ALASKA STATE LEGISLATURE  SENATE JUDICIARY STANDING COMMITTEE  ANCHORAGE, AK  June 12, 2012 10:07 a.m. MEMBERS PRESENT  Senator Hollis French, Chair Senator Bill Wielechowski, Vice Chair Senator Joe Paskvan Senator Lesil McGuire Senator John Coghill MEMBERS ABSENT  All members present OTHER LEGISLATORS PRESENT  Senator Bettye Davis Representative Chris Tuck Representative Shelley Hughes Representative David Guttenberg COMMITTEE CALENDAR  POINT THOMSON SETTLEMENT: Analysis and Legal Issues - Donald Bullock Jr. Department of Natural Resources - Deputy Commissioner Joe Balash; outside counsel Jon Katchen and Matt Findley Department of Law - Attorney General Michael Geraghty -HEARD POINT THOMSON PLAN OF OPERATION: ExxonMobil -HEARD PREVIOUS COMMITTEE ACTION  See Senate Judiciary Standing Committee minutes 4/27/12. WITNESS REGISTER DONALD BULLOCK JR., Legislative Counsel Legislative Legal Services Legislative Affairs Agency Juneau, AK POSITION STATEMENT: Discussed legal issues related to the Point Thomson settlement agreement. MICHAEL GERAGHTY, Attorney General Department of Law (DOL) Anchorage, AK POSITION STATEMENT: Clarified aspects of the Point Thomson settlement agreement. JOE BALASH, Deputy Commissioner Department of Natural Resources (DNR) Anchorage, AK POSITION STATEMENT: Provided information and answered questions related to the Point Thomson settlement agreement. MATT FINDLEY, Attorney Ashburn and Mason P.C. Anchorage, AK POSITION STATEMENT: Answered questions as outside counsel to the state on the Point Thomson settlement agreement. JON KATCHEN, Attorney Crowell & Moring Anchorage, AK POSITION STATEMENT: Answered questions as outside counsel to the state on the Point Thomson settlement agreement. LEE BRUCE, Senior Project Manager Point Thomson project ExxonMobil Corporation Anchorage, AK POSITION STATEMENT: Delivered a PowerPoint and discussed the Point Thomson Plan of Operation. CHARLES MCKEE, representing himself Anchorage, AK POSITION STATEMENT: Testified during the Point Thomson hearing. WARREN CHRISTIAN, President Doyon Associated LLP Anchorage, AK POSITION STATEMENT: Testified in support of the Point Thomson project. JERRY MCCUTCHEON, representing himself Anchorage, AK POSITION STATEMENT: Testified that the only Alaska gas pipeline will be from Cook Inlet. BARBARA HUFF-TUCKNESS, Director Governmental and Legislative Affairs Teamsters Local 959 Anchorage, AK POSITION STATEMENT: Stated support for the Point Thomson project and thanked the committee for continuing the hearings. RICK ROGERS, Executive Director Resource Development Council (RDC) Anchorage, AK POSITION STATEMENT: Testified in support of settling the Point Thomson lease litigation and stated support for monetizing North Slope gas. BILL WALKER, representing himself Anchorage, AK POSITION STATEMENT: Clarified that he appealed Commissioner Sullivan's decision to enter into the Point Thomson settlement agreement because the process bypassed the public. JOHN MACKINNON, Executive Director Associated General Contractors of Alaska Anchorage, AK POSITION STATEMENT: Testified in support of the Point Thomson project. DAVE CHAPUT, Program Director Alaska Frontier Constructors (AFC) Anchorage, AK POSITION STATEMENT: Testified in support of the Point Thomson project. GARY DIXON Jr., Vice President Alaska Teamsters Local 959 Anchorage, AK POSITION STATEMENT: Testified in support of the Point Thomson project. KATHLEEN O'CONNELL, Vice President of Projects PRL Logistics, Inc. Anchorage, AK POSITION STATEMENT: Testified in support of the Point Thomson project. ACTION NARRATIVE    10:07:05 AM  CHAIR HOLLIS FRENCH called the Senate Judiciary Standing Committee meeting to order at 10:07 a.m. Present at the call to order were Senators Coghill, Paskvan and Chair French. ^Point Thomson Settlement: Analysis and Legal Issues 10:08:21 AM CHAIR FRENCH said his interest in the hearing today is to look at both the settlement agreement itself and the policy implications going forward for this and future projects. As DNR pointed out in a summary of the Point Thomson history, an agreement struck in 1983 had the unintended consequence of leaving Point Thomson undeveloped for decades. The obvious intention is to keep that from happening again. He said that the legality of the settlement is not in question today, but there will be discussion of the overall breaking point of that idea. The committee will also address the legitimate question that many members of the public have asked about whether a secret deal crafted between the administration and ExxonMobil is really in the public interest. He welcomed Mr. Bullock. 10:09:20 AM DONALD BULLOCK JR., Legislative Counsel, Legislative Legal Services, Legislative Affairs Agency, stated that he primarily does oil and gas work for the legislature. CHAIR FRENCH asked him to review the June 8, 2012 memorandum that he prepared. 10:10:16 AM SENATOR WIELECHOWSKI joined the committee. MR. BULLOCK cautioned that he was unfamiliar with and not prepared to speak about several things. He was not familiar with the particulars of the agreements made regarding the leases in Point Thomson or the negotiations between the Department of Natural Resources (DNR) and the Attorney General. He suggested the committee ask the parties directly about those issues. MR. BULLOCK said he looked at the authority of the attorney general to enter into settlements and agreed with what the committee heard during the April 27, 2012 hearing. In that forum, the attorney general has broad discretion to settle cases on behalf of the state. If the settlement takes place at the administrative level, the attorney general can advise the commissioner of DNR regarding a particular action to take; during the litigation phase, the attorney general has the authority to enter into settlements. 10:11:51 AM CHAIR FRENCH asked what the outer boundaries are for that general rule. MR. BULLOCK replied it is a separation of powers issue; the legislature writes the laws within which the attorney general and the commissioner can operate. The legislature passed AS 43.23.020, which specifically authorizes the attorney general to settle cases like this. CHAIR FRENCH asked if the legislature could modify the statute to authorize the attorney general to settle cases valued up to $5 billion, but anything above value that would require legislative approval. 10:12:58 AM MR. BULLOCK replied that would probably be challenged under the separation of powers doctrine. The scenario in which it would be a problem is if the executive branch negotiated a settlement that the legislature didn't approve, and the beneficiary of the settlement challenged in court the legislature's power to approve the contract. He said there was some confusion when the legislature passed the Alaska Gasline Inducement Act because it gave the commissioners of natural resources and revenue the authority to make a recommendation, which the legislature would then approve. Arguably, the executive branch had the authority to approve the AGIA contract without legislative confirmation. 10:14:15 AM CHAIR FRENCH asked if his analysis on that point extends to the Stranded Gas Development Act. MR. BULLOCK offered his belief that the SGDA suffers from that problem in addition to the issue of contracting away the power to tax. CHAIR FRENCH asked if he was saying that it was potentially unconstitutional when the legislature considered the AGIA contract that the Murkowski administration and ConocoPhillips, BP and ExxonMobil negotiated. MR. BULLOCK said yes; there probably would have been constitutional litigation based on the separation of powers, had the legislature withheld its approval. CHAIR FRENCH summarized that absent a constitutional change to give the legislature the authority to intrude into executive branch matters, the attorney general and the administration have the power to settle litigation with essentially no boundary. 10:16:41 AM MR. BULLOCK said the one exception is that the legislature has the power of appropriation; the legislature it can ask what the money is for and withhold part of all of the funds. However, the appropriation issue is probably irrelevant at Point Thomson. The issue is more about when the state will receive money from development of the resource. CHAIR FRENCH asked what the result would be if the administration agreed to a settlement that was clearly in violation of state law. MR. BULLOCK responded that any taxpayer in the state could challenge the action in court. He noted that Baxley v. State, which he mentioned in the June 8, 2012 memorandum, involved a citizen-taxpayer challenge to an action that was taken. He noted that the courts will generally defer to the discretionary action of a person in state government, subject to abuse of that discretion or some fatal flaw. A difference of opinion doesn't qualify. 10:19:13 AM SENATOR PASKVAN asked if the scope of the litigation was part of the question. MR. BULLOCK said yes. The litigation began because the commissioner of natural resources took the administrative position that it was time to break up the unit. That was appealed and in the context of the litigation the attorney general looked at where the best interests of the state lay. The action had gone on for more than seven years and what the state would ultimately gain was at issue. The attorney general did not act in the dark or independently, the commissioner of natural resources signed the settlement too. SENATOR PASKVAN asked if it was fair to assume that filing litigation would not give the parties carte blanche to decide any issue that may be tangentially related. MR. BULLOCK responded that the attorney general has both the statutory and common law authority to act in the best interests of the state. SENATOR PASKVAN questioned whether eliminating administrative procedures or limiting the scope of review might prospectively exceed the scope of litigation. MR. BULLOCK said the settlement agreement addressed that issue by including dispute-settling provisions. Any disputes under the agreement will be handled in the way that is discussed in the settlement agreement. Issues that are not within the settlement will continue to be handled in the normal means for handling administrative appeals for the department. 10:23:44 AM SENATOR MCGUIRE joined the committee. SENATOR PASKVAN asked if provisions in the settlement agreement prospectively limit what the AOGCC can look at. MR. BULLOCK said the settlement affects some things outside the settlement such as how to divide the state's royalty gas between Point Thomson and Prudhoe Bay if it is used to pressurize Prudhoe Bay. He noted that he addressed that thoroughly in the June 8, 2012 memorandum. There are also things that the settlement doesn't address and doesn't have the authority to mandate particular outcomes. He offered his belief that AOGCC is in that category. 10:25:47 AM CHAIR FRENCH expressed concern with the representations from the administration that the agreement generally self-executes and is without appeal. He asked Mr. Bullock if he had reviewed those parts of the settlement. MR. BULLOCK confirmed that he looked at those generally and they seem to be the result of policy decisions and agreements between the parties. The settlement recognizes certain issues and says that the actions they require will happen without further appeal. The parties gave up options they would otherwise have to reconsider what was happening and make decisions along the way in order to keep things moving forward. He opined that the purpose of the settlement was to relate to the management of the unit, through 2019 in some cases. CHAIR FRENCH read the following from paragraph 5.1.4 of the settlement agreement: Any Party may dispute whether a specified event has occurred that pursuant to the terms of this Agreement would result in termination of the Point Thomson Unit Without Appeal or release of acreage Without Appeal He asked what it meant to him as an attorney that "any party may dispute whether a specified event has occurred." 10:28:38 AM MR. BULLOCK said his response would be general, because he had not looked specifically at that paragraph. He relayed that under any settlement agreement certain actions are expected, but whether a particular action has taken place will be a factual issue. The impact of a particular action would be subject to the terms of the settlement because that is the consequence of an action, but there would still be a dispute as to whether something should have happened at a particular point and whether it did happen. CHAIR FRENCH asked what would happen under the following example. The agreement says ExxonMobil has to drill three wells within five years or the unit would be terminated without appeal. At the end of five years, the state says that ExxonMobil drilled just 2.5 wells and ExxonMobil says it drilled 3 wells. MR. BULLOCK said the issue is whether drilling to the targeted depth constituted a well, and that would have to be clarified. CHAIR FRENCH asked who would resolve that factual dispute. MR. BULLOCK said the parties would do it within the settlement agreement if the issue was addressed. CHAIR FRENCH read the second part of paragraph 5.1.4 as follows: In the event of such dispute, termination of the Point Thomson Unit Without Appeal or the release of acreage Without Appeal shall not be required until there has been a final judicial determination as to the occurrence of the specified event, or upon an Abandonment determination via arbitration under Paragraph 4.2.3, This Paragraph 5.1.4 does not apply to DNR decisions referenced in Paragraph 5.1.2(b). He asked if the factual determination of whether 2.5 or 3 wells were drilled would go to the commissioner or a judicial determination, and if the latter would be in a courthouse. MR. BULLOCK suggested he ask the attorney general and ExxonMobil what they envisioned. It is obviously a product of policy decisions and agreement between the parties as to what things the action of the agreement itself would settle, the disputes they anticipated, and how they would be resolved. CHAIR FRENCH asked if a final judicial determination would be done in a courthouse. MR. BULLOCK answered yes; it would be a judicial branch action. 10:31:50 AM CHAIR FRENCH said another concern is that the settlement agreement adopts a different definition of "major gas sale" than is used in the Prudhoe Bay operating agreement. He asked Mr. Bullock to summarize the analysis he gave in the June 8, 2012 memorandum. MR. BULLOCK stipulated that because he wasn't familiar with unit agreements and leases, he didn't fully understand the consequences of a finding that a major gas sale has occurred. The settlement agreement has lynch pins concerning whether there is a major gas sale or not, and for the purposes of Point Thomson, "major gas sale" is defined as 0.5 billion cubic feet per day (bcf/d). He said he did not know how that number was reached outside the context of a competing natural gas pipeline under the Alaska Gasline Inducement Act, which entitles the licensee to triple damages of qualified expenditures. He suggested the parties may have a better answer. CHAIR FRENCH said he found it odd and worrisome that the definition does not specify the amount of gas that must be moved. It says that a pipeline has to be built that is capable of moving a major amount of gas, but nowhere does it say that a major amount of gas actually has to be moved. Moving a few molecules satisfies the definition under the agreement. 10:35:47 AM MR. BULLOCK said a critical part of settlement is that an event triggers the state to take its royalty gas. That event is when gas is produced into the gas pipeline from Point Thomson to Prudhoe Bay. AS 38.05.182(a) guides the taking of the royalty in kind, which is consistent with the settlement agreement. What the settlement doesn't say is how much or even that the state is in the position to sell its gas. However, if gas is produced from Point Thomson and used to pressurize Prudhoe Bay, the gas effectively will be stored in the Prudhoe Bay unit until there is an opportunity for sale. CHAIR FRENCH commented that it was a highly interesting arrangement to move gas from the Point Thomson reservoir and inject it into the Prudhoe Bay reservoir. He asked if the state had the same one-eighth royalty interest in both reservoirs. MR. BULLOCK said he didn't know, but he'd heard comments that the royalty agreements vary in the Point Thomson leases. He added that the use of Point Thomson gas to pressurize Prudhoe Bay would not be considered for taxable purposes, as the production of gas. The settlement cites the regulation, but there is actually statutory authority for that. 10:39:39 AM SENATOR COGHILL observed that the settlement says that if a pipeline is built, the state could take its royalty in kind for either in-state use or for pressurization. MR. BULLOCK responded that the in-kind gas belongs to the state but if there isn't a place to put it, it will stay in the gas cap. The settlement agreement provides two options for what to do with Point Thomson gas. One is to cycle the gas, which would maintain the pressure in the Point Thomson reservoir. The other option is to take the gas off the unit, at least as far as Prudhoe Bay. SENATOR COGHILL expressed interest in knowing how Point Thomson gas that's used to pressurize Prudhoe Bay will be measured once it's produced. He said his understanding is that it would be another agreement. MR. BULLOCK confirmed that the terms of the agreement include a delivery point definition. He suggested asking DNR where the gas will actually be measured and accounted for. CHAIR FRENCH reiterated how different the definition of "major gas sale" is in the settlement agreement compared to the definition in the Prudhoe Bay operating agreement. The Prudhoe Bay operating agreement defines a major gas sale as the movement of at least 1.75 bcf/d of gas off the North Slope. He asked what major issues are not addressed in the settlement agreement and will still need to be resolved. 10:42:00 AM MR. BULLOCK said two things stand out. The first is how the state will account for and take its royalty for Point Thomson gas that is used to pressurize Prudhoe Bay, once the gas is produced along with other production. The other open question is specifically how the Point Thomson unit participants will work to get gas off the North Slope. This can be a problem because the interests of the state and the producers aren't always in alignment. It can be money in the bank for the producer to keep the reserve in the ground as long as the pressure isn't lost and AOGCC standards are followed. The state, on the other hand, needs money every year. 10:43:30 AM CHAIR FRENCH observed that it will be a recurring question about the agreement that DNR put AOGCC forward as the final overseer in protecting the state's interest against waste with regard to the decision for full field cycling or blowdown. He asked if the role of AOGCC is the same as DNR in making that determination. MR. BULLOCK answered that AOGCC has a separate function to look at the optimum development of the resource in order to maximize production. One of the issues in Point Thomson is that if the gas comes off too quickly, it may leave too many liquids behind. That is a concern of AOGCC and something it has authority over, not necessarily when the resource is produced. CHAIR FRENCH thanked Mr. Bullock for the overview. MR. BULLOCK reiterated that his focus in the review was to make sure that the royalty terms were consistent with the law and that the tax event was properly addressed. 10:46:13 AM CHAIR FRENCH welcomed Attorney General Geraghty. ^Department of Law MICHAEL GERAGHTY, Attorney General, Department of Law (DOL), said he agreed with Mr. Bullock's opinion, but wanted to clarify two issues. The first is that there was no intent to have the court review and approve the settlement agreement, although it was submitted to the court as part of the settlement papers to dismiss the case. Given the timing of the dismissal, it was unlikely that the court reviewed and approved the settlement, he stated. 10:48:34 AM The second clarification relates to the authority of the attorney general to settle cases that may abrogate certain aspects of state law. He agreed with Mr. Bullock's opinion regarding the authority of the attorney general, but did not believe that this particular agreement abrogates or abridges state law or DNR regulations. He noted that he addressed that to some extent in the letter he submitted. ATTORNEY GENERAL GERAGHTY noted that Mr. Bullock raised the question of how gas injected into Prudhoe Bay and eventually sold in a major gas sale will be allocated between the two reservoirs. The answer is that there is an agreement and allocation in place so it is clear when the gas goes into the pipeline, what goes to the state, what goes to the producers, and what, for example, is Point Thomson gas and what is Prudhoe Bay gas. CHAIR FRENCH asked if that agreement was separate from the Point Thomson settlement agreement. ATTORNEY GENERAL GERAGHTY answered yes. REPRESENTATIVE CHRIS TUCK joined the meeting via teleconference. 10:51:24 AM CHAIR FRENCH asked his view of the boundary of his authority as attorney general - the point beyond which an issue is too large or involves too much money for him to sign and announce a deal, without any public process or input. ATTORNEY GENERAL GERAGHTY answered that he didn't know, but he didn't believe there was a legal, dollar boundary. Cases worth hundreds of millions of dollars have been settled in the past, and the Point Thomson case doesn't have a specific dollar amount per se. CHAIR FRENCH pointed out that Point Thomson is worth at least a couple of billion dollars. ATTORNEY GENERAL GERAGHTY opined that the break point is not a dollar figure; it is the good judgment and discretion of the attorney general to approve a settlement. He said some things are better negotiated in private, but it was not his position that he would never consult with the legislature. 10:53:20 AM SENATOR PASKVAN asked why the administration didn't ask for legislative input after the agreement was crafted and during the several months that ExxonMobil took to present the terms to the working interest owners. ATTORNEY GENERAL GERAGHTY said his understanding is that all the interest owners were involved in the negotiations to some extent. He also opined that there was a substantive difference between sophisticated commercial entities discussing an agreement and approving it among themselves, and submitting such an agreement to the political branch of government. 10:57:01 AM CHAIR FRENCH said DNR pointed out in the June 7, 2012 letter that its decision in 1983 to remove the automatic termination provision from the unit agreement had an unintended consequence. The consequence of that modification was that the unit continued for decades without production. He questioned what might have happened in 1983 if that agreement had come in front of the legislature or been publicly reviewed, and if it could have saved the state 30 years of trouble. He said he hopes that the settlement agreement is without even a small flaw, but he wonders if such a large question shouldn't be reviewed by another set of eyes. ATTORNEY GENERAL GERAGHTY responded that it was strictly a DNR process in 1983 and DNR clearly had the authority to make that decision. There would have been no precedent to consult the legislature. Given the circumstances of this particular case, the settlement was handled appropriately. However, he was not taking the position that this was a blanket conclusion on all settlements. CHAIR FRENCH referenced paragraph 5.1.4 and asked his thoughts as to when the commissioner of DNR would have omnipotent authority to make things happen under the settlement agreement and when there would be a judicial determination. 11:03:14 AM ATTORNEY GENERAL GERAGHTY said his perception is that in certain circumstances there may be a right to challenge whether a factual event took place, but the consequences of the event cannot be challenged. They are without appeal. He described the settlement as a compromise that was probably the best the state could achieve under the circumstances. The arbitration provision was something the state actually asked for to avoid challenges of whether a lease was abandoned or not. The state wanted a strict, timely arbitration for that particular circumstance. He deferred to DNR for further details. CHAIR FRENCH asked if he had any concerns as an attorney that the agreement has no volumetric aspect for moving gas off the North Slope in order for there to be a major gas sale. ATTORNEY GENERAL GERAGHTY replied he didn't have any concerns as an attorney. As a practical matter, he couldn't see the producers making the investment required to ship even some gas off the North Slope for the sole purpose of meeting the requirement. 11:08:45 AM SENATOR PASKVAN referenced page 6 of the June 8, 2012 letter that says the settlement agreement provides that the working interest owners may sanction a major gas sale at any time prior to the end of 2019 in order to retain acreage. He asked why it should take so long to get just a decision and how it fits with the understanding that Alaska's natural gas resources will be developed timely. ATTORNEY GENERAL GERAGHTY said his understanding is that the timeframes were rigorously negotiated, and 2019 was the shortest timeframe that DNR could get. He said he shares the frustration but the scope and investment of these projects are huge. 11:13:38 AM SENATOR PASKVAN asked how it happened that the settlement agreement defines a "major gas sale" as just a molecule over 0.5 bcf/day, because that's not what Alaskans have been considering for the last 30 years. ATTORNEY GENERAL GERAGHTY said his perspective is that the producers do not have an interest in building a line that is only 0.5 bcf/d. It only makes economic sense to build the largest line reasonably possible. The interests of the state and the producers are aligned on that issue. He deferred to DNR for specifics. 11:16:10 AM CHAIR FRENCH recessed the meeting. 11:28:28 AM CHAIR FRENCH reconvened the meeting and welcomed DNR. ^Department of Natural Resources JOE BALASH, Deputy Commissioner, Department of Natural Resources (DNR), introduced himself, Jon Katchen, and Matt Findley. 11:30:18 AM MATT FINDLEY, Attorney, Ashburn and Mason, introduced himself and relayed that his company had been outside counsel to the state on Point Thomson since the litigation commenced in 2007. MR. BALASH thanked the committee for the opportunity to put in writing the points he didn't have time to cover in the April 27, 2012 meeting, and that he would be happy to provide written answers to any further questions that may arise regarding how the agreement came into being and the consequences moving forward. CHAIR FRENCH informed the listening public that Commissioner Sullivan and the three presenters were the team that crafted this agreement. MR. BALASH explained that the negotiations on the settlement agreement began with the prior administration. The legal milestones that occurred were the decision in 2008 by Judge Gleason, the remand, and the decision by Judge Gleason again in 2010. In between was the 2009 interim decision by then Commissioner Tom Irwin authorizing the drilling of wells PTU 15 and PTU 16 for the Initial Production System (IPS). CHAIR FRENCH asked when the first work on the settlement agreement commenced. MR. BALASH answered that the plan of development that was submitted in 2008 - POD 23, formed the basis of this IPS. It is the foundation and technical plan for the settlement. Commissioner Irwin rejected POD 23 for two reasons. One was the concern about the commitment of the working interest owners to follow through on the activities proposed in the plan. The second concern related to what would happen after the IPS came on production. The 2009 interim decision authorized those first two wells and set this path to put the IPS on production. 11:35:40 AM Following the 2009 interim decision was Judge Gleason's decision in 2010, which was devastating to the state's interests and ability to manage Point Thomson through the POD process. The state filed an interlocutory appeal with the Alaska Supreme Court. The petition was accepted and that probably helped crystalize and move along negotiations that began in 2009. CHAIR FRENCH commented that that didn't sound very good because ExxonMobil had the upper hand in the negotiations. He asked his perception. MR. BALASH said it was a struggle, but it was wind in their sails when the court granted the petition. That probably helped bring closure on what was a term-sheet level agreement. CHAIR FRENCH asked what term-sheet level agreement means. MR. BALASH explained that many of the key terms and features of the agreement were agreed upon in late 2010. At that time, the team consisted of former DNR Deputy Commissioner Marty Rutherford and then Attorney General Dan Sullivan from the Department of Law (DOL). He said that a term-sheet level agreement was reached at that stage. CHAIR FRENCH observed that the term-sheet agreement occurred at the low point of state's legal posture. MR. BALASH offered his perspective that it was the Alaska Supreme Court's granting of the petition for review that allowed the team to move as quickly as it did to that agreement. The state's resolve was not shaken; it was going to do whatever it took to get the field into timely production. That resolve helped result in an agreement that is quite strong. 11:38:50 AM SENATOR PASKVAN asked what the consequence would have been to the state if: 1) the supreme court had upheld the trial court on the petition for review and 2) the supreme court had overturned the trial court decision. MR. BALASH clarified that the interlocutory appeal came before the final decision from Judge Gleason in 2010. If the supreme court had upheld the original decision, DNR would have then gone back to Judge Gleason for finalization of her decision. That could have led to a Section 21 hearing under the agreement, which would have placed the entire burden on the state to identify and justify what should happen next in the development of the field. Had the decision gone in the state's favor, DNR would have gone back to Judge Gleason to reconsider the particular decisions and findings that related to Section 21 and who carried what burden. She would have formulated that and then issued a final decision. He expressed confidence that one party or the other would then have appealed to the supreme court on that final judgment. SENATOR PASKVAN said his assumption is that Judge Gleason determined that the state somehow erred in its termination process. He asked what DNR had done to avoid a similar error if it were to terminate a lease in the future. MR. BALASH said there were two points. First, the original dispute and decision in 2008 found that DNR did not provide sufficient notice to the working interest owners that termination was forthcoming, and that the remedy was termination of the unit. After 2008, there was a hearing where the working interest owners provided what they thought was the right POD and proper remedy in the event of a rejection. 11:43:49 AM In 2010, Judge Gleason found that the question of remedy was to hold a hearing conducted pursuant to Section 21 of the unit agreement. That was somewhat different from the discussion that took place in her court in 2008. SENATOR PASKVAN asked if DNR formally modified its procedures to make sure that the due process issue doesn't happen again if the state should decide to terminate a lease in the future. 11:45:31 AM MR. FINDLEY said Judge Gleason's rulings raised issues regarding how DNR implements its existing regulations and the specific things that happened. That does not imply that the regulations need to be changed. 11:45:49 AM JON KATCHEN, Attorney, Crowell & Moring, added that Section 21 of the Point Thomson unit agreement is unique. Judge Gleason read that the POD process flowed into a Section 21 process, which shifted the burden and then reversed how DNR manages land. No other unit agreement has a similar provision. CHAIR FRENCH asked when that unit agreement was crafted. MR. KATCHEN answered it was written in 1977 and amended several times in the early 1980s. CHAIR FRENCH asked when the term sheet was developed. MR. BALASH answered that it was an October 2010 agreement with just the operator. 11:47:22 AM CHAIR FRENCH summarized that it was a five or six page agreement between DNR and ExxonMobil that developed into the 85-page document that the legislature saw first on March 29, 2012. MR. BALASH recounted some of what took place after October 2010 as DNR and ExxonMobil continued negotiations. Following the November election, Governor Parnell went through a transition process and then Attorney General Sullivan became commissioner of natural resources. He essentially retained the portfolio on the negotiations and settlement. CHAIR FRENCH asked if this process accounted in part for Mr. Sullivan's transfer from the position of attorney general to commissioner. MR. BALASH suggested he ask the Governor. His understanding was that Mr. Sullivan demonstrated a broad understanding of the complex issues in the oil and gas arena to manage this and other cases. CHAIR FRENCH asked if any consideration was given to presenting this settlement agreement to the legislature for preview before finalization. MR. BALASH described the process that unfolded following the October 2010 term-sheet agreement. He said the negotiations and exchange of papers perhaps took longer than it should have, but the "fully papered" agreement was finalized in the summer of 2011. Commissioner Sullivan mentioned to a legislative committee that there was an agreement with the operator. It was at that time that the other working interest owners were apprised of the specific terms and the relative positions of both the operator and the state. CHAIR FRENCH recalled that the news reports at that time indicated some pushback from the other operators about their lack of involvement in the structuring of the settlement agreement. 11:50:15 AM MR. BALASH confirmed that there was some dissatisfaction. He continued to explain that the ongoing conversations clarified the need to find a means of monetizing North Slope gas in order to realize the value at Point Thomson. In the summer of 2011, ConocoPhillips and BP terminated their jointly sponsored Denali pipeline project, and it was in the fall of 2011 that the Governor started to make clear his willingness to pivot from the North American market to the LNG market in order to commercialize the state's North Slope resources. CHAIR FRENCH asked at what point in the process ExxonMobil announced it was joining TransCanada in its AGIA pipeline. MR. BALASH recalled that it was in the second quarter of 2009. CHAIR FRENCH asked if there was a connection between the Point Thomson settlement agreement and ExxonMobil joining forces with TransCanada to build a large-scale pipeline. MR. BALASH opined that there was nothing direct or specific, but it was fair to observe that ExxonMobil was looking for ways to work with the state to meet the state's goals and objectives represented through the AGIA license. MR. BALASH relayed that the Governor met with the CEOs of BP, ConocoPhillips and ExxonMobil early in 2012 to work to finalize the agreement and come to an understanding of how all parties would fit together, particularly in light of the state's relationship with TransCanada through the AGIA license. Commercializing North Slope gas via an LNG project was going to occur within the AGIA framework. 11:54:06 AM CHAIR FRENCH asked why DNR chose such a different definition of "major gas sale" in the settlement agreement than the definition under the Prudhoe Bay operating agreement. He also asked why the definition did not include specific volume requirements. MR. BALASH recapped the answer Attorney General Geraghty gave to the question and highlighted that the 1.75 bcf/d threshold in the Prudhoe Bay operating agreement was an agreement between and among the working interest owners, not the unit agreement to which the state is a party. To the extent that DNR looked to any particular frame of reference, 500 mmcf/d was identified in 2007 in the AGIA statute, and is double the amount that Alaskans need. The intention in setting the 0.5 bcf/d threshold in this agreement is to ensure there is room to meet Alaskans' needs, not to identify the minimum needed to retain the acreage. 11:57:43 AM CHAIR FRENCH said it was extremely troubling that the settlement agreement uses "major gas sale" as a functioning milepost throughout the document, but the definition in the agreement does not require the movement of more than a single molecule of gas off the North Slope. He acknowledged that it was unlikely that someone would build a pipeline that could carry more than 0.5 bcf and not move gas, but it was possible. ExxonMobil is arguably the most sophisticated company in the world, and it doesn't make a move without thinking ahead ten steps. The state doesn't have that capability. He asked to be convinced that his concerns were unfounded that when ExxonMobil agreed to the definition in the agreement, that it didn't put one over on the state. MR. BALASH asked him to consider the MPV reports in the AGIA finding that identified that size matters. It matters to the overall efficiency and economic performance of any investment by anybody. The Brookings Institution analysis recently confirmed that particular finding with regard to exports of Alaska North Slope gas to Pacific markets. CHAIR FRENCH said he was in complete agreement that to make money moving gas, the bigger the pipeline the better. He asked why the settlement agreement didn't define a major gas sale as 2 bcf/d or larger. MR. BALASH said the work done in 2008 and the findings document demonstrated that there is no way to predict with any certainty what the "right" number is. The placement of LNG into the market will occur over a number of years, so the issue is how big to make the pipeline before the deliveries start. He said that while the repeated use of the definition "major gas sale" is critical, the use of the term "project startup" is also important. That is when hydrocarbons enter the pipeline. He said that the results of the concept selection agreement between the parties and TransCanada are expected by the end of the year; at that time everyone will get a sense of the magnitude and scale of the project. He emphasized that it isn't the end of the discussion with these companies in realizing the full potential of the North Slope. 12:03:09 PM SENATOR PASKVAN asked if a first binding open season is expected under this concept. MR. BALASH said that LNG projects in North America typically do not develop through the use of a conventional open season. However, the AGIA licensee has an obligation to solicit the market every two years. That will happen by the end of this year. SENATOR PASKVAN noted that he said that this gas pipeline project would occur within the AGIA framework. His understanding was that there were statutory provisions under AGIA for a first binding open season. He asked if the intention was that those statutory provisions would be retriggered and result in a coupled tax structure for the first 10 years of production. 12:05:06 PM MR. BALASH said that with regard to this license, there is only one first binding open season and it occurred in 2010. The referenced upstream tax inducements have expired, and it would require legislative action for that particular inducement to be available again. CHAIR FRENCH asked if his view was that the opportunity for a tax freeze that was offered under AGIA has passed. MR. BALASH said yes. SENATOR PASKVAN asked for confirmation that the administration would not protest the removal of the royalty inducements under the AGIA statutes, so there would be no question that they would not apply to any pipeline operated through an AGIA framework. MR. BALASH replied he was not prepared to endorse that today, but would review that with counsel to make sure that amending a portion of the AGIA statute did not affect the contractual arrangement with TransCanada. He said he would provide a written response. SENATOR WIELECHOWSKI asked if the administration briefed or discussed the terms of the settlement with any legislators prior to settling the case. MR. BALASH answered he did not believe so. 12:07:43 PM SENATOR WIELECHOWSKI asked if a major gas sale, as defined in paragraph 2.16 of the settlement agreement, could be done outside of the AGIA process. MR. BALASH said yes. SENATOR WIELECHOWSKI asked if a major gas sale could be done under a small pipeline such as the one proposed in HB 9. MR. BALASH replied that the question will go to the size and throughput of the pipe. The legislature will authorize the construction of the project it wants, knowing the boundaries and consequences. SENATOR WIELECHOWSKI asked if under paragraph 2.16 a "large- scale pipeline" does not mean a small pipeline such as the bullet line proposed in HB 9. MR. BALASH said the intention of the agreement in that definition is to reserve the ability for the state to do whatever it needs to meet the needs of Alaskans. He opined that had HB 9 become law, some provisions within that statute would have prevented AGDC from eclipsing that 0.5 bcf/d threshold. It is a matter of speculation as to which words would have changed before it became law. 12:09:51 PM CHAIR FRENCH cautioned that if the legislature authorizes an in- state pipeline, it should make sure it does not have a design throughput greater than 0.5 bcf/d, because the state could inadvertently build the pipeline that ExxonMobil was supposed to build for the state. MR. BALASH said even if the state were to build a pipeline with a design throughput of 750 mmcf/d, this agreement says that ExxonMobil and the other working interest owners would then fall under the regular POD process. 12:11:28 PM SENATOR WIELECHOWSKI recalled that the AGIA statute prohibits state contributions towards a pipeline larger than 500 mmcf/d. He asked if that was correct. MR. BALASH replied that the project assurance provision allows TransCanada to receive a buyout if the state takes that kind of action on a competing project. If the state offers a specific tax or royalty deal or grants cash to a project, other than TransCanada, that exceeds 500 mmcf/d, it has violated that project assurance and is liable for the damages identified in the statute. SENATOR WIELECHOWSKI observed that there was no way the state could contribute to a gas pipeline larger than 500 mmcf/d and meet this requirement. MR. BALASH said the state could do that, but additional cost would attach. SENATOR PASKVAN asked if the additional cost the state would pay is according to the breach provisions of the AGIA contract. MR. BALASH answered he believed that was correct. 12:13:43 PM CHAIR FRENCH turned the discussion to full field cycling versus blowdown. MR. BALASH said the letter he submitted to the committee discussed the evaluation that DNR and DOL have undertaken since the 2008 PetroTel study was released. SENATOR PASKVAN returned the discussion to the previous topic. He asked if a state-supported in-state line with a design throughput of less than 0.5 bcf/d would violate some statutory provision or the Point Thomson settlement if it included an export component. He asked, "Can, for example, 0.3 bcf be exported?" MR. BALASH said the number that matters is how much gas goes through the pipeline leaving the North Slope, and how much North Slope gas is going through that pipe. Hypothetically, a 400 mmcf/d pipeline travels through the state. Gas is found either in the Yukon Flats or the Nenana Basin and another 200 mmcf/d is put into the pipeline at those points. The pipeline would be carrying more than 500 mmcf/d of gas, but not more than 500 mmcf/d of North Slope gas. Another variation is 400 mmcf/d of North Slope gas going through the system and 230 mmcf/d is used nominally to fill the Nikiski plant. That leaves 170 mmcf/d of North Slope gas that could be used in state. That is still well within the threshold regarding the license and the agreement. SENATOR PASKVAN summarized that an in-state line could be built using state dollars and 0.5 bcf/d could be exported. MR. BALASH said yes, as long as the amount of North Slope gas in the pipeline stays below 0.5 bcf/d. 12:17:11 PM CHAIR FRENCH asked Mr. Balash to discuss full field cycling versus blowdown. MR. BALASH said any talk about liquids and the potential loss of liquids should specify if the talk is about Brookian horizon liquids, natural gas liquids in the gas layer and reservoir at Point Thomson, or the oil rim that sits adjacent to the high- pressure gas reservoir and sands. CHAIR FRENCH suggested he take any discussion about the Brookian off the table, because it's not at risk. Regardless of what happens with the Point Thomson reservoir, Brookian oil will not be lost. MR. BALASH agreed that the Brookian oil could be developed by these working interest owners or somebody else, someday. CHAIR FRENCH clarified that this discussion was about Point Thomson liquids. They are unique and depending on how the field is developed, tens of millions of barrels of liquids may or may not come out of that reservoir. Not everyone knows what full field cycling and blowdown means, but it means enormous differences in liquid recovery. He asked him to talk about the differences. 12:19:54 PM MR. BALASH said the oil rim in particular will be technically challenging to recover. He noted that written correspondence submitted to the committee says that the potential for that thin oil rim is much smaller than was estimated in the 2008 PetroTel study. CHAIR FRENCH identified that as on page 25-26 of the June 7, 2012 DNR letter. Footnote 99 says there may be less oil than thought in the past, but it's still in the 300 million barrel region of oil available. MR. BALASH said the technical staff advises that that oil rim should be viewed as a potential upside as development plans move forward. MR. BALASH said that natural gas liquid condensate is the term generally used when talking about the liquids entrained in the gas. They're entrained at high pressure so they are in a gaseous state. When the condensate is brought to the surface and depressurized, the liquid falls out. It can then be recovered and moved through a conventional liquid pipe. CHAIR FRENCH asked if that liquid pipe will connect with the current Badami pipeline. MR. BALASH said yes. CHAIR FRENCH asked if the volume initially is expected to be between 10,000 and 20,000 barrels a day MR. BALASH said the commitment in the agreement to put the IPS on production will result in 200 mmcf/d of gas being cycled; liquid will be recovered and the dry gas reinjected into the reservoir. The expected result in the initial production system is 10,000 barrels per day of liquid recovered at the surface and moved through the pipeline. In the agreement, that has to be on production by year-end 2015. TAPS throughput will be impacted in 2016. CHAIR FRENCH asked how high the IPS could go. 12:23:37 PM MR. BALASH explained that the IPS will be designed to accommodate 200 mmcf/d, and depending on condensate yield rate, the 10,000 barrels could be higher or lower. In 2016 the working interest owners will begin to evaluate whether to expand cycling at the field or pursue one of the other two development paths. 12:24:30 PM CHAIR FRENCH noted that the June 8, 2012 DNR letter takes issue with the fact that Dr. Myers based his analysis on the estimates in the 2008 PetroTel study, because it was an initial study. He read the following from page 26: After completing this extensive review, the Division of Oil and Gas concluded that the potential amount of liquid condensate and oil that could be lost if Point Thomson were "blowndown" early for a Major Gas Sale would be significantly less [than] the estimates found in the 2008 PetroTel study that Dr. Myers and Mr. Walker rely upon. DNR cannot disclose the revised estimate because this information is protected under Alaska law. He said it raises another goosebump to see that secret data is being used to support the deal that was made in secret. He asked why he should have confidence. MR. BALASH said everyone recognizes the value of proprietary information, but he would be willing to explore the outer boundaries of what could be shared in confidence, if the committee wanted to do that. The negotiating team relied on the technical staff within the Division of Oil and Gas and the contractors they worked with to understand the information in order to make the policy choices that were made in the negotiation and resolution of this dispute. CHAIR FRENCH summarized that the physics of the reservoir and the complexities of the analysis aren't something that can be kicked around at this hearing. MR. BALASH said that is correct. He suggested thinking about the challenges both above and below ground and the consequences for each with regard to the ultimate viability of cycling on a larger scale. The way that the reservoir performs below ground and the way the equipment performs at the surface are both important. The 2008 PetroTel study just wanted to understand how the reservoir might perform and didn't consider the above ground constraints. 12:28:38 PM One of the scenarios brought 8 bcf/d to the surface and reinjected it at Point Thomson, but neither the cost of cycling that amount of gas nor the location of the pads and facilities was taken into consideration. The reservoir itself is below water in the shallow Beaufort Sea so it is a challenge. Another above ground constraint is the highly engineered machinery that is necessary to handle gas at extremely high pressure. MR. BALASH suggested the members think about it in terms of the way the USGS estimates resources. There is a resource estimate, a technically recoverable estimate, and an economically recoverable estimate. The 2008 PetroTel study is between the first and second estimates. How best to optimize recovery of hydrocarbons in the field, moves closer to the economically recoverable estimate. That is where the state relies on the expertise and financial interests of the working interest owners to help identify the broad link for development of that unit. DNR's perspective takes into account a broad range of things, whereas the AOGCC looks purely at the question of waste. The evaluation of whether to cycle Point Thomson at more than 200 mmcf/d and beyond 10,000 barrels of condensate recovery per day will begin in 2016. 12:31:56 PM SENATOR PASKVAN asked what duty the administration has to disclose to the legislature in the future, if the current confidential information materially changes. MR. BALASH reiterated his willingness to explore the bounds of the confidentiality agreements and obligations. SENATOR PASKVAN said he appreciated that, but he wanted to know what duty there is to disclose in the event that there is a material change in that information. MR. BALASH responded that under the agreement, the working interest owners have an obligation to share with the Division of Oil and Gas what they have learned and are thinking with regard to the defined objectives and pathways in the agreement. The results in 2016 will lead to further evaluation as to whether the state agrees with the direction and if it is consistent with the agreement and state law. There will be opportunity for that to be understood on the executive branch level and then with the legislative branch and broader public. However, it is likely that there will still be limits to what information becomes public. SENATOR PASKVAN asked what duty there is to disclose that there has been a material change. MR. BALASH deferred the question to counsel. MR. KATCHEN asked if he was asking about the duty of the working interest owners to disclose. SENATOR PASKVAN said he understands that in the agreement there is some obligation of the working interest owners to disclose information to the executive branch. He asked if there is a legal duty for the executive branch to disclose to the policy making legislative branch when there is a material change in substantive and factual information. MR. FINDLEY said he was not aware of any statutory or regulatory obligation or duty, but that didn't mean there shouldn't be communication. CHAIR FRENCH quoted Thomas Jefferson saying, "The price of freedom is eternal vigilance." and promised that the legislature will watch carefully to see if it would be better to reinject the gas. He offered his perspective that the state comes out ahead if the gas is cycled for a long time. The legislature may have to hire its own experts to be convinced about what the best way forward is. He asked how the settlement agreement handles the decision to do full field cycling or blowdown. MR. BALASH explained that post IPS there is provision in the agreement for a POD to be submitted. CHAIR FRENCH asked if he believes it will be public. 12:38:49 PM MR. BALASH replied he would have to look at the statute and regulations to see what becomes public and when, but notice and review processes for both plans of operation (POO) and plans of development (POD) will take place over the life of this agreement. DNR has agreed to approve the POD if it is consistent with the agreement, but in a blowdown scenario, the definition in the agreement describes the project as one that has gotten AOGCC approval. He declined to specify the order of those steps. 12:40:21 PM CHAIR FRENCH said the next line of questioning relates to enhanced oil recovery (EOR), specifically the difficulty of tracking Point Thomson gas when it is used to pressurize the Prudhoe Bay reservoir. He asked if the state royalty interests were the same in Prudhoe Bay and Point Thomson. MR. BALASH said no. The Point Thomson unit has a variety of leases; some are one-seventh, some are one-sixth, and some are net profit share leases. CHAIR FRENCH said it was his understanding that the accounting details have not been worked out. MR. BALASH clarified that some features will not change. Specifically, there has been no change to the Point Thomson royalty percentages in the leases and the resulting volumes in the EOR case. CHAIR FRENCH asked who will keep track of the volumes once the Point Thomson gas joins an undifferentiated mass of Prudhoe Bay gas and sits there for some period of time. MR. BALASH directed attention to the provisions on page 47, paragraph 4.16.2.4 of the agreement. When a volume of gas leaves Prudhoe Bay, 75 percent is Prudhoe Bay volume and 25 percent is Point Thomson volume. Within that 25 percent volume the working interest owners and the state will account the relative royalty share that has gone in. The agreement requires gas balancing agreements be struck to ensure that all parties, including the state, know whose gas is where and when. 12:44:49 PM CHAIR FRENCH reviewed subsection ii on page 47 and asked if the affected parties are Point Thomson and PBU working interest owners and the state. MR. BALASH answered yes. CHAIR FRENCH asked what "gas balancing agreement" means. MR. BALASH replied it is a standard feature of accounting for the gas in the field and who owns that particular gas. If the state were to sell its Point Thomson RIK gas in Prudhoe Bay to some third party, there would have to be some accounting mechanism for when that gas is put in Prudhoe Bay, when it is taken out, and under what circumstances it is taken out. CHAIR FRENCH said it was a fair answer, but he was still uneasy. MR. FINDLEY added that injecting nonnative gas into another reservoir and accounting for the molecules is not novel. The accounting is not a simple procedure, but it's not uncommon. He said the next question is what happens if the state wants to withdraw that gas. CHAIR FRENCH asked if he was talking about an option whereby the state says it wants its royalty gas from the Prudhoe Bay reservoir. MR. FINDLEY answered yes. The state can withdraw its royalty gas, but it has to live with the physical constraints of the reservoir and within the constraints that Prudhoe Bay is still an oil-producing field. The settlement contemplates an agreement, including the possibility of over balancing the 75 percent 25 percent split for a short period. He highlighted that this agreement also makes it clear that the various Point Thomson royalty rates attach when the gas molecules come out of Prudhoe Bay. 12:50:04 PM SENATOR PASKVAN asked if the provisions on page 47 apply to Alternative C, a pipeline for in-state use that is smaller than 0.5 bcf/d. MR. BALASH confirmed that the RIK gas allocation principles apply to Alternative C. Under the scenario that 1.2 bcf/d of gas is moved to Prudhoe Bay, roughly 200 mmcf is going to be saved as RIK gas. If a major gas sale project has not been sanctioned, these rules apply going forward. SENATOR PASKVAN said the public needs to understand that royalty in kind gas applies solely to Alternative C, and that the only way there will be an in-state line is if the state assumes some of the cost. MR. BALASH said how the state might use that in-state gas isn't defined, but DNR views it as added value to the state. Under an Alternative A scenario where a major gas sale project has been sanctioned and is moving forward, the state will have a royalty share of the gas that moves through that project, and it could be used for in-state purposes. He reiterated that these particular RIK provisions only apply to Point Thomson gas, not Prudhoe Bay gas. SENATOR PASKVAN reviewed the three alternatives. Under Alternative A the producers essentially sanction a major gas sale; under Alternative B the producers cycle at Point Thomson; under Alternative C Point Thomson gas is injected into Prudhoe Bay and that is the only option that triggers royalty in kind. MR. BALASH said that in an Alternative A scenario Point Thomson gas very likely will be moving into the system and provide opportunity to take that gas in kind or in value. 12:55:36 PM MR. KATCHEN clarified that the three options are not mutually exclusive. A major gas sale would not eliminate the other options. SENATOR PASKVAN highlighted that under Alternatives B and C, a large diameter gas pipeline may be many years into the future. MR. BALASH agreed. In an Alternative C scenario, the gas would be moved from Point Thomson to Prudhoe Bay and there would be an opportunity to market that gas to Alaskans by some means. A commitment in the agreement is that if by 2019 the working interest owners haven't committed to cycling and a major gas sale, the rough volumetric equivalent of Prudhoe Bay gas will be commercially available to Alaskans. 12:59:57 PM SENATOR COGHILL asked what has to happen to get to sanction of a major gas sale. MR. BALASH said the process to get to a sanction point is measured in years. Today, because permits are not in hand the boards of directors are not practically able to say yes, there will be a pipeline. The 2016 date is realistic and somewhat aggressive. 1:02:29 PM MR. FINDLEY added that the definition of "sanction" in paragraph 2.28 requires documentary evidence of corporate approvals, firm transportation service agreements, and necessary federal regulatory certificates that have been issued and accepted. CHAIR FRENCH said he had decided to formulate his questions about the aspects of the agreement that are within the total discretion of the commissioner versus judicial determination and submit them to both legislative legal counsel and DNR for a written response. He asked for summary comments. MR. BALASH said DNR feels this is a good agreement for the state. It achieves the objective of getting the field into production and it puts the working interest owners back on the clock. Either the resource will be produced or the state will get the land back. 1:07:54 PM Recess for lunch ^Point Thomson Plan of Operation: ExxonMobil 2:14:52 PM CHAIR FRENCH reconvened the meeting and welcomed Mr. Bruce who would deliver the ExxonMobil presentation. LEE BRUCE, Senior Project Manager at Point Thomson, ExxonMobil Corporation, stated that ExxonMobil and the Point Thomson unit owners are committed to putting in the Initial Production System (IPS). He delivered a PowerPoint and discussed the project accomplishments to date; a summary of the project and schedule; the project as it stands today; and the plans going forward to meet the production startup date in the winter season 2015/2016 and extending no later than May 1. Responding to a question, he confirmed the intention at startup is for ExxonMobil to begin cycling 200 mmscf/d of gas. He further explained that the project is located on the eastern flank of the North Slope, west of ANWR and 25 miles east of Badami. The location is remote, the environment is hostile, and there is limited access to any established infrastructure. Supplies are delivered by ice road and barge and personnel travel by helicopter. 2:20:01 PM He highlighted that Point Thomson represents about 25 percent of the discovered North Slope natural gas resources and that ExxonMobil is committed to the long-term, responsible development of these resources. He reviewed the progress on wells PTU-3, PTU-15, and PTU-16 on the Central Drilling Pad starting in July 2008 and that drilling in the hydrocarbon zone is limited to November 1 to April 15 due to permitting requirements from the North Slope Borough and the Department of Environmental Conservation (DEC) to facilitate clean up in the event of a spill. These rules continue in the yet to be approved North Slope master plan. MR. BRUCE reviewed the field layout and infrastructure, which is all that will be needed outside of expanding for the next phase. About 12 miles of road will be permitted to connect the outlying east and west pads to the 56-acre central pad. This is specific to ExxonMobil's operations at Pt. Thomson; no road will connect to Badami. Site developments include a gravel mine, an airstrip that can handle a Hercules-sized aircraft, and water reservoir. 2:33:49 PM CHAIR FRENCH asked when the developments depicted in slide 5 would actually be on the ground at Point Thomson. MR. BRUCE answered that the gravel and infrastructure will be installed by the winter season 2014/2015, but not the facilities. Gathering lines will bring gas from the east and west pads to the central pad so it can be treated. The export pipeline, which is in the same right-of-way as the west gathering line, will go on to Badami. Responding to a question, he confirmed that the export pipeline will have typical pressures, whereas the gathering lines will be very high pressure. Due to the corrosive flow stream at Point Thomson, carbon steel lined pipe from Germany will be used. 2:36:11 PM MR. BRUCE reviewed the plans for the initial production facility on the central pad that will be in place winter season 2015/2016. The scope is to produce 10,000 barrels/d of condensate into TAPS, cycling 200 mmcf/d of natural gas at 10,000 psi. He highlighted that this will be the highest pressure cycling project in the world. SENATOR PASKVAN asked for a definition of "cycling" and other terminology. MR. BRUCE explained that cycling is the process of producing oil and gas from the ground. The liquids are separated from the gas and the residual gas is then compressed to reservoir pressure and reinjected. The produced condensate or liquids are treated to meet pipeline-quality specifications and pumped into the pipeline to join Badami and then on to TAPS. He explained that the Point Thomson reservoir underlies the Beaufort Sea. Extended-reach drilling techniques will be used to enter the reservoir. The reach is 9,000-13,000 feet. He noted that prior to PTU-15 and PTU-16, 19 wells were drilled in the Point Thomson area in efforts to gain a better understanding of the geology and resource. 2:42:20 PM SENATOR PASKVAN asked the maximum gas capacity and the capacity for processing liquids. MR. BRUCE answered the design gas capacity is 200 mmcf/d and the design liquids capacity is 10,000 barrels/d. The treatment facility design is for these capacities. CHAIR FRENCH commented that this appears to be an enormous investment to produce a modest amount of oil. He questioned how much capacity can be added for oil production in the future. MR. BRUCE responded that capacity can't be added to this facility. He added that part of this project is to determine the next step by better understanding how the resource reacts in a cycling mode, the connectivity of the wells, and what it takes to work in this remote environment. CHAIR FRENCH asked if production and injection will take place in the same or different locations. 2:45:57 PM MR. BRUCE answered that they take place in different locations in order to sweep the reservoir, and a producer well is paired with an injector well. For example, if PTU-15 is an injector then PTU-16 can be a producer. The settlement agreement requires a third well by the winter season of 2016/2017. That will be the west pad well. He reviewed the timeline and recapped the status of the project. The detailed engineering for the IPS facilities is about 40 percent complete and the engineering for the pipeline and gravel infrastructure is essentially finished. The expectation is that the final EIS will be published in July and the Corps will issue the record of decision on September 21. Civil and pipeline construction can begin thereafter phased over two seasons. Module installation will take place in the summer of 2015 and additional drilling will take place in the winter season 2014/2015. The latter is for a saltwater disposal well, completion of PTU-15 and PTU-16, and the west pad well. MR. BRUCE outlined the construction goals for the upcoming winter season, January through mid to late April. CHAIR FRENCH asked how many jobs will be created by the upcoming construction season. MR. BRUCE estimated it would be about 600 jobs. He continued to describe the project sequencing until startup in April 2016, as described in the plan of operations. 3:07:31 PM CHAIR FRENCH again mentioned that the facility as described doesn't have the space to accommodate additional capacity in the future. MR. BRUCE responded that the existing facilities will be used in conjunction with the yet to be identified next phase. He then displayed a contractor tree with ExxonMobil at the bottom followed by WorleyParsons FLUOR and many in place subcontractors. Aside from Haskell Corporation, all are Alaska based. SENATOR WIELECHOWSKI asked how many people will be employed in the next year and what percent will be Alaska hire through the contractors and subcontractors. MR. BRUCE answered that he could not give a percentage, but there is a content requirement for Alaskans and North Slope Borough residents. About 80 people are working on the project team; half are employees and the rest are experts and contractors. More people are working on the project itself, but the day-to-day hiring has not been done. He reiterated that the workforce is expected to peak at about 600. SENATOR WIELECHOWSKI asked what steps ExxonMobil is taking to ensure that the subcontractors are hiring Alaskans. MR. BRUCE said the contracts have requirements to maximize Alaska hire and ExxonMobil is working with contractors to ensure those requirements are met once hiring starts in several months or the fourth quarter. However, this is dependent on getting the permits. MR. BRUCE reviewed some of the community engagement and consultation that has taken place and noted that Appendix I in the plan of operations has 4-5 pages of the interactions with residents of the North Slope Borough. He highlighted the direct benefits to the state from the Point Thomson project and concluded that the IPS lays the foundation for future gas monetization on the North Slope. ExxonMobil's vision is to distinguish the project with superior performance, be a good neighbor and partner, and build trust with the State of Alaska. 3:18:34 PM CHAIR FRENCH thanked Mr. Bruce and recessed the meeting. 3:25:50 PM CHAIR FRENCH reconvened the meeting and opened public testimony. 3:25:59 PM CHARLES MCKEE, representing himself, reviewed the materials he was entering into the record including his ownership letter and letter of sovereignty, a statement from the Congressional Record in 1934 by Lewis T. McFadden, and pages from the fourth edition of Black's Law Dictionary. He referenced earlier testimony, mentioned the palming off doctrine, and raised the question of a conspiracy chain. He relayed that when he worked on the pipeline he witnessed the secrecy-shrouded delivery of a scale model of the complete pipeline that included a gas pipeline running alongside the oil pipeline. That model was destroyed, the actual pipe disappeared, and the gas line was never built. It was a lost opportunity, he said. 3:31:56 PM WARREN CHRISTIAN, President, Doyon Associated LLP, stated that Doyon is a union pipeline construction company and part of Doyon Limited whose shareholders mostly reside in Alaska. In past construction projects they attained over 90 percent Alaska hire and over 30 percent Alaska Native hire and used local Alaska companies to every extent possible. He stated support for the Point Thomson project, which will help ensure a healthy economy via increased flow through the pipeline and an opportunity for contracts and employment. Doyon Associated will directly hire over 200 employees over the next two years in support of this project in addition to the Alaska subcontractors and vendors it will utilize. This project will also provide an opportunity to train the next generation of Alaskan construction workers with the help of the individual union apprentice programs and the Fairbanks training facility. 3:34:21 PM JERRY MCCUTCHEON, representing himself, said the law of oil and gas production is that maximum recovery can only be had when a reservoir is produced at or above the bubble point. Because there is no exception to this law, the only Alaska gas pipelines will be from Cook Inlet to the Donlin Creek Mine and possibly one from Cook Inlet to Fairbanks. A gas liquids pipeline will run from Prudhoe Bay to Cook Inlet and the lower leg may be a gas pipeline from Cook Inlet to Fairbanks. He said that beginning in 1974 ExxonMobil said that Prudhoe Bay would produce only 9 billion barrels of oil with or without a gas pipeline, which flew in the face of all known reservoir action. Even when challenged with engineering facts they would not back down. That falsehood persists today, even though Prudhoe Bay has produced more than 6 billion barrels of additional oil because no gas line was constructed, and more will be produced. Even the AOGCC in 2008 testified that the state would be broke today if the gas pipeline of the 1980s had been constructed. MR. MCCUTCHEON cautioned that Alaska is nothing more than a cash cow to ExxonMobil or any other oil company. 3:39:12 PM BARBARA HUFF-TUCKNESS, Director, Governmental and Legislative Affairs, Teamsters Local 959, thanked the committee for continuing the hearings; they have elicited valuable information. She stated for the record that Teamsters Local 959 is not part of the litigation, but is excited about the job opportunities the members and employers statewide. CHAIR FRENCH asked how many local 959 employees will work at Point Thomson project. MS. HUFF TUCKNESS said she's been told that about 100 members would be employed. She also extended thanks for the ongoing funding for the Fairbanks Pipeline Training Center. 3:42:27 PM RICK ROGERS, Executive Director, Resource Development Council (RDC), said RDC is grateful that the Point Thomson lease litigation has been settled because it has been one of the barriers to monetizing North Slope gas. The settlement appears to be a commercially reasonable agreement with firm timelines and work commitments as well as significant consequences for failure to perform. It also has flexibility to accommodate the unknowns. He said ExxonMobil and the other leaseholders are among the best-capitalized and technically capable companies in the world, and that is required in a project of this magnitude. It is now possible to move forward. He extended thanks to the administration, the leaseholders, and this committee. 3:47:45 PM BILL WALKER, representing himself, said he wanted to clarify the reason that he appealed Commissioner Sullivan's decision to enter into the Point Thomson settlement agreement. He said he doesn't have an issue with ExxonMobil or those who negotiate on behalf of the state. He was challenging the fact that it was done outside the public process. He said he was an aggressive proponent of developing Point Thomson and he applauded those who were moving forward to do some development after 47 years. However, the settlement meandered beyond the core issue of the litigation, and was presented as a final deal. He said he believes there is already too much confidentiality in the state on issues associated with oil and gas development. The public and the legislature need to know more about what is happening. Negotiating the settlement behind closed doors was a quantum step in the wrong direction. 3:53:50 PM JOHN MACKINNON, Executive Director, Associated General Contractors of Alaska, said this is a construction trade association with roughly 650 members. He relayed that he first met with ExxonMobil about four years ago to discuss how to maximize Alaska hire and the use of Alaskan contractors on this project. ExxonMobil committed to try to maximize the use of Alaskan companies and they fulfilled that commitment. He said he was pleased that the litigation was settled and would like to see Point Thomson move forward to construction this winter. 3:56:01 PM DAVE CHAPUT, Program Director, Alaska Frontier Constructors (AFC), and Board Member, Resource Development Council, said that for the last few years he has worked with ExxonMobil on the Point Thomson project. He was testifying to highlight the excellent job that ExxonMobil has done with regard to the safety and health of the Alaskan workforce and protection of the environment. The AFC workforce is looking forward to going to work at Point Thomson helping to bring North Slope resources to market. 3:57:49 PM GARY DIXON JR., Vice President, Alaska Teamsters Local 959, said that 150-200 teamsters will be employed on the Point Thomson project at the peak. He talked about the union apprentice program and the recruitment efforts in Alaskan communities. Apprentices have a trade and can fulfill a good working career on the North Slope. Point Thomson will provide a great opportunity for the members and he is appreciative. 3:59:22 PM KATHLEEN O'CONNELL, Vice President of Projects, PRL Logistics, Inc., said that PRL recently received two large contracts with the Point Thomson project to transport materials and people. She explained that PRL does not have assets so it will use more than 25 companies to execute the two contracts This is the way that ExxonMobil allows one company to manage the work that leverages the powers of other companies. PRL is an Alaskan-owned company that is currently 100 percent Alaska hire. It is committed to responsibly developing Alaskan resources. 4:01:35 PM CHAIR FRENCH asked how many people are directly employed by PRL. MS. O'CONNELL said PRL currently has about 20 employees and growth is anticipated during the course of the contracts. She reiterated that the real power of PRL is its ability to leverage all the other companies. 4:02:30 PM CHAIR FRENCH closed public testimony and thanked everyone for coming to the meeting. 4:03:13 PM There being nothing further to come before the committee, Chair French adjourned the Senate Judiciary Standing Committee meeting at 4:03 p.m.