slope gas from a high-pressure, dense-phase gas pipeline must not be cost prohibitive.

Econ One said it found that several factors may challenge the economics of in-state access to ANS gas. In the Interior, costs for residential natural gas include a $1 per thousand cubic feet gas transmission cost from the North Slope to Fairbanks, 5 cents per Mcf for gasline tap, meter and pressure reduction and a local distribution system cost of about $2.29 per Mcf. Those costs are approximately competitive with electricity, but conversion also requires approximately $1,000 per home for furnace and water heater conversion and 100 percent conversion of 11,000 residential customers. The study said the 100 percent penetration was unlikely and noted Enstar serves only 80 percent of Southcentral homes.

For Southcentral, ANS gas could be competitive with energy alternatives such as fuel oil or liquefied natural gas imports into Cook Inlet if annual throughput for a spur line exceeded 30-40 Bcf a year. To be economic, a spur gasline would have to serve a segment of the existing Southcentral customer base now served by gas from Cook Inlet.

The study includes estimated gas usage for several major industrial projects:

In Southcentral, increased gas usage in existing industrial capacity is limited to 3-4 Bcf a year at the ammonia-urea plant; plant expansion could use 30 Bcf a year.

On the North Slope, a moderately sized Internet data center would consume less than 1 Bcf a year while a relatively large Internet data center could consume as much as 4.3 Bcf per year.

A polyethylene petrochemical plant in the Interior — similar to the one being considered by Williams ó would have net gas usage of less than 30 Bcf per year, although it would process 300-400 Bcf per year.