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Annual plans required from operators Division of Oil and Gas director Bill Barron discusses units, participating areas, plans of development with Senate Resources Kristen Nelson Petroleum News
Bill Barron, director of the Alaska Department of Natural Resources’ Division of Oil and Gas, gave members of the Senate Resources Committee an overview of how the division manages oil and gas units at a Feb. 22 hearing.
Members of the committee have questioned the state’s effectiveness in getting North Slope leaseholders to develop oil resources.
Issues senators raised at the hearing included a question from committee co-Chair Tom Wagoner, R-Kenai, on whether this winter’s active exploration season is being driven by expiring leases, a request from co-Chair Joe Paskvan, D-Fairbanks, for the number of leases which expired in the last five years and the number which will expire in the next five years, and questions from Sen. Bill Wielechowski, D-Anchorage, on whether companies need as much time as leases allow to develop prospects and why companies wait until the end of lease terms to work their acreage.
Lease terms On the issue of this winter’s exploration drilling, Barron said Repsol — which has a number of exploration wells planned this winter — had picked up leases that were about to expire and said the company is “a poster child” for drilling because leases were expiring.
As for the appropriateness of lease terms, Barron said terms have varied from 10 years down to five, with seven as a middle ground. He said shorter terms are probably appropriate on the Kenai Peninsula where there is infrastructure and roads, while longer terms are needed on the North Slope where there is winter-only exploration, essentially allowing companies three months out of the year for exploration. Barron said companies have to gain enough land, do seismic, analyze the seismic, find an appropriate target, get permits, secure a rig, build an ice road and ice pad and begin drilling.
The state experimented with a five-year term on the North Slope, he said, but that was a detriment to both the industry and the state because it didn’t give companies enough time.
Barron said the division had a lot of dialogue with historic and prospective explorers about lease terms prior to this winter’s areawide lease sales and went with a full 10-year term, but kicked the annual rental rate up after year seven, from $10 an acre to $250 an acre for year eight, nine and 10. He said the idea was that seven years is probably reasonable for exploration and delineation, and if someone is not interested in moving forward they probably know that by year five, six or seven.
If a company isn’t going to move forward on its leases, but wants to keep them, it will cost the company about the same amount it would cost to drill a well, he said.
Wielechowski cited Great Bear, Royale and Repsol as examples of companies that are moving forward rapidly.
Barron said Great Bear has had leases for two years, originally said they’d be working in December of 2011 and has yet to explore, although they can work year round because they are on the road system. Royale may or may not come in as planned, he said, and Repsol was motivated because of lease expiration.
The shale issue Asked by Wielechowski if the division had figured out how it was going to unitize shale, Barron said no, but that the division was working closely with the Department of Law on that issue.
In discussing units for conventional resources, Barron said they provide for efficient development of the reservoir while protecting each lessee’s interests and extending the life of leases in the unit.
For conventional resources there is interaction between wells in a unit, but in a shale development there is no interference with a well from a well next to it because the rock is very tight, with very low permeability and porosity.
At the extreme, in shale, every well is its own unit, he said.
One issue with shale is protecting the state’s interests. A single shale well could hold an entire lease even though 50 wells may be needed to drain the hydrocarbons within that lease.
That is why, in the last lease sale, the state offered quarter-sectioned leases in areas prospective for shale, Barron said.
Participating areas Plans of development occur at the stage where a leaseholder has made a discovery, acreage has been unitized, production has begun and a participating area has been established.
A participating area is formed once the unitized reservoir is on sustained production and a separate participating area is required for each producing horizon within the reservoir. There are 18 existing units on state lands, with two more proposed, and 42 participating areas, Barron said.
Wagoner asked about partners in a development not wanting to participate, and asked if the state gets involved.
Barron said the state requires leaseholders to join units for their protection and the state’s protection.
Typically a unit agreement has clauses for parties who don’t want to participate, he said, but there is usually a significant penalty.
Wagoner asked if the state gets involved when partners don’t agree with the decision of the operator on work within a unit and Barron said, yes, that the state has typically gotten engaged in such discussions.
Paskvan asked if all working interest owners must agree on a plan of development.
Barron said companies don’t have to gain working interest owner approval to present a plan, but they do need it to progress a plan once it’s approved.
Approval of the plan of development is the responsibility of the Division of Oil and Gas. The operator presents plans to the division, and in theory they’ve had discussions with their partners, he said.
The division receives a plan of development or POD every year and has a dialogue with the operator on the plan.
Once the POD is approved by the division, the operator has permission to proceed, but at any time during the 12 months covered by the plan it can change, Barron said.
Economics? Wielechowski asked if the state did economic analyses on PODs.
Barron said not specifically, that the division is looking at the overall direction of activities, but he did say the division has at times engaged in a dialogue on moving forward a project that generally looks economic. He said having an economic model in conjunction with a POD probably doesn’t sway the needle in the state’s favor in being able to move a project forward.
North Slope operators are allocating company resources, Barron said, and if the division looked at a single project and said it was economic, the operator would probably say it doesn’t meet the company’s hurdle rate.
Companies are trying to do reservoir management, long-term field development and portfolio management, he said.
Barron also PODs are just plans, not commitments, not promises, not contracts — they are a scenario for planning purposes, and companies review what occurred in a given year in the following year’s POD.
POD approval is a process, he said, with a technical review and typically requests from the division for more information before the division approves a POD.
Barron characterized the POD process as messy, but said it has generated a tremendous reserve base for the state. He said the state’s reservoirs are “incredibly well managed” by any standard, and referring to Prudhoe Bay and Kuparuk, noted that these are huge fields that have well surpassed original projections of reserves, and called activity on the North Slope very high for a very mature basin.
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