MINUTES  SENATE FINANCE COMMITTEE  April 24, 2007  9:05 a.m.    CALL TO ORDER  Co-Chair Bert Stedman convened the meeting at approximately 9:05:53 AM. PRESENT  Senator Lyman Hoffman, Co-Chair Senator Bert Stedman, Co-Chair Senator Charlie Huggins, Vice Chair Senator Kim Elton Senator Joe Thomas Senator Fred Dyson Senator Donny Olson Also Attending: MARCIA DAVIS, Deputy Commissioner, Department of Revenue; ANTHONY SCOTT, Commercial Analysis, Division of Oil and Gas, Department of Natural Resources; Attending via Teleconference: There were no teleconference participants. SUMMARY INFORMATION  SB 104-NATURAL GAS PIPELINE PROJECT The Committee heard a sectional analysis of the bill through Section 43.90.130(6) added by Section 1 from the Department of Revenue and the Department of Natural Resources. The bill was held in Committee. 9:09:49 AM CS FOR SENATE BILL NO. 104(JUD) "An Act relating to the Alaska Gasline Inducement Act; establishing the Alaska Gasline Inducement Act matching contribution fund; providing for an Alaska Gasline Inducement Act coordinator; making conforming amendments; and providing for an effective date." This was the second hearing for this bill in the Senate Finance Committee. 9:10:23 AM MARCIA DAVIS, Deputy Commissioner, Department of Revenue, testified that she would provide a sectional analysis of the Senate Judiciary Committee substitute, which has retained its "key structures" through the committee process. 9:11:13 AM Ms. Davis characterized the bill, also referred to as the Alaska Gasline Inducement Act, or AGIA, as follows. It's essentially government taking a soft touch. It's government stepping in an looking at a situation that has not moved on its own under normal market forces and for whatever reason either because of the structure of the ownership patterns at Prudhoe [Bay oil fields], the structure of global gas markets or simply the time has not come. But one thing that has come is the time for the State of Alaska to do whatever it can do to move the gas and ensure that the time for the revenue stream flowing from that gas happens at the soonest moment feasible given market conditions. 9:11:54 AM Ms. Davis shared that this bill was designed to provide several inducements for "two pieces" of a gas line. One of which would induce construction and the other would ensure the success of the natural gas pipeline by inducing resource owners to commit gas to that pipeline. 9:12:20 AM Chapter 90. Alaska Gasline Inducement Act. Ms. Davis began detailing each section of Chapter 90, added to AS 43 by Section 1 of the bill. Article 1. Inducement to Construction of a Natural Gas Pipeline in this State. Section 43.90.010. Purpose. (page 1, line 9) Ms. Davis asserted that the purpose of this legislation had not changed during the committee process. It was designed to facilitate commercialization of North Slope gas resources, promote exploration and development of oil and gas reserves, and as constitutionally mandated, maximize the benefit of that gas resource to the people of Alaska, as well as encourage oil and gas lessees to commit gas to that pipeline. 9:13:21 AM Article 2. Alaska Gasline Inducement Act License. (page 2, line 6) Ms. Davis stated that this article would specifically establish the inducement structure. 9:13:36 AM Section 43.90.100. Gas project. (line 7) Ms. Davis explained this language would provide for the grant of an Alaska Gasline Inducement Act license to a party that applies under the provisions of this chapter and meets the requirements set out in the chapter. 9:13:47 AM Ms. Davis noted an important addition in the language of subsection (b). Federal law provides that a state could not interfere with the construction of a pipeline that traverses across state lines. This subsection is intended to assuage the perception by some that no pipeline could be constructed without the license. 9:14:34 AM Co-Chair Stedman asked whether a party that unsuccessfully applied for a license under AGIA would be precluded from constructing its own pipeline. Ms. Davis answered that it would not. 9:14:55 AM Section 43.90.110. Natural gas pipeline project construction inducement. Ms. Davis highlighted the key inducement of a grant of up to $500 million provided in two phases. The first portion could not exceed 50 percent of the total grant award and would be granted prior to open season. "Open season" pertains to the process in which natural gas resources would be committed to the pipeline. The provision of this phase of the grant had initially required a mandated 50 percent matching contribution from the licensee. The current version of the bill stipulates that the match would be "up to 50 percent" with the exact percentage established by the applicant in its proposal. 9:15:35 AM Ms. Davis continued that after the open season had concluded, the remaining portion of the grant funds would be awarded. The grant would be calculated as an 80 percent match to the applicant's contribution. The amount would be established by the applicant in its proposal. 9:15:54 AM Ms. Davis gave a "frame of reference" for the dollar amount. The estimated cost to progress from the grant of the license to the open season has varied from $50 to $80 million up to $400 million. The lower estimate was cited by a party that already held a license and proposed to amend that license. The higher estimates were provided by a producer and by an independent pipeline company. The amount of the State contribution in the first three years after the grant of the license, according to these estimates, would be $40 million to $200 million. The provisions of this bill would allow the applicant "up to 36 months" from the date the license was issued to initiate the open season. 9:16:53 AM Ms. Davis stated that after the open season, the remainder of the cost associated with the process to obtain certification by the Federal Energy Regulatory Commission (FERC), has been estimated at up to $1 billion. The total State contribution would be limited to $500 million and would be subject to the amount proposed by the applicant. 9:17:45 AM Senator Thomas returned to Section 43.90.100(b), noting that nothing would preclude a party other than the winning applicant from constructing a natural gas pipeline. He asked if this language would provide that the party would be ineligible to receive "special treatment" from the State in its efforts. Ms. Davis clarified that this provision would not prohibit the State from granting tax or royalty relief or other incentives. However, doing so for a competing pipeline project would incur a financial consequence to the State. 9:18:39 AM Senator Thomas indicated he would further review this provision later. 9:18:49 AM Senator Elton understood the licensee would submit an application to the Executive Branch for reimbursement of up to $500 million. The Executive Branch would request an appropriation from the Legislature in the same amount. 9:19:20 AM Ms. Davis replied that Senator Elton correctly explained the first step of the process. A provision of AGIA would provide for a special fund established by the Legislature and from which reimbursements would be paid. Therefore, the Legislature would appropriate the funds, although not specific to each submission. 9:19:46 AM Senator Elton asked if the expectation would be that the Legislature would appropriate the entire $500 million to the special fund at once or in smaller amounts over time. Ms. Davis responded that the appropriations would be expected to be made "piecemeal". 9:20:05 AM Senator Huggins cited language from Section 43.90.110(1) on page 2, line 17, which read in part as follows. "…state matching contributions in an amount not to exceed $500,000,000, paid in total to the licensee over a five- year period; the payment period may be extended by the commissioners under an amendment or modification of the project plan…" Senator Huggins asked for examples of scenarios that would justify an extension and whether a limit would be imposed on the length of time an extension could be granted. 9:20:29 AM Ms. Davis answered that the language of the bill stipulates no "backstop date for the filing for the FERC certification process". The Senate Judiciary Committee had expressed concern that "reasonable and appropriate" circumstances could occur during the period between issuance of the license and receipt of FERC certification that could require more than five years. The committee intended to avoid an applicant "behaving in an economically irrational fashion" by incurring expenses earlier than prudent for the purpose of qualifying for the State reimbursement. Rather costs should be incurred "in a rational way that makes sense for the process." Ms. Davis informed that the bill contains a provision relating to "when can the project plan, which is captured in the license, be modified". She would explain this provision to allow for modification in circumstances that would improve the net present value to the State, where required by changes by the Alaska Oil and Gas Conservation Commission (AOGCC) "gas off take rules", and in situations "where the conditions were unexpected and out of the control of the applicant". 9:22:46 AM Ms. Davis noted the aforementioned conditions were the three for which a deadline could be extended or modified. 9:22:57 AM Senator Huggins requested additional insight on potential conditions that would be beyond the control of the licensee. 9:23:11 AM Ms. Davis gave the following response. The pipeline company is going to do everything in its power to develop the economics, the design, all of the appropriate bone structure around their project so that when they go to an open season and ask the market, the shippers, to enter into a commitment to ship gas on their line, they've given those shippers a good solid, but still an estimate because the pipeline still hasn't been built, such that shippers would come forward. There will be two situations: one, they'll ship, and two, they won't ship. If they chose not to ship it could be for two reasons: one is that despite the best efforts of that pipeline company, they have not given enough assurance to that shipper that they've nailed the economics - that they've properly handled the cost overruns, etc. In that situation you'd be looking at a shipper who still hasn't been convinced that that project is economic and that they're willing to enter into that contractual commitment. There's another situation where a shipper might not tender their gas. That would be because their own personal economics or personal politics might require them to not tender the gas because they are looking doing something else at a different timeframe or in a different setting. In that situation, you've got a pipe company that has essentially done everything reasonable - everything appropriate that they need to do and there's really not much more they can do on the front of proving up their economics, proving up the case for their pipeline company, if that gas is still being withheld. In that instance, the FERC has stated under the Alaska Natural Gas Act, that they consider this gas critical to the nation, critical to its energy supplies and that they would proceed notwithstanding the lack of a commitment of that gas to that pipeline. However, it's a slightly different process. It's perhaps a longer process and will involve more congressional involvement. That's a situation where we would envision that the Administration, as well as the pipe company should hold firm - keep their feet on the line, and move that project forward. But it might take a longer period of time for them to get to that FERC certification process. So we're trying to make sure that we have given all the support we can to a pipeline company to proceed in good faith and with good science and good economics and when they do so, stick with them to get them through that process. Since we're asking them in return to commit that they will go through an open season and if it's unsuccessful, progress onto a FERC certificate notwithstanding that. 9:26:00 AM Senator Huggins expressed that Ms. Davis' comments were disconcerting because of previous discussions on the cost to extend the project. An extension would "up the payment level to 80 percent in the period when we're extending the project", which would be counterintuitive in that it would increase the expenditure and the length of the project. He did not have a solution to this risk factor. 9:26:47 AM Ms. Davis noted a mitigating factor would be that the funds reimbursed after the initial five-year time period would be "later in time" and would incur a minor "time, value and money" benefit. This benefit would not counterbalance Senator Huggins's concerns. 9:27:17 AM Co-Chair Hoffman asked if discussions about the funding source of the $500 million grant had been held and whether the source would be general funds, the Constitutional Budget Reserve (CBR) fund, the Permanent Fund Earnings Reserve Account, or other sources. 9:27:40 AM Ms. Davis reported that no such discussions had yet been held on this matter. 9:27:56 AM Ms. Davis resumed her analysis of the sections of the bill, noting that language of Section 43.90.110(1)(C) on page 2, line 31 through page 3, line 8, describes and defines the types of expenses that would be eligible for reimbursement. The expenses had been "carefully delineated" to identify "those that are directly and reasonably related to obtaining a certificate or amended certificate of public convenience and necessity". Specifically excluded would be overhead costs, litigation costs, assets, and work product that predated the issuance of the license and civil or criminal penalties and fines. 9:28:45 AM Co-Chair Stedman directed attention to Sec. 43.90.100(1)(B) on line 26 through 30 that reads as follows. (B) after the close of the first binding open season, the state shall match the licensee's qualified expenditures at a level specified in the license; however, the state's matching contribution may not be greater than 80 percent of the qualified expenditures incurred after the close of the first binding open season Co-Chair Stedman questioned the use of "shall" versus "may", posing that the State could "have a different opinion at that time." 9:29:12 AM Ms. Davis characterized this as the "promise" the State would make to potential applicants that "this is the terms for which we are holding out and asking you to make an offer to us to build our pipeline." The intent is to induce an offer from a party to commit its time and funds to build a pipeline. In return, the State would match funds up to 50 percent based on the proposal by the successful applicant. Originally the language of this provision stipulated the match would be 50 percent. 9:30:21 AM Ms. Davis explained that once the applicant has submitted an offer, the Administration has reviewed it and the Legislature has accepted it, the matching funds would be committed. This is akin to a contractual agreement. 9:30:59 AM Senator Thomas, referencing the qualified expenditures listed in Section 43.90.110(1)(C), asked if certain litigation expenses relating to disputes over the open season should be allowed. 9:31:30 AM Ms. Davis responded that a determination was made that the State funds would be better invested in matching contributions made directly to the project, thus avoiding any debate over qualifying expenditures. While some litigation costs could be reasonably incurred by the licensee, delineating those from other litigation costs could be difficult. 9:32:28 AM Senator Dyson appreciated the notation of the changes made by the committees that previously heard the bill. He requested the testimony include comment as to whether the Palin Administration supported the changes. 9:33:09 AM Co-Chair Stedman announced he would direct the Administration to prepare a comparison of the amendments to the bill made by the Senate Resources Committee and the Senate Judiciary Committee. 9:33:51 AM Senator Dyson repeated his request for the Administration's position on the changes; especially those changes which the Administration deemed "not helpful" to the intent of AGIA. 9:34:08 AM Co-Chair Stedman remarked that the comparison could include a column indicating the Administration's support or opposition to the amendments. 9:34:15 AM Senator Dyson surmised that the Co-Chair would not permit the witnesses to provide this information in the present setting. 9:34:27 AM Co-Chair Stedman stated that such comment would be allowed. 9:35:04 AM Ms. Davis continued, pointing out that the second inducement the State would provide to the licensee is listed in Section 43.90.110(2) on page 3, lines 9 and 10, and reads as follows. (2) the benefit of an Alaska Gasline Inducement Act coordinator who has the authority prescribed in AS 43.90.250. Ms. Davis explained the position that would be created to assist the licensee. Concern had been expressed by industry representatives that this benefit would act as a de facto deterrent for other potential pipeline projects. If a competing project did not have representation of this coordinator, the concern was that the State could deny permits to the competitor. 9:37:06 AM Senator Huggins voiced confidence that the Administration would make every effort to accommodate any competing projects. He had been told that the State pipeline coordinator position would be "tailored" after the similar federal position. Ms. Davis affirmed. Senator Huggins pointed out however, that the federal pipeline coordinator position was charged to assist with any pipeline project, while the State position proposed in AGIA would be directed to assist with only the project undertaken by the successful applicant. 9:37:47 AM Co-Chair Stedman requested the language pertinent to the federal position for comparison purposes. 9:38:10 AM Section 43.90.120. Request for applications for the licensee. (page 3, lines 11 through 18) Ms. Davis resumed analysis of the bill. This section would direct commissioners to develop a request for applications (RFA) as soon as possible after the effective date of the Act. The RFA would be similar to the request for proposals (RFP) process utilized for the awarding of other State contracts. She disclosed, "In reality because of the concerns about mitigating and eliminating delay, we're beginning that process know just to ensure that we have an rfa ready to go as soon as possible." Ms. Davis informed that the original language of this section would have directed the commissioners to undertake this process within 90 days of the effective date. However, legislative legal counsel advised that unforeseen circumstances could arise making the mandated deadline unattainable. To address this, the 90 day timeframe was transferred to a different section of the bill pertaining to "goal[s] or aspirational" benchmarks. The intention that the process would be completed within 90 days would be retained. 9:39:23 AM Senator Elton asked if this change would be acceptable to the Administration. 9:39:31 AM Ms. Davis answered it would, and reemphasized the Administration goal to complete the RFA process sooner than 90 days. The Administration appreciated the "wisdom" and advice regarding deadlines and unintended consequences. 9:39:51 AM Section 43.90.130. Application requirements. (page 3, line 19) Ms. Davis characterized this section as embedded with "the State's must haves". She detailed the criteria. 9:40:48 AM Ms. Davis stated that the language of subsection (1) would provide for a deadline for submission of the RFA s. 9:40:58 AM Ms. Davis noted subsection (2) would require the RFA to include a detailed description of the project including the route, receipt and delivery points, size and design capacity at those points, the economic analysis, and a technical viability of the project. Ms. Davis directed attention to an amendment to the original language of this section on page 4, lines 6 through 8. Co-Chair Stedman interrupted to direct the witness to detail the criteria individually. Ms. Davis repeated that Section 43.90.130(1) would provide for the deadline and Section 43.90.130(2) would provide for a detailed description of the project and categorizes the components into subparagraphs. Ms. Davis stated that Section 43.90.130(2)(A) stipulated that the detailed description must contain a proposed route for the natural gas pipeline. Subparagraph (B) pertained to the receipt and delivery points. Subparagraph (C) would require the RFA to include an analysis demonstrating the project's economic and technical viability. Ms. Davis explained that Section 43.90.130(2)(D) listed the economic and technically viability of the work plan, the timeline and associated budget, including a description of how the applicant would perform field work, environmental studies, design and engineering, and how the applicant would implement practices for controlling carbon emissions from natural gas systems as established by the federal Environmental Protection Agency. 9:41:56 AM Ms. Davis pointed out that the provision relating to carbon emissions was inserted into the bill by a Senate committee to address concerns about future global warming. The project could have carbon emission impacts and the State must be mindful of the applicants' ability to minimize those impacts. Ms. Davis continued outlining the provisions of subparagraph (D) noting the rfa must include a description of how the applicant would comply with State, federal and international laws. Ms. Davis noted the further delineation of Section 43.90.130(2)(D) into two types of projects that would require "special attention; special focus". The first, listed as (i) on page 4, lines 11 through 16, addressed potential "Canadian throughway issues, which would entail having the applicant describe if the project does require transiting through Canada, giving us specific details about the right-of-way situations or capabilities and the regulatory issues involving Canada." The second project type was listed as (ii) beginning on line 17, "focuses on the specific details that relate to a liquefied natural gas (LNG) project." Ms. Davis stressed the following. Keep in mind the AGIA process does not prejudge what type of project can be submitted. It can be an all in-state line for gas; it can be an in-state with an export for LNG [liquefied natural gas]; it can be a combination of those - one or both of those, with a gas line that would transit through Canada into the Lower 48, or into just Canada. So there's a wide range of projects that this bill has to back up and make sure that its got language that covers and enables commissioners to make a proper analysis. 9:43:46 AM Ms. Davis next described Section 43.90.130(3) on page 5, beginning on line 3, as the criteria that would require the applicant to provide "date certains". Subparagraph (A) contains "the one hard deadline that the AGIA bill imposes upon an applicant" to conduct an open season no later than 36 months after the date the license was issued. 9:44:19 AM Co-Chair Stedman requested Ms. Davis elaborate on the 36 month deadline and explain the difference between a binding open season and "potentially an unsuccessful open season". Ms. Davis answered as follows. The process by which an applicant has an open season is guided in good part by FERC. They set out specific procedures for the manner in which an open season is to be held. An open season is simply a period of time that that the pipeline company says, "I've put out this information, here's the data; I would like to invite the market to come forward and offer to ship on my pipeline." It's not a date; it's not a single date, it's a process that has to last, I believe, at least six months. And so you open a period of time of six months in which you wait for the market and you have dialog with the market. You encourage the market to come forward. In that time period you will be offering up what you believe are the likely tariffs; the likely structures. This is a period of time of negotiation for the pipeline with its shippers. In this time period, it will either get commitments from shippers that say "sure, sign me up for the base rate, the rack rate", or they'll say "you know, we're going to be doing a lot of business with you; we'd like to ship for this period of time for this volume of gas. We'd like to negotiate our own rate." That's a time period when they can actually negotiate a rate as opposed to take the FERC approved rack rate kind of structure. 9:45:59 AM Ms. Davis continued. This time period is the testing of the market. This is when the pipeline company finds out if they've done their homework and they've structured a project that will meet the needs of that market. It's a process that lasts for up to six months. Once the pipeline company has tested the market and seen the response, either they figure out that they didn't size the pipeline big enough, or they find out that they got it just right, or they find out that they've got more pipe then they've got gas being offered. That's when they step back and they ask themselves "Do I believe that my design is correct and that there's still more market demand out there that I just haven't been able to attract and I need to do more work to attract it. Or did I size my pipe wrong and I need to downsize my pipe to match what is in fact the real market demand." It's a very fluid time period this open season. It's a give and take process between the pipeline company and the market and the dialog. 9:46:56 AM Ms. Davis continued her explanation. As a result of when the cutoff happens and when the pipeline company says, "OK, I think I've got all the response I'm going to get." The pipeline company takes that information and then decides how they're going to proceed from that point. When we talk about an open season being successful or unsuccessful, that's a little bit of a - it's not a useful label because it really is sort of in the eye of the beholder; in this case the eye of the pipeline company how it wants to respond to the responses it got in its open season. 9:47:39 AM Ms. Davis concluded: But obviously a pipeline company that's set up to have a 4.5 bcf [billion cubic feet] a day pipe and they've only gotten shippers interested in about one billion cubic feet of that space, they've got an issue. After they have that open season, they'll need to figure out what the market reasons were for why their design didn't match the market. They'll have several ways to proceed from that point depending upon what their analysis tells them about the mismatch. 9:48:04 AM Co-Chair Stedman asked the reason for the allowance of 36 months from the date of issuance of the license to hold an open season and why a time limit of 24 or 18 months had not been chosen. The proposal to construct a natural gas pipeline from northern Alaska had been "worked on extensively" for the past several years and would not require "starting with a fresh idea into a new basin". 9:48:42 AM Ms. Davis deferred to the Department of Natural Resources. 9:48:54 AM ANTHONY SCOTT, Commercial Analysis, Division of Oil and Gas, Department of Natural Resources, testified to the question as follows. This is the only mandated date in the bill in terms of when an entity must do something by a particular date. It was important for us not to prejudge how an open season should be conducted, or the level of data that would be assembled. What we recognized was that 36 months gave essentially any applicant, no matter who they were, two full field seasons to assess, route, soils, whatever it is that they needed to assess to be able to put together a credible project. There are some potential applicants who may be able to move to an open season more quickly, as Mr. Chairman you recognized … because they have already done a tremendous amount of work. Presumably that would work in their favor in the application process because that goes to the issue, hopefully, of timing and when we could expect first gas. But again we didn't want to prejudge what an appropriate approach would be to conducting an open season. This gives enough time, two full field seasons; but we didn't want to sort of prescribe and impose artificial limitations about what could or should be done. 9:50:52 AM Co-Chair Stedman deduced from the presentation made at the previous hearing on this bill that a one year delay "at 5.5 as far as the price of gas 1.8 billion - this could be a fairly expensive extension all else being equal from 24 to 36 months." 9:51:16 AM Mr. Scott agreed about the advantage of entities that had already conducted "a fair amount of work" on the pipeline project and that could move to an open season after only one field season. The timing of the open season "sets up a process that leads you to first gas in a reasonably defined period of time" and "the earlier you start that process, the earlier you get to first gas and indeed, improved net present value for the State." 9:52:00 AM Co-Chair Stedman again asked how the 36 month time limit was determined and whether it was requested by any particular entity or was the resulting recommendation of an economic analysis or other comparisons. 9:52:23 AM Mr. Scott responded that neither was the case. Rather, "the desire was to permit enough time, given the timing of when this bill would move forward, and then we would get applicants and a license awarded, to ensure that we provided at least two field seasons." "Having spent years in negotiation," the Department was "quite sensitive to not wanting to tell people how they must conduct their business and what an appropriate open season and the preparatory work for that would be." The intention of allowing for a competitive process and because delay on the project would be detrimental to the State, evaluating comparative bids on the basis of net present value would create a competitive impetus to "move this forward more quickly." 9:53:24 AM Senator Elton asked the reason to establish a 36 month "hard deadline" rather than a requirement that either an open season must conclude within 36 months or that it begin within 30 months. Mr. Scott reiterated the intent to provide any applicant at least two field seasons to undertake the efforts necessary to conduct an open season. The open season process had been mandated in federal legislation and is "fairly lengthy" and would require approximately six months. It would include presentation of an open season plan to the FERC, after which FERC would have 30 days to approve the plan. 9:54:54 AM Senator Elton asked if open seasons were ever extended by FERC. 9:55:12 AM Mr. Scott replied that generally FERC did not have regulations that address open seasons because the open seasons were usually commercial practices held between two private parties. The federal natural gas act was the only project to include FERC regulation. The regulations require certain minimum periods of time but do not specify maximum periods of time. If the State did not mandate that the process by concluded by a certain date, it would be possible that the process could start and then continue for many years. This would not be preferable. The intent is that a termination date be established. 9:56:15 AM Senator Huggins requested an explanation of the rationale as to why the deadline would not be 30 months or less. Although 36 months could be the best option, the reasons why alternative time periods were not acceptable should be understood by the Committee. 9:56:49 AM Co-Chair Hoffman referred to the presentation given to the Committee at the previous hearing on this bill, noting that one of the "must have" criteria was to complete the pipeline sooner. Under this provision, he asked if the applicants would be questioned on how soon, within the 36 month deadline, the open season would conclude. If so, he asked the priority that would be given to applicants that demonstrate an ability to complete this process in a shorter time period. Ms. Davis affirmed that the "structure" of AGIA would require the applicant to provide a date by which it would conclude the open season. This date would be one factor considered in determining the net present value to the State of the proposal. Additionally, experts would be employed to judge the credibility of the date provided by the applicant because the "likelihood of success" would be another factor in determining the winning applicant. A projected date could be deemed unrealistic based on the amount of information and data collected by the applicant and would "counter balance" the advantage of the earliness of the date. 9:58:47 AM Co-Chair Hoffman asked the value that would be given to an application with an earlier completion date. 9:59:30 AM Ms. Davis replied that the evaluation criteria are defined in a separate section of the bill that would establish a formula utilized to rate each application and determine the net present value to the State. The projected date for completion of an open season would be one factor considered. If all factors of two applications were identical with the exception of this, the application with the earlier completion date would be ranked higher. 10:00:36 AM Senator Thomas assumed consideration must have been given to the impact of the timing of the inducement reimbursements on the ability to complete the open season. 10:01:07 AM Ms. Davis affirmed that the timing of State disbursements would affect the net present value of the project to the State. The determination of the net present value would be complex given the multiple factors that are not only "stand alone important" but also impact the other factors. 10:01:38 AM Senator Thomas remarked upon the urgency of completing the pipeline project. He would therefore consider the 36 month time limit in relation to when and in what amounts reimbursements were paid. Larger payments could be made sooner to "urge that project along." 10:02:10 AM Ms. Davis continued the sectional analysis, stating that Section 43.90.130.(3)(B) on page 5, lines 9 through 12, would require the applicant to provide a date certain of the pre-filing for a FERC certification. This process had been established by FERC to "facilitate the ultimate FERC certification process" and "focuses significantly on the environmental evaluations of the project." This effort would assist in the streamlining of the FERC certification process in the event an applicant partakes in the pre-filing procedure. FERC currently does not require pre- filing for a non-LNG project; however, this legislation would request the applicant to participate. Participation would "encourage quicker action". 10:03:23 AM Ms. Davis explained that Section 43.90.130(3)(C) relates to the actual application for the FERC certificate and would request the AGIA applicant to propose a date certain in which an application for FERC certification would be submitted. A projected date of receipt of the FERC certificate is not required because once the FERC process was underway an applicant would not control the pace by which FERC would issue the certificate. 10:04:05 AM Co-Chair Stedman posed a scenario and made the following request. One of the potential exposures for time that the State faces if we don't have as much success at open season we'd like and we go to the FERC certificate and we match the 80 cents on the dollar and we go for FERC certificate without enough FTs to construct whatever we're hoping to construct. So can you bring back to the Committee how often that process is done elsewhere; is this a common way large lines are built, or large projects, or not, and what projects have had failed open seasons, gone on to the driven on to the FERC certificate, which ones were successful and non- successful. 10:05:08 AM Ms. Davis answered that she would provide the requested information. Ms. Davis next characterized the provisions of Section 43.90.130(4) on page 5, beginning on line 17, as the "analog" to subparagraph (3); however "in a setting where the project is not governed by FERC but rather Regulatory Commission of Alaska [RCA], which means that the project would be an in-state project." Subparagraph (A) includes "a parallel requirement of concluding an open season within 36 months" and subparagraph (B) includes a requirement that the AGIA license apply for the certificate from the RCA by a date certain. Ms. Davis explained that Section 43.90.130(5), on line 25 through 27, pertains to the commitment required of applicants to assess market demand for additional pipeline capacity at least once every two years through nonbinding solicitation. She informed that once the design of the pipeline is completed and open season has commenced, the licensee could express a resistance to change the design despite a market offering a large quantity of natural gas. Ms. Davis asserted that the long term success of the Alaska Natural Gas Pipeline would depend in part on expansion with new gas from other fields to backfill declines in existing fields. Therefore a "cycle of renewal of gas resources over time" would be necessary. To accomplish this, "the explorationists need to look ahead and be able to say 'OK in x years ahead, I will have the opportunity to put my gas in a pipeline.'" The opportunity to do this would depend on that pipeline company's willingness to seek solicitations in a "fairly regular period" for interest in expansion. Ms. Davis relayed that criticism of this provision had been voiced by industry representatives due to concerns that "in a typical setting, when a pipeline company goes and solicits interest in expansion, they do so in a fairly formal process." 10:07:52 AM Mr. Scott further explained that the provisions of Section 43.90.130(5) and (6) "were designed to ensure that whoever owns the pipeline will act like a pipeline company." Nonbinding open seasons were regularly held and were "merely" solicitations of interest. If sufficient interest existed to support economic expansion, a pipeline company would later conduct a formal binding open season. Subsection (5) would provide a mechanism in which solicitations of some form would be acquired. This process would not have to be expensive and would require no engineering or design work. Mr. Scott stated that if adequate interest for new capacity was expressed, the provision of subsection (6) would require the pipeline company would commit to expand the project in "reasonable engineering increments and on commercially viable terms." 10:09:36 AM Co-Chair Stedman spoke of "considerable interest in this." He stated, "Clearly this is a basin-opening project and it's in the best interest of the State to open the basin up, have more exploration and development in the Arctic along with the ability to access the offshore issues, offshore gas." Ms. Davis pointed out that subsection (5) was intended to allow for a public non-binding solicitation or similar means. This could be "a fairly loose process" and would not need to be expensive. Co-Chair Stedman identified two areas of concern; one of which would be the impact of this clause on project design and engineering and possibly construction of the pipeline itself prior to the date of first gas. The second concern was the "relative frequency of it". He could not argue that the process should not occur, but asked how common such a two-year assessment clause was imposed. 10:11:18 AM Mr. Scott was unaware of any pipeline in the Lower 48 states governed by a fixed schedule to conduct solicitation of demand on a formal or informal basis. The Administration recognized that the Alaska Natural Gas Pipeline project would be unique and would probably not have competing projects. The likelihood that the producer group could own the pipeline was significant and if the producer group were solely concerned with generating pipeline returns, this project would likely already be underway. He did not challenge the producer's right to be interested in returns in addition to those generated from a pipeline; however the producer groups were not "geared towards the steady relatively modest returns that pipeline companies enjoy." Mr. Scott stated that the two year schedule would be "something new". If the pipeline entity "engaged in a process which is common in Canada" the outcome would be in the State's best interest. Tariffs in Canada have a "cueing system" in which interests expressed in shipping through a pipeline are noted and at the point sufficient interest has been expressed to support expansion, the interests are granted on a "first come first served" basis. 10:14:08 AM Mr. Scott emphasized that solicitation must be periodic to support the robust exploration and development necessary for success. Co-Chair Stedman asked if the two-year requirement was determined as a result of economic modeling or other analysis. Mr. Scott answered it was not. Recognition was given that the time period must be "sufficiently long" to ensure that the process would be "meaningful", and also a "short enough period" to provide those interested in exploration and development of hydrocarbons with "reasonable predictability" of when those efforts could be commercialized. If the Committee deemed that the exact amount of time should be different, he would not oppose an amendment to the subsection. 10:15:33 AM Co-Chair Stedman asked whether an analysis had been conducted on when the smaller exploration and development companies would have capacity of gas in sufficient amounts to participate in the pipeline. 10:15:42 AM Mr. Scott characterized this as "a chicken and egg problem". The date certain for the open season is important to "get this process moving" and provide increased predictability for those parties to begin to expend funds for exploration and "prove up" the anticipated reserves. "Explorer companies" would unlikely be able to prove up hydrocarbons in time to participate in the initial open season. This is one reason for the importance to continue the solicitation process past the open season. 10:17:11 AM Co-Chair Stedman, qualifying his limited expertise in oil and gas issues, commented and posed questions as follows. When we do this line; and maybe it has initial capacity of 4.5 pcf, maybe it's expandable to six, some ballpark numbers that seem to come up quite a bit in the analysis and we can assume that - do that type of volume or run a line down the continent into Canada. Clearly there's an interest in the State in seeing the basin opened up and we get more players up there; we have more exploration and expansion and we have the ability, like you've just mentioned for these newer applicants that have substantially less volumes of gas to be able to enter into a gasline and sell their product. But we also have, I think, roughly 52 or something right over 50 percent of the potential of reserve capacity laying offshore where the State of Alaska would not get as much economic activity off of it as we do on the North Slope. What kind of analysis or process - or has there been anything done on that particular issue to see what impact that may have in squeezing out these smaller companies on shore that we're trying to see expand so they one, don't have the ability to access … feeder lines … there's another term and I can't remember it right now, to feed into the [indiscernible] and then out and down the line. There's also the issue of just capacity in the line. Before you can get to that point you gotta get it to it. So can you enlighten me a little bit on that and the Committee on the potential risk that Alaska may be facing in the potential squeeze out that we may face in the offshore federal - I'm assuming that the folks offshore are gonna want to use that gasline to ship their product. 10:19:30 AM Mr. Scott made the same assumption, and acknowledged that the relative pace of different developments was unknown. "Which gas will come when" could not be determined at this time and was subject to different corporate strategies which the State was not privy to. Mr. Scott spoke to additional "must haves" provided for elsewhere in the bill, and discussed at a later hearing, as follows. One of the reasons on balance why we strongly believe that the rolled in rate provisions are in the State's best interest is because it is not at all - it is entirely possible that offshore gas could come in and fill the relatively inexpensive expansion capacity first. In that event without rolled in rates, gas from State lands might have to wait 15 or more years until Prudhoe Bay starts coming off decline before there's adequate capacity at an economic rate to get into the pipeline. So given the uncertainties on balance, we think it is clearly in the State's interest to have a level playing field for all gas across the board. In addition, … the rolled in rates provision in AGIA - there's no question that because it creates a level playing field, it opens potentially opportunities for offshore gas to come into the project. It's certainly in the federal government's interest. That will be helpful as we move forward in this process. It will also be helpful in the State's effort to try to obtain a royalty share from the OCS gas, which is more than six miles offshore, which is something which is of some interest now. People are working on that and I think it will improve our position actually as a State to obtaining that kind of share. Now, whether we will or not, I don't know. 10:22:15 AM Co-Chair Stedman directed the witness to provide a brief synopsis of the reason for concern about "offshore gas from a revenue perspective". He remarked, "All gas is not equal to the State treasury." 10:22:35 AM Mr. Scott responded that generally the State's royalty share from resources developed on State-owned land is 12.5 percent or one-eighth of the value. On federally owned lands located in the state, the State receives one-half of the federal government's 12.5 percent royalty. The State receives a higher revenue for developments from the greater Prudhoe Bay are, the Foothills, Point Thompson, etc., than from the National Petroleum Reserve- Alaska (NPR-A). The State typically receives approximately one- quarter of the federal royalty rate from gas produced within three to six miles offshore. Therefore, the State would prefer that the natural gas pipeline transport gas from NPR-A versus gas developed three to six miles offshore. The State currently receives no royalty share from developments located more than six miles offshore, known as the real Outer Continental Shelf. 10:24:50 AM Co-Chair Stedman summarized the issue that monetarily all gas is not equal to the State. The amount of revenue generated for the Alaska Permanent Fund would be impacted significantly depending on the location the gas was developed. The best scenario would be that all the gas transported through the natural gas pipeline would be developed from State-owned lands. Co-Chair Stedman requested a summary of the expected volumes, acknowledging the significant subjectivity. 10:25:56 AM Senator Dyson realized that a proposal from the producers that had the capacity to commit gas to the pipeline would be "attractive". However, he expressed concern about a proposal from a producer whose actual goal would be to continue to maximize oil production and generate profits from the Trans- Alaska Pipeline System (TAPS), and/or control the reservoir basin, and/or control access to the natural gas pipeline. If such a proposal were received he asked how the different goals would be evaluated. 10:27:29 AM Ms. Davis responded that the applications would represent "hugely expensive commitments by companies" and would not be submitted with the expectation that if accepted, the company would "walk away". She predicted that because of the amount of funds involved in preparing the applications, the motives would not be disingenuous. 10:28:01 AM Ms. Davis expected that the applications would be factual, would have credibility and would detail the proposed plan. She did not expect the applicants to "opine the pace of the gas off take". Rather, the application "is about building a pipeline." The Administration must conduct independent forecasting of the gas flow. 10:29:20 AM Ms. Davis made the following statement. The design of AGIA has built in from the get-go, tools that enable or ensure that that basin is not locked up. We recognize that once you've given a license to a group of people to build a pipeline and they're off and running, that's their pipeline. We as a state have certain regulatory rights, but that is their business; that is their pipeline. Our ability to tell them what to do or what not to do is limited by whatever the appropriate jurisdiction rights are through the RCA or the powers and authorities of FERC. So there are agencies out there designed to ensure that fair competition happens on that pipeline, that appropriate rates and tariffs are being charged, and that the access rights are being managed. 10:30:17 AM Ms. Davis qualified: With that said, in AGIA, looking ahead and anticipating what could go wrong, that is why we have certain must haves in the AGIA. A commitment by whoever that pipeline applicant is, that they will look around every two years and look to see if there's expansion opportunities and if there is appropriate expansion that they will do so. Finally, … is how the cost of that expansion will be borne by the shippers and the pipeline company. We've also go a few other must haves we haven't gotten to, which is the debt equity structure for rate purposes. We have some elements that we're going to hardwire from the beginning that will protect the State's interests without going overboard. But as far as being concerned whether or not a producer- owned pipeline is going to be damped - its economics dampened because of concern about what they're doing with the oil - we have to remind ourselves we have a stake in the oil as well as a state. We benefit from oil production as well and from the continuing flow of oil through TAPS. One must hope that we've got good alignment - the State's economics with the producer's economics subject to a couple elements that we've put into AGIA that ensure fair play. 10:31:37 AM Senator Dyson then expressed concern that the State did not have adequate reservoir information about the optimum gas off-take rate that maintains the oil production and that the producers did have this knowledge. He asked if the State possessed the ability to evaluate the maximum gas off-take rate proposed in an application. 10:32:23 AM Ms. Davis suggested the Committee address this issue as an independent topic, given its importance. The AOGCC agency is vested with the responsibility of managing the gas off-take rate and has currently undertaken this in conjunction with the producers. The producers developed reservoir data, which the State possessed. However, the State did not posses the computer model that provides conclusions of impacts on the reservoir. This has been made available to the AOGCC under confidentiality provisions. As an interested and involved party, the Department of Natural Resources would likely have access to the information as well for the purpose of evaluating an AGIA application. She questioned whether a third party would have similar access. ADJOURNMENT  Co-Chair Bert Stedman adjourned the meeting at 10:33:42 AM