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In September 2005 the Director of the Division of Oil and Gas, Department of Natural Resources disapproved the Point Thomson Unit (PTU) owners’ 22nd Plan of Development (POD) because “it did not set out a plan to bring the PTU into commercial production within a reasonable time frame.”
The Director believed that the pace of prospecting and development for the PTU should be more aggressive than what the PTU owners proposed; so he rejected the POD. Ultimately the Superior Court upheld his decision rejecting the 22nd POD.
After several years of appeals, and after the current appeal to the Alaska Supreme Court, the next step in the process will be for the Director to explain what he considers necessary to diligently develop the PTU. As a part of that explanation the Director can state that if his determination is not accepted by the PTU owners, the unit will be terminated. This explanation would normally take the form of a proposed POD that would be agreed to by the PTU owners. Once the Director explains what he believes is necessary to diligently produce the PTU, the Director will give the PTU owners at least 30 days notice for an opportunity to comment on the proposed POD.
After the hearing the Director will make a final determination regarding the rate of prospecting and development for the PTU. If the PTU owners disagree with the Director’s decision, they can once again appeal that decision to the Commissioner and to the Superior Court.
The PTU owners’ obligation will be to convince the court that what the Director proposed is “in excess of that required under good and diligent oil and gas engineering and production practices.” Because the decision involves substantial agency expertise and not merely an application of the law, the court will apply the reasonable basis test and give deference to the department in its review of the Director’s decision.
To quote the court “Under the reasonable basis standard of review for administrative decisions involving complex issues involving agency expertise, the court is to give deference to the agency’s determination so long as it is reasonable, supported by evidence in the record as a whole, and there is no abuse of discretion.”
This means that unless the Director grossly oversteps his authority, the Superior Court will uphold his determination. The PTU owners understand this and will not risk losing the PTU over an appeal unless the PTU owners believe the Director clearly overstepped his authority in what he required of the PTU owners.
Once this step in the process is completed the PTU will be back on track moving toward development.
Showing posts with label Point Thomson Unit. Show all posts
Showing posts with label Point Thomson Unit. Show all posts
Monday, April 5, 2010
Saturday, February 20, 2010
DNR Point Thomson Study Evaluated by Feds
Recently the National Energy Technology Laboratory (NETL) published an addendum to its August 2007 report titled “Alaska North Slope Oil and Gas, A Promising Future or an Area in Decline?” This report is often referred to by the State of Alaska and others for support in identifying the potential undiscovered reserves on the Alaska North Slope.
The April 2009 addendum made few changes to the original April 2007 Report, but one significant addition was the inclusion of a couple of paragraphs referring to Point Thomson. I have included the additional paragraphs below. The quote is from page 2-30 of the report and can be found at http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potential.pdf.
The statement is significant because it evaluates a study commissioned by the Alaska Department of Natural Resources (ADNR) estimating the original oil and gas in place at Point Thomson and, I assume, is at least part of the reason for ADNR’s position arguing that Point Thomson oil is economic and should be produced first, prior to gas development. The federal report states that the DNR study was optimistic and that a more realistic reserve estimate would be approximately one-fifth the size stated in the DNR study.
Quote at Page 2-30
“Point Thomson is a large field, with a long and troublesome history. A study, recently commissioned by the ADNR (ADNR, 2008), provided an original gas in place (OGIP) estimate of 8.5 to 10.4 TCF, with original condensate in place of 490 to 600 million barrels of condensate (MMBC), and OOIP of 580 to 950 MMBO in the oil rim. The study suggests that under ideal conditions, with gas cycling and extended production of condensate and oil prior to gas blowdown (30 years with 22 producing wells and 8 injection wells), the field could produce as much as 420 to 515 MMBCF and 290 to 475 MMBO. The technically recoverable gas reserves produced under a scenario similar to the one above would be about 5.9 to 7.3 TCF. If blowdown were to occur early in the history of the field development, the models suggest that recovery of condensate and oil could be as low as 127 to 156 MMBC and 30 to 150 MMBO, but gas recovery would be in the 6 to 7 TCF range over a period of 12 to 15 years (ADNR, 2008). Additional scenarios were run with varying numbers of producing and injection wells, for periods of 10 and 20 years before blowdown, and results shown production ranges of: (1) 10 years of cycling – 300 to 370 MMBC, 225 to 370 MMBO, and 4.8 to 5.9 TCF, and (2) 20 years of cycling – 370 to 450 MMBC, 250 to 400 MMBO, and 4.8 to 5.9 TCF.
The findings appear to be optimistic and open to question, especially with respect to the recovery predicted for oil from the oil rim. The summary of findings (ADNR, 2008) cites the oil having American Petroleum Institution (API) gravity as high as 18°. This is the same range of API gravity as the heavy oil being produced from the West Sak and Schrader Bluff reservoirs, and recoveries are not projected to be more than 5 to 10%. The API gravity at the Kuparuk West Sak pool ranges from 22° to 10°, increasing with depth (temperature) and at the Milne Point Schrader Bluff pool it ranges from 22° to 16°. Thus a more realistic value for the oil rim at the Point Thomson field may be 58 to 95 MMBO, not the 290 to 495 MMBO theorized in the PetroTel study performed for ADNR. The Point Thomson owners “don’t believe the recovery of this heavy oil will be more than 5% --- nowhere near 50” (PN, 2008). They further state that “the oil rim is thin, discontinuous, and heavy oil --- molasses.””
The above bolding was mine and not in the original report. Additional discussion consistent with the above can be found at pages 3-98,99 where the NETL calls the ADNR study "overly optimistic."
The April 2009 addendum made few changes to the original April 2007 Report, but one significant addition was the inclusion of a couple of paragraphs referring to Point Thomson. I have included the additional paragraphs below. The quote is from page 2-30 of the report and can be found at http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potential.pdf.
The statement is significant because it evaluates a study commissioned by the Alaska Department of Natural Resources (ADNR) estimating the original oil and gas in place at Point Thomson and, I assume, is at least part of the reason for ADNR’s position arguing that Point Thomson oil is economic and should be produced first, prior to gas development. The federal report states that the DNR study was optimistic and that a more realistic reserve estimate would be approximately one-fifth the size stated in the DNR study.
Quote at Page 2-30
“Point Thomson is a large field, with a long and troublesome history. A study, recently commissioned by the ADNR (ADNR, 2008), provided an original gas in place (OGIP) estimate of 8.5 to 10.4 TCF, with original condensate in place of 490 to 600 million barrels of condensate (MMBC), and OOIP of 580 to 950 MMBO in the oil rim. The study suggests that under ideal conditions, with gas cycling and extended production of condensate and oil prior to gas blowdown (30 years with 22 producing wells and 8 injection wells), the field could produce as much as 420 to 515 MMBCF and 290 to 475 MMBO. The technically recoverable gas reserves produced under a scenario similar to the one above would be about 5.9 to 7.3 TCF. If blowdown were to occur early in the history of the field development, the models suggest that recovery of condensate and oil could be as low as 127 to 156 MMBC and 30 to 150 MMBO, but gas recovery would be in the 6 to 7 TCF range over a period of 12 to 15 years (ADNR, 2008). Additional scenarios were run with varying numbers of producing and injection wells, for periods of 10 and 20 years before blowdown, and results shown production ranges of: (1) 10 years of cycling – 300 to 370 MMBC, 225 to 370 MMBO, and 4.8 to 5.9 TCF, and (2) 20 years of cycling – 370 to 450 MMBC, 250 to 400 MMBO, and 4.8 to 5.9 TCF.
The findings appear to be optimistic and open to question, especially with respect to the recovery predicted for oil from the oil rim. The summary of findings (ADNR, 2008) cites the oil having American Petroleum Institution (API) gravity as high as 18°. This is the same range of API gravity as the heavy oil being produced from the West Sak and Schrader Bluff reservoirs, and recoveries are not projected to be more than 5 to 10%. The API gravity at the Kuparuk West Sak pool ranges from 22° to 10°, increasing with depth (temperature) and at the Milne Point Schrader Bluff pool it ranges from 22° to 16°. Thus a more realistic value for the oil rim at the Point Thomson field may be 58 to 95 MMBO, not the 290 to 495 MMBO theorized in the PetroTel study performed for ADNR. The Point Thomson owners “don’t believe the recovery of this heavy oil will be more than 5% --- nowhere near 50” (PN, 2008). They further state that “the oil rim is thin, discontinuous, and heavy oil --- molasses.””
The above bolding was mine and not in the original report. Additional discussion consistent with the above can be found at pages 3-98,99 where the NETL calls the ADNR study "overly optimistic."
Wednesday, January 13, 2010
Point Thomson - Where to From Here?
In order to understand the Court’s January 11, 2010 decision, a review of what the court told DNR and the Point Thomson Unit (PTU) Owners in the December 26, 2007 decision is necessary.
In the December 26th opinion the court addressed two issues: (1) the Department’s rejection of the Lessees’ proposed modified 22nd Plan of Development (POD) for the PTU, and (2) the Department’s termination of the PTU.
Regarding the Department’s rejection of the 22nd POD the Court determined that DNR had the authority to administratively decide whether a proposed plan of development should be accepted or rejected and cited Section 10 of the PTUA which states that the POD “shall be as complete and adequate as the Director may determine to be necessary for timely development and proper conservation of the oil and gas resources of the unitized area…” As to the standard of review the Court would apply to DNR’s decision, the court stated that the court’s “review of those determinations ‘would need to be appropriately deferential’ such that the reasonable basis test would apply.”
“Under the reasonable basis standard of review for administrative decisions involving complex issues involving agency expertise, the court is to give deference to the agency’s determination so long as it is reasonable, supported by evidence in the record as a whole, and there is no abuse of discretion.”
What this meant to the PTU Owners is that DNR had broad discretion to accept or reject a POD and if the PTU Owners wanted to have an approved POD they would have to listen to what DNR requested and respond accordingly.
Regarding the Department’s termination of the PTU, the PTU Owners argued that the termination could only occur by bringing action in State Court. The court disagreed and stated that termination could occur through administrative action, but the court then went on to state that Unit termination was just one of the remedies for rejection of a POD and that DNR did not provide the Unit Owners with an opportunity for a hearing on the appropriate remedy to the State upon DNR’s rejection of the proposed 22nd Plan of Development. The Court remanded the matter to DNR to conduct a hearing on the appropriate remedy.
The court provided DNR with two statements of guidance regarding its review of the appropriate remedy for rejection of the POD. The first came in footnote 7 on page 24 of the opinion. There the court stated:
“But see Section 21, second paragraph, of the PTUA as modified in 1985. [R. 794] That revision specifies that the Department may not require any increase in the rate of production or development “in excess of that required under good and diligent oil and gas engineering and production practices.” This section may well have applicability when determining the appropriate remedy when DNR rejects a proposed plan of development. See discussion, infra.”
The second came near the end of the opinion at page 42:
“Accordingly, this matter is remanded to the DNR for the purpose of according to the Appellants a hearing on the appropriate remedy to the State upon DNR’s rejection of the proposed 22nd Plan of Development. On remand, the agency should also consider the import of Section 21 of the PTUA, as amended in 1985, in determining the appropriate remedy.”
A statement like this is comparable to telling DNR they have the right to determine the remedy for a rejection of a POD, and Unit termination is one of those options, but the DNR should apply the standards in Section 21 to make that determination.
Subsequent to the issuance of the above opinion, recognizing what the court said about DNR’s authority to reject a POD and possibly terminating the Unit, the PTU Owners submitted a 23rd POD substantially committing to everything DNR had previously requested: an unequivocal commitment to bring the unit into production.
DNR granted the PTU Owners a hearing and considered Section 21 as the court requested but determined that Section 21 did not apply to its analysis of remedies. DNR then rejected the PTU Owners proposed 23rd POD and terminated the Point Thomson Unit without applying the standards set out in Section 21 of the PTUA.
With the above as background this document will now analyze the January 11, 2010 Superior Court Decision.
The second sentence in the first paragraph provides a concise statement of the next 30 pages of analysis, “…the contractual agreement between DNR and the Appellants precludes termination of the Point Thomson Unit in these circumstances without consideration of good and diligent oil and gas engineering and production practices, …” .i.e., the DNR did not consider the standards set out in the second paragraph of Section 21 as the court told them to do; therefore, DNR may not terminate the Point Thomson Unit.
In its analysis the court found that the interpretation of Section 21 is “dispositive of this appeal.” The PTU Owners argued that DNR was required to comply with the provisions of Section 21 and DNR argued that Section 21 did not apply to its remand proceedings.
If Section 21 does not apply to DNR’s POD decision, then the burden for coming up with an acceptable POD lies with the PTU Owners and DNR is not obligated to propose or identify conditions that would lead to an acceptable POD. If Section 21 applies to DNR’s review of remedies for a rejected POD, then DNR has a burden to identify conditions that would lead to an acceptable POD.
DNR proposed five reasons why Section 21 should not apply to its remand decision and the court systematically disposed of each. The crux of the Court’s decision came with its response to DNR’s fifth reason: an impermissible shift of burden to DNR to determine the appropriate rate of production. The DNR argued that if it were required to comply with the standards set out in Section 21, the agency would be inappropriately “saddled with the burden of designing an adequate POD.” The Court recognized that burden but considered it a reasonable contractual obligation for DNR to meet and in a footnote implied that DNR was not in as bad a position as it supposed and that DNR could probably require the Unit to go into production or be terminated.
The Court then determined that the PTU Owners did not receive a Section 21 hearing and that further proceedings were necessary.
The next issue the Court addressed was a due process concern. The PTU Owners argued that the dispute should be referred to an independent hearing officer or, in the alternative, the Court should grant a trial de novo. DNR argued that the due process concern should be addressed first before the trial de novo decision was made.
The court stated that “An impartial tribunal is basic to a guarantee of due process” and found a due process violation in DNR's process because the attorneys advising the Commissioner were the same attorneys that represented the agency on the first appeal and because Ms. Nan Thomson served as both the hearing officer at the remand proceeding and previously as DNR’s representative when the agency was defending its first decision in the 2007 appeal before the Court.
Once the Court made a finding of a due process violation the only remaining issue was whether the court should remand the matter to DNR for an administrative proceeding in accordance with this decision or retain jurisdiction and conduct a de novo trial. The court then gave both parties 30 days to submit additional briefing on this issue.
This places DNR in the interesting position of arguing to the Court that it should be granted the right to conduct a Section 21 hearing and that it can effectively apply the Section 21 standards to the issues before it when it had previously argued so vehemently that Section 21 standards should not apply. It will be interesting to see if the Court grants DNR the right to hold the hearing or if the Court has lost so much trust in the agency that the court retains jurisdiction and makes the determination itself.
In summary, the Court determined that the Section 21 standards applied to DNR’s decision requiring DNR to identify for the PTU Owners those conditions that the DNR considers necessary for approval of an acceptable POD, and if DNR is granted the right to conduct a Section 21 hearing, it must be conducted by an impartial hearing officer.
In the December 26th opinion the court addressed two issues: (1) the Department’s rejection of the Lessees’ proposed modified 22nd Plan of Development (POD) for the PTU, and (2) the Department’s termination of the PTU.
Regarding the Department’s rejection of the 22nd POD the Court determined that DNR had the authority to administratively decide whether a proposed plan of development should be accepted or rejected and cited Section 10 of the PTUA which states that the POD “shall be as complete and adequate as the Director may determine to be necessary for timely development and proper conservation of the oil and gas resources of the unitized area…” As to the standard of review the Court would apply to DNR’s decision, the court stated that the court’s “review of those determinations ‘would need to be appropriately deferential’ such that the reasonable basis test would apply.”
“Under the reasonable basis standard of review for administrative decisions involving complex issues involving agency expertise, the court is to give deference to the agency’s determination so long as it is reasonable, supported by evidence in the record as a whole, and there is no abuse of discretion.”
What this meant to the PTU Owners is that DNR had broad discretion to accept or reject a POD and if the PTU Owners wanted to have an approved POD they would have to listen to what DNR requested and respond accordingly.
Regarding the Department’s termination of the PTU, the PTU Owners argued that the termination could only occur by bringing action in State Court. The court disagreed and stated that termination could occur through administrative action, but the court then went on to state that Unit termination was just one of the remedies for rejection of a POD and that DNR did not provide the Unit Owners with an opportunity for a hearing on the appropriate remedy to the State upon DNR’s rejection of the proposed 22nd Plan of Development. The Court remanded the matter to DNR to conduct a hearing on the appropriate remedy.
The court provided DNR with two statements of guidance regarding its review of the appropriate remedy for rejection of the POD. The first came in footnote 7 on page 24 of the opinion. There the court stated:
“But see Section 21, second paragraph, of the PTUA as modified in 1985. [R. 794] That revision specifies that the Department may not require any increase in the rate of production or development “in excess of that required under good and diligent oil and gas engineering and production practices.” This section may well have applicability when determining the appropriate remedy when DNR rejects a proposed plan of development. See discussion, infra.”
The second came near the end of the opinion at page 42:
“Accordingly, this matter is remanded to the DNR for the purpose of according to the Appellants a hearing on the appropriate remedy to the State upon DNR’s rejection of the proposed 22nd Plan of Development. On remand, the agency should also consider the import of Section 21 of the PTUA, as amended in 1985, in determining the appropriate remedy.”
A statement like this is comparable to telling DNR they have the right to determine the remedy for a rejection of a POD, and Unit termination is one of those options, but the DNR should apply the standards in Section 21 to make that determination.
Subsequent to the issuance of the above opinion, recognizing what the court said about DNR’s authority to reject a POD and possibly terminating the Unit, the PTU Owners submitted a 23rd POD substantially committing to everything DNR had previously requested: an unequivocal commitment to bring the unit into production.
DNR granted the PTU Owners a hearing and considered Section 21 as the court requested but determined that Section 21 did not apply to its analysis of remedies. DNR then rejected the PTU Owners proposed 23rd POD and terminated the Point Thomson Unit without applying the standards set out in Section 21 of the PTUA.
With the above as background this document will now analyze the January 11, 2010 Superior Court Decision.
The second sentence in the first paragraph provides a concise statement of the next 30 pages of analysis, “…the contractual agreement between DNR and the Appellants precludes termination of the Point Thomson Unit in these circumstances without consideration of good and diligent oil and gas engineering and production practices, …” .i.e., the DNR did not consider the standards set out in the second paragraph of Section 21 as the court told them to do; therefore, DNR may not terminate the Point Thomson Unit.
In its analysis the court found that the interpretation of Section 21 is “dispositive of this appeal.” The PTU Owners argued that DNR was required to comply with the provisions of Section 21 and DNR argued that Section 21 did not apply to its remand proceedings.
If Section 21 does not apply to DNR’s POD decision, then the burden for coming up with an acceptable POD lies with the PTU Owners and DNR is not obligated to propose or identify conditions that would lead to an acceptable POD. If Section 21 applies to DNR’s review of remedies for a rejected POD, then DNR has a burden to identify conditions that would lead to an acceptable POD.
DNR proposed five reasons why Section 21 should not apply to its remand decision and the court systematically disposed of each. The crux of the Court’s decision came with its response to DNR’s fifth reason: an impermissible shift of burden to DNR to determine the appropriate rate of production. The DNR argued that if it were required to comply with the standards set out in Section 21, the agency would be inappropriately “saddled with the burden of designing an adequate POD.” The Court recognized that burden but considered it a reasonable contractual obligation for DNR to meet and in a footnote implied that DNR was not in as bad a position as it supposed and that DNR could probably require the Unit to go into production or be terminated.
The Court then determined that the PTU Owners did not receive a Section 21 hearing and that further proceedings were necessary.
The next issue the Court addressed was a due process concern. The PTU Owners argued that the dispute should be referred to an independent hearing officer or, in the alternative, the Court should grant a trial de novo. DNR argued that the due process concern should be addressed first before the trial de novo decision was made.
The court stated that “An impartial tribunal is basic to a guarantee of due process” and found a due process violation in DNR's process because the attorneys advising the Commissioner were the same attorneys that represented the agency on the first appeal and because Ms. Nan Thomson served as both the hearing officer at the remand proceeding and previously as DNR’s representative when the agency was defending its first decision in the 2007 appeal before the Court.
Once the Court made a finding of a due process violation the only remaining issue was whether the court should remand the matter to DNR for an administrative proceeding in accordance with this decision or retain jurisdiction and conduct a de novo trial. The court then gave both parties 30 days to submit additional briefing on this issue.
This places DNR in the interesting position of arguing to the Court that it should be granted the right to conduct a Section 21 hearing and that it can effectively apply the Section 21 standards to the issues before it when it had previously argued so vehemently that Section 21 standards should not apply. It will be interesting to see if the Court grants DNR the right to hold the hearing or if the Court has lost so much trust in the agency that the court retains jurisdiction and makes the determination itself.
In summary, the Court determined that the Section 21 standards applied to DNR’s decision requiring DNR to identify for the PTU Owners those conditions that the DNR considers necessary for approval of an acceptable POD, and if DNR is granted the right to conduct a Section 21 hearing, it must be conducted by an impartial hearing officer.
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