That was something of a side issue when the State of Alaska terminated the Point Thomson unit in late 2006 for lack of development is starting to draw more attention.
That issue is certification of wells capable of producing in paying quantities.
Current focus is around a July 10, 2008, letter from Alaska Division of Oil and Gas Director Kevin Banks. Judging from that letter, the division is changing how it certifies wells judged capable of producing in paying quantities.
Previous certifications — many dating from decades ago — contain no time limit for the lease extension, although the state does have the authority to order a well certified capable of producing in paying quantities into production.
Banks told Petroleum News Feb. 19 that it was not the state’s intention to allow certification to hold leases indefinitely, but as a step in moving a prospect into production.
The July letter apparently went unnoticed last summer, but was challenged by ConocoPhillips, ExxonMobil and Chevron when they became aware of it in September.
The issue of leases held by wells certified capable of producing in paying quantities came up in 2006 at the end of the Murkowski administration when then-Department of Natural Resources Commissioner Mike Menge terminated the Point Thomson unit, citing lack of an acceptable plan of development for the 30-year-old unit.
Ten wells, on nine leases at Point Thomson, had been certified by the state as capable of producing in paying quantities. Those certifications did not contain time limits.
Menge said in his decision that there were no leases in the unit capable of producing in paying quantities because the certified wells had been plugged and abandoned.
He said that the certified wells were no longer capable of producing in paying quantities, and thus no longer held the leases on which they were drilled.
North Shore letterIn a July 10, 2008, letter to Brooks Range Petroleum Corp. on the company’s North Shore No. 1 well, Banks said the division had determined that by its regulations (11 ACC 83.105) and paragraph 7 of the lease, that the North Shore No. 1 well “is economically and physically capable of producing in paying quantities.”
But Banks said that the determination “is conditioned” on the well’s “continued physical and economic capabilities to produce in paying quantities,” and said the determination “is subject to redetermination” of the well’s capability to produce in paying quantities and said BRPC is to seek the “first redetermination” by Aug. 1, 2010.
An appeal of the decision was required within 20 days; BRPC did not appeal.
And the division’s determination appeared to have gone unnoticed by majors over the summer.
ConocoPhillips, ExxonMobil and Chevron, however, all protested the decision in September and October.
Not a sinecureBanks told Petroleum News that the time limit on the North Shore certification is different than earlier certifications.
The state wants to see “progress and development,” he said. The applicant for certification, on the other hand, wants some assurance “that they’ll be able to benefit from expenditures of money to drill the well.”
Once a well has been drilled, proving up a prospect, the operator wants to secure the land position to be able to continue toward development, Banks said.
“Our point of view is that should be encouraged — at the same time it’s not some sort of latch to lock up the land forever without any progress,” he said.
With the time limit placed on the North Shore well certification, what the state would like to do moving forward is to “keep the well in certified status and that will help secure the lease or unit” until the operator can move on with full development, given that there may be lack of infrastructure to tie into or the need to drill a lot more wells, he said.
The producers have “taken the tack that certification means forever,” Banks said, and that certification “somehow overrules the state’s ability to see that development occurs.”
He noted that the decision to certify a well has never been brought before a commissioner; it’s a policy exercised by the division without the commissioner making any kind of decision on appeal about certification.
Banks said he does not believe that regulatory changes are necessary to specify a time limit in a certification.
“I wouldn’t have signed the certification if I believed that was true,” he said. “I believe that we do have the authority.”
When such a time-limit certification is appealed to the commissioner, whether will be up to the commissioner to decide if the division has the authority, Banks said.
“We don’t want people holding on to leases forever,” he said.
And as for recertification, the basis for recertification is the same as applied in certification, Banks said.
Conoco: departs significantlyIn a Sept. 18 letter ConocoPhillips told Banks the July 10 determination “has been brought to our attention” as ConocoPhillips owns an interest in the lease on which the well was drilled. The company said that although it did not appeal the decision, “the decision departs so significantly from prior decisions on well certification requests as to warrant comment and clarification about the Division’s intent in issuing such a letter.”
“The letter appears to create a new policy and practice that have not undergone the required public process by granting an undefined conditional ‘determination,’” ConocoPhillips said, without referring to the certification incorporated in such letters in the past. The company said the letter “does not provide information on what criteria will be used as the basis for determining anew in August 2010 that the North Shore #1 well will or will not be ‘capable of producing in paying quantities.’”
ConocoPhillips also said that commercial arrangements for exploration properties “may hinge the conveyance of lease rights upon receipt of certification that a well is capable of producing in paying quantities” and a determination contingent on the view the division may take in the future — and subject to reversal — “could seriously undermine the viability of such commercial arrangements.”
The letter creates additional uncertainty, ConocoPhillips said, because it is not clear how the division “might intend to attempt to apply this new practice to other leases or wells.”
Exxon: new conditionsIn a Sept. 30 letter, ExxonMobil Production Co. told Banks it was pleased the division had determined the North Shore No. 1 well capable of producing in paying quantities, but noted “that your letter makes certification of the well subject to new conditions for ‘continued physical and economic capabilities to produce in paying quantities’” and requires BRPC to seek the first redetermination by Aug. 1, 2010, suggesting “that further such ‘redeterminations’ will be required in the future.”
ExxonMobil said this appeared to be “contrary to existing lease and regulatory conditions and a significant new policy by DNR. We are unaware that any well previously certified in Alaska as capable of producing in paying quantities has ever been made subject to such conditions.” The company said DNR regulations do not impose such requirements and “a process of ongoing ‘redeterminations’ appears to be inconsistent with regulations that require only a single certification.”
ExxonMobil said, “other longstanding lease rights and regulatory protections in turn derive” from certification of a well as capable of producing in paying quantities, ,and are potentially diminished or overridden by such a new policy.”
The company said it was unclear why the division would implement this policy for a single well.
“We believe that for both substantive and procedural reasons such a new policy would need to be established, if at all, on a uniform application through public notice and rule making, not on an ad hoc basis,” ExxonMobil said.
“In addition to questions as to the legal authority for these requirements,” ExxonMobil said it also believes the new approach “will undermine the certainty that previously existed about the nature of certification, and possibly serve to discourage or delay development.”
Alaska law, the company said, “requires that such a major new policy be implemented through rule making.”
Chevron, in an Oct. 1 letter, said it had recently become aware of the July 10 letter to BRPC and had also seen the ConocoPhillips and ExxonMobil letters to the division expressing concern “over the apparent departure from existing lease and regulatory conditions and deviation from prior decisions regarding well certification indicating a possible new practice and policy regime.”
The historic caseThe certification issue was argued Jan. 16 on behalf of BP Exploration (Alaska) by Tom Walsh, a geophysicist and managing partner at Petrotechnical Resources of Alaska, whose firm researched certified wells in the state and who told DNR Commissioner Tom Irwin and hearing officer Nan Thompson that Menge’s certified well decision changed what had been longstanding DNR policy.
At a hearing on appeals of 31 Point Thomson lease terminations, Walsh said more than 100 leases in the state are held beyond their primary terms of wells certified capable of production.
He said a study of certified wells found that plugging and abandoning had no impact on certification: The state had certified wells both before and after they were plugged and abandoned.
At a Feb. 12 continuation of the hearing, Walsh said he had investigated 119 certified wells, most of which, he said, are now in producing units.
Walsh said he had not seen time limitations on leases extended by wells capable of production until the July 2008 determination on the North Shore well.
One of the benefits of certification, applicability of a reduced discovery royalty, has a time limit, Walsh said at the hearing, but letters certifying wells do not include a time limit for the extension of the lease.
He said that was true of any certified well: “I’ve never seen anything that conflicts with that.”
Thompson asked whether a time limit in a certification letter would override that extension.
Walsh said “the only one I’ve seen so far that does that is the ... qualification in the Brooks Range North Shore letter. That’s the first time I’ve ever seen the qualification on the term.”
In a Feb. 4 affidavit Walsh summarized the conclusions he presented Jan. 16.
He said that before DNR’s Point Thomson decision whether a well was plugged and abandoned was not relevant in a determination that the well was capable of producing in paying quantities; whether a well was capable of producing in paying quantities was a one-time determination; there was no minimum production rate required; such a determination was recognized by DNR as extending the term of the lease beyond its primary term even if a unit containing the lease was dissolved; that DNR’s interpretation of “capable of producing oil or gas in paying quantities” was consistent from the 1960s until the 2006 Point Thomson decision; and that the certified well program “has been and remains a key component of the state’s oil and gas resource management, and has been relied upon by the industry for 46 years.”
The Menge decisionIn a Nov. 27, 2006, decision terminating the Point Thomson unit, then-DNR Commissioner Menge said: “There is no existing certified PTU well capable of producing in paying quantities. A PTU production well has never been drilled. No certified PTU well exists today.”
Menge said that because discovery exploration wells have been plugged and abandoned, none of them are capable of producing in paying quantities today. With the exception of the Sourdough No. 2, all of the certifications were issued in the 1970s and 1980s, the commissioner said, and all of the certified wells have been plugged and abandoned.
This issue was not raised when then-Director of the Division of Oil and Gas Mark Myers put the Point Thomson unit in default in 2005.
The state’s early DL-1 oil and gas lease forms do not require a plan of development for a lease with a well capable of producing in paying quantities to be continued beyond its primary term; new-form leases have this requirement.
“Whatever the merits of the certifications when they were originally issued, the suggestions in the Director’s Decision that certified wells exist today or that the prior certifications of now non-existent exploration wells indefinitely extend the term of the leases upon which they were drilled or that the PTU should be treated as a unit with certified wells is disapproved and reversed in this Commissioner’s Decision,” Menge said. “Those suggestions are not supported by the facts. There are no certified wells in the unit capable of producing in paying quantities. All the wells which were certified have been plugged and abandoned. Inconsistent findings and statements in the Director’s Decision on certified wells are hereby disapproved.”
Exxon on well productionIrwin asked during the lease termination hearing what would happen if he required the certified wells at Point Thomson to be put on production.
ExxonMobil drilling engineering manager Bill Meeks said in an affidavit that he has reviewed the manner in which each of the 10 wells capable of producing in paying quantities was plugged.
“I am confident that we can re-enter each of these wells and put them on production,” he said.
He provided detail on how each of the 10 wells could be re-entered and said that given the procedures described, and without permitting delays, ExxonMobil may be able to re-enter and do the described remedial work in less time than it would take to drill a new well, but it may take longer to put the wells on production because most of them would require flowlines, control lines and mainland roads to connect them to a production facility. The production facilities will not be completed until the end of 2014.
For most of the wells, costs could be comparable to new wells, estimated at $100 million to $150 million per well at Point Thomson, he said.
Meeks also said in his affidavit that re-entering the 10 wells capable of producing in paying quantities “is not the optimal way to develop this resource” because the re-entered wells would have lower delivery potential due to smaller tubing strings.
“They will also have a greater environmental footprint than a more centralized development,” he said. “The wells planned for the nine-well drilling program are designed to accommodate all types of production from the reservoir and will have high production capacity aimed at maximizing production. That is a more efficient way to develop the resource.”