SENATE FINANCE COMMITTEE April 20, 2022 1:07 p.m. 1:07:51 PM CALL TO ORDER Co-Chair Bishop called the Senate Finance Committee meeting to order at 1:07 p.m. MEMBERS PRESENT Senator Click Bishop, Co-Chair Senator Bert Stedman, Co-Chair Senator Lyman Hoffman Senator Donny Olson Senator Natasha von Imhof Senator Bill Wielechowski MEMBERS ABSENT Senator David Wilson ALSO PRESENT Scott Jordan, Director, Division of Risk Management, Department of Administration; Paloma Harbour, Fiscal Management Practices Analyst, Office of Management and Budget, Office of the Governor. PRESENT VIA TELECONFERENCE Ryan Fitzpatrick, Commercial Analyst, Division of Oil & Gas, Alaska Department of Natural Resources; Emily Feenstra, Assistant Attorney General, Department of Law. SUMMARY CSHB 81(RES)am OIL/GAS LEASE: DNR MODIFY NET PROFIT SHARE CSHB 81(RES)am was HEARD and HELD in committee for further consideration. HB 102 STATE INSUR. CATASTROPHE RESERVE ACCT. HB 102 was HEARD and HELD in committee for further consideration. CS FOR HOUSE BILL NO. 81(RES) am "An Act relating to the modification of a royalty or net profit share in an oil and gas or gas only lease." 1:08:38 PM RYAN FITZPATRICK, COMMERCIAL ANALYST, DIVISION OF OIL & GAS, ALASKA DEPARTMENT OF NATURAL RESOURCES (via teleconference), discussed a presentation, "HB 81 NET PROFIT SHARE and ROYALTY MODIFICATIONS ON OIL & GAS LEASES" (copy on file). He turned to slide 2, "Outline": I. Overview of Net Profit Share Leases II. Overview of the modification process III. Why Allow for NPSL Modifications? IV. Overview of House Bill 81 as amended in the House V. Appendix Mr. Fitzpatrick spoke to slide 3, "ROYALTY and NET PROFIT SHARE," which showed a table that compared different types of petroleum revenues including royalty, production tax, net profit share, and profit to the lessee. He explained that that purpose of the slide was to try and show the differences between the different revenues. He continued that royalty and profit share were both derived from the oil and gas lease contract and were significantly different from production tax. Royalty and net profit share contract provisions could only be changed through the consent of both parties, whereas production tax was on a separate fiscal system and was changeable at will by the state acting as a sovereign. He noted that currently royalties could be modified by the Department of Natural Resources under an existing statutory scheme in AS 38.05.180 (j). He reminded that production tax was amendable at-will by the legislature. Mr. Fitzpatrick noted that there was currently no statutory scheme to allow for net profit share lease modifications. There had been one instance of a modification that occurred in the mid to late 1990s. He recounted that the lessee had approached DNR about modification, it was determined the department did not have the authority, and the modification had been brought to the legislature in the form of a bill that was later passed by the legislature. One of the reasons the bill proposal was advanced was to streamline the process so that DNR might have the authority to modify the leases (within the confines of the statute) without having to come to the legislature each time. 1:13:02 PM Co-Chair Bishop asked how many modifications of net profit share had occurred in the previous ten years. Mr. Fitzpatrick cited that there had been no such modifications in the previous ten years. He noted that the case he mentioned was the only instance of a modification of net profit share leases, however there had been three decisions that had modified royalties. Mr. Fitzpatrick highlighted an important difference between royalties and net profit shares and noted that royalties began payments at the beginning of commercial production as a share of the total production from the lease. The net profit share payment was calculated in a significantly different manner and took into account the costs of production. In order for a net profit share payment to be made, the lease had to generate a profit and the lessee had to recover initial capital costs. The net profit share would be a percentage of the net profits generated by the lease after the recovery of costs and could begin many years after the lease went into production. He reiterated that the net profit shares took into account the costs of production and royalties did not. 1:15:50 PM Mr. Fitzpatrick referenced slide 4, "NET PROFIT SHARING: A HYPOTHETICAL EXAMPLE," which showed a hypothetical example of a breakdown between the costs and revenues generated by the sale of a barrel of oil. He noted that the example was not reflective of any particular oil price and used made up numbers. He drew attention to capital and operating expenditures, transportation costs, and revenues from the barrel of oil. There were some taxes not shown on the diagram. The royalty and production tax that went to the state was shown, and finally the profit that went to the lessee. Mr. Fitzpatrick pointed out that the barrel shown on the right of the slide showed the same costs and royalty as the first share of revenue to the state. He pointed out the production tax and net profit share, which turned out to be a small reduction to the production tax because the payment of the net profit share under the lease was a deduction against the profits on which the tax was paid. Overall, the state took more revenue from the example on the right because it received both the net profit share and the production tax. The final item was the profit to the lessee, which was less because of the net profit share percentage. Co-Chair Stedman referenced the states gross tax before conversion to net tax, after which there was net profit share leases embedded into production tax section of profit oil. Mr. Fitzpatrick agreed that Co-Chair Stedmans description was correct. He noted that all of the net profit share leases currently were issued prior to the conversion of the production tax from gross tax to a net tax back in 2006. When the net profit share leases were issued, the production tax under which the net profit share leases were operating would not have included any deduction for net profit share payments as part of the tax calculation. When the production tax was converted from a gross to a net tax in 2006, net profit share payments were called out as another field cost of the lease to be deducted from the production tax. 1:20:16 PM Mr. Fitzpatrick turned to slide 5, "26 ACTIVE NET PROFIT SHARE LEASES," which showed a table with a list of all the net profit leases outstanding in the state. He reminded that all the leases were originally issued in the late 1970s and early 1980s. He noted that some leases were listed as being issued in 2019 or 2007, and the leases were subdivided portions of a lease that was previously issued. Mr. Fitzpatrick pointed out the column entitled 'Net profit share rate,' and made note of the significant variation from 30 percent to 40 percent for most leases, and up to almost 80 percent for other leases. He explained that for the most part the net profit share rate was a fixed component of lease sales, but there were times that the net profit share rate was the bid variable. The royalty rates also reflected that the leases still generated royalties, with most at 12.5 percent but some with royalty set at 20 percent. Mr. Fitzpatrick noted that the next several columns on the table had information about the unit and the source of production for the leases. An additional column reflected whether the net profit share leases had recovered all of the capital costs and were beginning to generate net profit share payments to the state. He noted that some of the net profit share leases listed had reached payout, and some had not. In some cases, the leases had no production allocated to the lease. In other instances, there could be production generated from the lease, but it had not recovered the capital costs allocated to the lease yet. There were additional columns that provided information on the amount of the cumulative net profit share payments and royalties that had been generated from each unit. He pointed out the last column, which showed the date the lease generated its first royalty payment. He pointed out the first payout dates. He observed that there were several examples on the slide that illustrated that the payout date was generally much later in time than the start of the royalty payments. 1:23:56 PM Co-Chair Stedman understood that Pt. Thomson was unique. He asked about the Kuparuk lease, which had not reached the payout stage. He asked if the leases were sitting idle for as long as 40 years. Mr. Fitzpatrick stated that the Kuparuk leases were generating some small amount of production. He pointed out that the Cumulative Royalty column reflected that the net profit share leases in the Kuparuk unit had generated $40 million in royalties to the state, which was lower than some other net profit share leases. Much more of the production from Kuparuk weas being generated from leases that were not net profit share leases. He noted that there was a map of net profit share leases in the appendix of the presentation. The initial capital investments of the Kuparuk region, primarily exploration expenses, were allocated across the leases and became a capital cost of the leases. Because of the small production, the initial capital cost had not been recovered. Co-Chair Stedman understood that the Kuparuk leases had been taken out in 1983, and Kuparuk had been active for decades. He understood that capital expenditures were allocated against the leases, and not just capital expenses from the 1980s. Mr. Fitzpatrick affirmed that ongoing capital expenses and ongoing capital costs were allocated to each of the leases based on the share of production from the lease. A very small amount of the capital and operating costs would be allocated to the leases because only a small fraction of the production was allocated to the leases. The initial capital expenditures around exploration were having the most effect and remained as part of the lease. He continued that one of the features of net profit share leases was that capital expenses allocated to the lease generated a hypothetical amount of interest in the development account. For accounting purposes, there was a small amount interest allocated to the capital account based on the prime rate. The initial capital costs had been generating small but continual amounts of interest over a number of years, and very little production allocated to the leases to continue to pay down the initial capital cost. 1:29:13 PM Co-Chair Stedman wanted to put the matter in context. He observed that the last time the leases were used was 1984. He asked why the leases ceased to be used, and why the leases were being considered so long after being inactive. Mr. Fitzpatrick agreed that it had been a number of years since the leases were issued. He mentioned the North Star leases, which were not currently net profit share leases and were not included on the table. Some of the leases had been issued with net profit share in excess of 90 percent, which began causing problems with getting some of the units into development. He explained that if a lease was deemed to be only moderately prospective, the 90 percent net profit share rate could be a barrier to development. The high rate had been the reason for the modification of the North Star net profit share leases, after DNR had decided the lease offering was no longer the best alternative for the state Senator Wielechowski asked to go to Appendix 15, "Map of Net Profit Share Leases." He referenced the map and thought it looked as if there were no net profit share leases in Prudhoe Bay nor Badami. Mr. Fitzpatrick answered "yes." Senator Wielechowski asked if the leases, or any other existing leases, could be converted into net profit share leases. Mr. Fitzpatrick informed that the current statutory scheme for royalty modification allowed DNR, within certain limits, to modify the payment mechanisms for individual leases on a number of different bases. It would be possible to functionally add the equivalent to a net profit share component through the modification process, although there would still have to be a base royalty rate. The process would have to occur if a lessee applied for a royalty modification and then ultimately accepted the terms offered by DNR. 1:33:29 PM Senator Wielechowski asked if the bill affected the process. He asked if the owners of Prudhoe Bay could request a modification to add a net profit share lease and pay a net profit share of 30 percent. Mr. Fitzpatrick stated that the bill would not change the part of the modification scheme that he described. Senator Wielechowski went back to slide 5. He asked if any other fields other than those listed on the slide would be eligible for net profit share leases if the bill were enacted. Mr. Fitzpatrick stated that the proposed changes to net profit share rates would not affect other leases, because the other leases did not have a net profit share component. The bill would not affect the current statutory authority for parties to agree on adding a functional equivalent of net profit sharing to other leases. The net profit share modification component of the bill would not impact leases other than those listed. Senator Wielechowski asked about Colville River, which had royalty rate of 12 percent, and a net profit share rate of 30 percent. He asked Mr. Fitzpatrick to walk through a simple balance sheet of the components. He mentioned a production tax. Mr. Fitzpatrick affirmed that Senator Wielechowski was correct; if barrel of oil was sold, the first thing to happen would be a deduction for transportation expenses. Whatever was left of the sale of a barrel after the deduction would first have the royalty share paid out. What was left was split between production tax, net profit shares, and covering the field costs of the lessee and remaining profit to the lessee. 1:37:09 PM Mr. Fitzpatrick continued that the next functional step after the royalty would be the net profit share payment, after deducting capital costs and operating expenses for the year. He noted that the Colville River was already in payout, and there would not be any prior year capital costs factored in, just whatever costs incurred in the particular year. Mr. Fitzpatrick described the lease language that allowed for a deduction for net profit shares in calculating net profit shares for production tax. There was a regulation that calculated the production tax within the net profit share calculation. Anything that was left was profit to the lessee. Senator Wielechowski wondered if Mr. Fitzpatrick could provide his answer in writing. He asked where deductible oil tax credit factored into the process. He asked whether there was still a gross 4 percent tax floor. Mr. Fitzpatrick did not have the information to address dollar values. He offered to provide the information at a later time. He addressed tax credits and how it factored into the calculation. He explained that in doing the net profit share payment calculation, the regulations simulated the production tax payments that might otherwise be paid. Any tax credits that were in the tax statute were treated as if they were a deduction from a tax when calculating the net profit share payment. If the production tax was lowered because of the payments, the tax deduction in the net profit share calculation went down, and the lessee would pay a higher net profit share to the state because the tax was lower. 1:41:05 PM Senator Wielechowski reiterated that it would be helpful to have Mr. Fitzpatricks answer in writing. He asked if it would be fair to say if there was a net profit share rate of 30 percent if the company was paying more or less production taxes than under the current statute. Mr. Fitzpatrick stated that in the instance of a net profit share, the company would generate the net profit share payment as a result of the calculation, because it was then deducted against the production tax, and the lessee paid a smaller production tax. The overall effect of the net profit share rate combined with the production tax was always larger than the production tax itself. Senator Wielechowski hypothesized that the state decided to cut the net profit share down to one percent. He assumed the company would still be paying as much as under the current production tax structure if there were no net profit share at all. Mr. Fitzpatrick answered in the affirmative and stated that even if the net profit share rate were reduced to the minimum that was in the bill or eliminated entirely, whatever the production tax was reduced to, the lessee was paying at least as much in production tax as it would have paid if there had been no net profit share in the lease originally. He noted that there was a provision in the bill that limited the modification to a ten percent net profit share. He summarized that in any instance where there was a net profit share component that remained, the combination of the net profit share and production tax would always be more than the production tax on its own. Senator von Imhof thought it was important to consider the big picture rather than the minutiae of the bill. She noted that HB 81 did not propose to change the modification process but added oversight. She asked Mr. Fitzpatrick to confirm her understanding. Mr. Fitzpatrick agreed and explained that her interpretation was correct. He continued that the change proposed in the bill was to add net profit share rates to the existing modification process. Senator von Imhof thought she read something about trying to eke more life out of fields that were not profitable or producing. Mr. Fitzpatrick answered affirmatively. He stated that might be useful to bring a new field intro production or it could extend the life of an existing field by eking out more production. Senator von Imhof thought the choice at hand was "something" versus "nothing. Mr. Fitzpatrick agreed that the only proposed to add the net profit share to the existing scheme. 1:45:45 PM Senator Wielechowski asked if the bill would allow or make it easier for the state to lower the net profit share rate of fields. Mr. Fitzpatrick stated that the bill would make it easier to modify the net profit share rate in that the current process would be to bring the matter to the legislature. The bill proposed a process with a heightened burden of proof and significant analysis by DNR. He noted that DNR had the authority to hire outside consultants at the applicant's expense to assist in analysis. The bill also added an oversight component for the state Oil and Gas Royalty Board for both royalty modification and net profit share modification decisions. Senator Wielechowski asked if a company could request a net profit share reduction, which could result in a loss of revenue to the state. Mr. Fitzpatrick answered that the modification scheme that was currently in place required DNR to only authorize modifications only if the field did not come into production or the field was already shut in. Senator Wielechowski mentioned a previous tax structure known as the Economic Limit Factor (ELF) and asked if Mr. Fitzpatrick had been in the state at the time. Mr. Fitzpatrick stated he was in the state but was not involved in oil and gas tax at the time. Senator Wielechowski asked if Mr. Fitzpatrick could discuss the history of how ELF had worked at Kuparuk, when it lowered the tax rate from 12.5 percent gross to zero from 1996 to 2003, with an objective of encouraging increased production. He recalled that production dropped precipitously as the tax rate was going down to zero. Mr. Fitzpatrick understood that the production tax rate at Kuparuk did decline during the ELF years, which was coincident with the decline of production at the field. Co-Chair Bishop wanted to note that Senator Wielechowski had used Point Thomson as an analogy and pointed out that even with 100 percent tax rate there would be no profit without production. 1:49:48 PM Mr. Fitzpatrick considered slide 6, "HISTORY OF ROYALTY MODIFICATION APPLICATIONS," which showed a table, including the Northstar modification he had alluded to earlier. He noted that there had been several modification applications over the years going back to 1995. He cited that DNR had not had the authority to modify the net profit share for Northstar and it had been brought to the legislature. The legislation that was passed had removed the net profit share of the leases and increased the royalty from a base of 20 percent to a sliding scale between 20 percent and 27 percent based on the price of oil and other factors. The decision was presented by the lessee as necessary to bring the field into production. Mr. Fitzpatrick pointed out that there had been several applications made for royalty modifications to the department that had been denied or withdrawn. Only three out of all the modification applications had been approved and were shown in blue. Of the three modifications, only two were still active. The third, for the Nuna field, had a limitation that required an investment decision by a certain period of time. The lessee ultimately didnt make the investment decision and the modification lapsed of its own accord. Co-Chair Bishop asked if the Nuna modification had an 80 percent Alaska-hire rate as part of the royalty modification. Mr. Fitzpatrick believed the Alaska hire provision had been part of the agreement. He believed the provision that ultimately caused the modification to rescind was that Caelus (the lessee) had been required to make an investment decision in a certain period of time, which it failed to do. Co-Chair Stedman commented on the complexity of the state's tax structure. He asked why the state did not try and simplify its tax structure to make it more transparent. Mr. Fitzpatrick was certain there were many discussions about how to best modify all of the components. He thought the idea behind the bill proposal was that it would be easiest to slot the net profit share modification proposal into the existing royalty modification scheme. 1:54:12 PM Co-Chair Stedman asked which leases listed on slide 5 had a hindrance to production. He referenced Co-Chair Bishop's comment regarding the lack of production. Mr. Fitzpatrick iterated that one of the modification criteria for royalty was to extend the life of a field that might otherwise shut in because it reached the economic end of field life. He noted that some of the fields listed might have relatively strong production values and commented on the oil market. He continued that as units continued to age and production dropped further, some of the units could reach the point where the reduced production no longer covered operating expenses. The proposal was primarily targeted at those fields as they began to reach the end of field life because of declining production. Co-Chair Bishop referenced slide 6, and the history of royalty modification applications. He asked if the modifications all required legislative action. Mr. Fitzpatrick explained that the current modification for royalties did not require legislative approval but did require the department to offer a presentation to the Legislative Budget and Audit Committee during the public comment period of the decision. There was an opportunity for the legislature to receive some of the confidential information that went into the decision, and to offer comments during the comment period. He stated that under the bill, the process would be extended with an additional oversight requirement of a vote by the royalty board. 1:57:52 PM Mr. Fitzpatrick displayed slide 7, "WHAT TYPE OF MODIFICATION IS WARRANTED?": A. Royalty Modification is capped at certain minimum royalty rates. ?Five percent for .180(j)(1)(A) or three percent for .180(j)(1)(B)(C). B. The proposed NPSL modification also establishes a minimum net profit share of ten percent. C. The modification must be based on a sliding scale mechanism. ?It could vary with the price of oil, volume of production, per-barrel costs, etc. ?HB 81 allows use of fixed royalty rates for a modification, but any fixed rate must be coupled with other modification mechanisms that create an integrated sliding scale modification. D. Modifications of royalty or net profit share can be either lower or higher than the original percentages. (AS 38.180(j)(3)) ?In certain circumstances, this would allow DNR to recapture foregone royalties or net profit revenue if oil prices rise, or even to participate in "upside" price movements if DNR provides "downside" relief. Senator Wielechowski asked if DNR had any opinions from the attorney general, Legislative Legal Services, or any attorneys that the bill might be unconstitutional under the power of taxation. 2:01:56 PM EMILY FEENSTRA, ASSISTANT ATTORNEY GENERAL, DEPARTMENT OF LAW (via teleconference), relayed that she had reviewed the bill and had not found any constitutional issues. Senator Wielechowski asked if net profit share was not considered to be a tax. Ms. Feenstra stated that net profit share was considered to be separate but related to a tax. Senator Wielechowski recalled a similar issue that a legislative attorney had found to be unconstitutional. He asked if the net profit sharing was considered to be a tax, Ms. Feenstra would find that giving away the ability to review the process would make it unconstitutional. Ms. Feenstra agreed to do more research on the topic and noted that she would be happy to see the information Senator Wielechowski was referencing about the previous legal opinion. Senator Wielechowski asked if Ms. Feenstra would agree that if the net profit share was considered to be a tax, the legislature could not give up its right to review it. Ms. Feenstra believed that Senator Wielechowski was correct. Co-Chair Stedman commented that twenty years previously the Legislative Budget and Audit Committee had reviewed a lease modification. He could not recall the details. He thought the committee should review the information. 2:05:04 PM Mr. Fitzpatrick highlighted slide 8, "DECISION-MAKING PROCESS": A. HB81 does not propose to change the modification process, but adds oversight for the final decision to grant a modification. B. A producer applying for a royalty modification must provide a clear and convincing evidence showing that they meet the statutory requirements. ?A higher standard of proof than required for most other DNR applications. ?Applicants required to provide abundant evidence to justify any request for relief. C. DNR may require (for .180(j)(1)(A)) or request (for .180(j)(1)(B)(C)) that producers pay up to $150,000 per application for consulting work to support DNR's evaluation of the application. D. Publication of Best Interest Finding and offer presentation to Legislature (AS 38.05.180(j)(9)-(10)). E. HB 81 adds an oversight role for the Alaska Royalty Oil & Gas Development Advisory Board. The Board is required to approve any modification proposed by the Commissioner. F. If granted, modifications are not transferrable without the authorization of the Commissioner. (AS 38.05.180(j)(5) 2:08:24 PM Mr. Fitzpatrick looked at slide 9, "WHY ALLOW FOR NPSL MODIFICATIONS?" 1. Increase Production from Otherwise Stranded Resources ?Under certain circumstances, even with royalty modification, it is possible for continuing or for incremental production from pools which contain NPSLs to be stranded. ?Modification of royalty and/or net profit share for pools which would otherwise be stranded could extend the life of such field and other existing fields. 2. Flexibility for Royalty Modifications ?NPSL Modifications would give DNR flexibility to elect targeted reductions and could be a useful tool in environments of high oil price volatility. ?NPSL Modifications would enable DNR to increase net profit shares in scenarios where DNR can structure potential payback of foregone revenues in the event of higher prices or production levels. 3. Streamline Process for NPSL Modifications ?Current process to modify NPSLs is for DNR to negotiate a modification package and submit proposal for legislative action. ?Providing for NPSL Modification in statute would streamline the NPSL modification process, while allowing for the Legislature to set conditions and limits on NPSL Modifications. 2:11:35 PM Mr. Fitzpatrick addressed slide 10, "WHAT HB 81 ACCOMPLISHES": 1. Expand the royalty modification process to include the modification of net profit shares: ?Commissioner would have the authority to modify net profit share rates in the same manner as royalty rates under AS 38.05.180(j). o Objective is to encourage production of otherwise stranded resources. 2. Creates an additional qualifying scenario for modification of NPSLs ?For producing pools, where incremental production requires incremental capital expenditures, which, in the absence of modification, would be uneconomic. 3. Adds Oversight Role for Royalty Board for Royalty and NPSL Modifications ?The existing Alaska Royalty Oil & Gas Development Advisory Board would gain an oversight role in the modification process. The Board would be required to review proposed modifications for royalty and/or NPSL, and no modification could be granted without Board approval. 4. Resolves an existing potential statutory ambiguity ?Clarifies that test production during exploration does not disqualify a field or pool from royalty or NPSL modification based on new production. This merely codifies existing interpretation and is not a change in policy. 2:14:26 PM Co-Chair Bishop asked if item four on the slide would be codified in statute. Mr. Fitzpatrick stated that the item would be part of the bill. Senator Olson went back to slide 9, and the mention of increasing production of otherwise stranded resources on slide 10. He asked if there had been an estimate by the department to see what additional revenues the state might realize if the bill were to pass. Mr. Fitzpatrick stated that the department had prepared an indeterminate fiscal note, and cited that it was very difficult to predict which producers or scenarios might apply for a modification. Senator Olson understood that the department might not have exact numbers. He asked whether the change might be significant or minimal. Mt. Fitzpatrick did not characterize the potential additional revenue from the bill as a large revenue stream. He estimated that the fields in question would be reaching the end of life with low production, and the net profit share payment was likely to be low. The goal of the proposal was to hypothetically eke out some field life, both for the net profit share component, and potentially for the royalty component and tax component. He identified that if the state could modify the net profit share rate and get some additional production out of a field, all three revenue streams would be available for an additional year. Senator Olson commented that if the bill did go through there would be minimal effect, and he saw no significant reason to move the bill forward. 2:17:08 PM Senator Wielechowski asked if the department had a guidance document that the commissioner used to determine whether to or how much to modify royalty agreements. Mr. Fitzpatrick relayed that the guidance primarily resided in statute. The statute dictated that the modification be granted on a basis that it was only what was required to change the investment decision. In a situation where the modification of the royalty down to ten percent would bring a field to production or extend the life of a field, the statute did not allow the department to modify the royalty down to five percent. Statute allowed for the smallest modification that was possible while still flipping the investment decision. Senator Wielechowski asked if any other states had a similar scenario in which it was allowed to reduce royalty rates or tax rates on public lands. Mr. Fitzpatrick understood that for tax rates, the state would act as sovereign and had the right to change tax rates at any point in time. For the royalty rates, he understood that the federal government had a royalty modification process that federal lessees could apply to, and it operated somewhat like the states modification mechanism, although there were also significant differences in how the modifications were applied. He was not aware of other states that had a net profit share component of oil and gas leases. 2:19:26 PM Senator Wielechowski knew there was a statute regarding royalty rate reduction but asked if there was any kind of internal document stipulating the net present value or royalty rate of return. He asked if there was anything the commissioner had to use as guidance in making the determinations. Mr. Fitzpatrick was not aware of any internal documents that set the requirements. He considered that past royalty modification decisions had involved a survey of the market to identify reasonable rates of return. If the modification of royalty to 10 percent was enough to the net present value just slightly over zero, the amount was all that would be authorized. Mr. Fitzpatrick advanced to slide 11, "HB 81 VS. CSHB 81(RES)AM," which showed a table with a comparison of the original bill proposed in the House versus the Committee Substitute (CS) that the committee was considering. He pointed out that the original bill and the CS both allowed for modification of net profit shares, and both included correction for the statutory ambiguity around test production. The bill had been amended to restrict the new modification scenario for additional capital expenditures to net profit share rates only. The 10 percent floor for net profit shares percentages in a modification scenario was included in the original bill and the same language was in the CS. Mr. Fitzpatrick continued that there were some additional requirements put in place in the House to require the lessee to incur the capital expenditures proposed under the modification. The DNR commissioner would make the determination that the capital expenditures were necessary to maximize economic production. The oversight role for the Royalty Oil and Gas Development Board was also a component of the original version of the bill. There were some other conforming changes to the language proposed by Legislative Legal Services and accepted in the House. 2:23:37 PM Co-Chair Bishop OPENED public testimony. 2:23:51 PM Co-Chair Bishop CLOSED public testimony. 2:24:01 PM AT EASE 2:24:57 PM RECONVENED Co-Chair Bishop set HB 81 aside. CSHB 81(RES)am was HEARD and HELD in committee for further consideration. HOUSE BILL NO. 102 "An Act relating to the state insurance catastrophe reserve account; and providing for an effective date." 2:25:04 PM Co-Chair Bishop noted that the committee had heard the companion bill for HB 102 the previous session and had heard public testimony. 2:25:54 PM SCOTT JORDAN, DIRECTOR, DIVISION OF RISK MANAGEMENT, DEPARTMENT OF ADMINISTRATION, discussed the presentation "House Bill 102 - Alaska Department of Administration - Division of Risk Management" (copy on file). He showed slide 2, "Purpose": The assets of the Catastrophe Reserve Account (CATFund) may be used to obtain insurance, to establish reserves for the self-insurance program, and to satisfy claims or judgments arising under the program. ? The purpose is to allow the State to self-insure for property coverage. ? HB102 will save the state $3M in the first year and $26M over the next 5 years (est.) ? Due to global property insurance markets hardening we had a 30% increase in insurance costs from FY20 ($5.1M) to FY21 ($6.6M) and FY22 was ($7.1M). ? HB102 is a request to change the Catastrophe Reserve Account (CATFund) limit from $5,000,000 to $50,000,000 unencumbered. ? Currently the limit on catastrophe coverage that can be purchased is $50,000,000 for an annual premium. We can save that annual premium by self-insuring 2:28:20 PM Mr. Jordan showed slide 3, "What other states are doing?": • Just pay the higher premiums. Some states are forced to maintain excess coverage due to benefits paid by FEMA which requires "Obtain and Maintain" agreements when FEMA pays for a catastrophic loss. • Set up Captive Plans-similar to self-insured plan. • Increase Self-Insured Retentions (SIR), in some states $40M to $50M retention. • Some states are coming off multi-year premium price guarantees. Mr. Jordan spoke to slide 4, "Comparison of premiums paid, property losses paid, recovery (excess insurance) FY95- 2020": FY95-FY2020 property premiums paid $59,017,386 FY95-FY2020 property losses paid by DRM $26,145,207 FY95-FY2020 recovery from excess insurance $17,942,815 FY2014 Kodiak Launch Facility loss $15,931,131* FY2007 DOT-Girdwood Fire $ 835,136 FY2000 Court Plaza Bldg $ 1,176,54 *this type of claim is now excluded from coverage Mr. Jordan noted that there had been about a $1.9 million return on an $85 million investment in the losses. 2:32:18 PM Co-Chair Stedman asked if the premiums were calculated nation-wide, such as in the flood insurance program. He thought it would be difficult to get through the regulatory environment. Mr. Jordan explained that the state's insurance went both through the domestic market and the London market, which came up with the rates. There were models through which the markets could come up with catastrophic loss rates, and freely admitted the modelling was not correct. He cited that the state paid about 7.4 cents per $100. Senator Wielechowski thought Mr. Jordan indicated that the state was responsible for $50 million in damages and then would purchase insurance for any amount beyond. Mr. Jordan stated that the division's intention was to fully self-insure the program. With the $50 million increase proposed in the bill, it would allow the state to have the same funding it currently purchased for catastrophic losses (earthquake and flood insurance). Senator Wielechowski mentioned catastrophic earthquakes in Anchorage and Fairbanks, and wildfire that destroyed state facilities. He asked about the state's liability. Mr. Jordan stated there was no liability component when considering property losses. He explained that if there was a catastrophic loss, the state would go to the carrier for the full limit. If the state did a self-insurance program, it would have access to the fund at full value and would probably turn to the Federal Emergency Management Agency (FEMA) to help reimburse the losses. Senator Wielechowski hypothesized about a catastrophic incident in the state with enormous loss of hundreds of millions. He asked how much the state would be responsible for under the current insurance and if the state would rely on FEMA if it was self-insured. Mr. Jordan answered affirmatively. Currently the state's catastrophic loss coverage from purchased insurance had a limit of $50 million. The excess carriers would only pay $50 million. There was a different retention schedule for catastrophic versus non-catastrophic losses. He continued that catastrophic losses were only paid by percentage of value. He continued that the way the insurance was written, it would take the loss of many buildings to get $50 million from the insurance company, whereas with the provisions in the bill, the state would pay the first dollar out the door. 2:36:44 PM Senator von Imhof understood that the deductible was the first 5 percent of the building, but if the state did not purchase insurance, it would be liable for the entire $50 million. Mr. Jordan stated that with excess insurance on catastrophic losses, the state was required to pay 5 percent of a buildings value for a catastrophic loss. Under the self-insurance scenario, risk management would pay the first dollar out the door to agencies that had losses out of the catastrophic loss fund. If there was a $5 million loss on a $100 million building, it would be paid out of the fund. Senator von Imhof asked about if the whole $100 million building was lost to fire. Mr. Jordan stated that the fund would pay up to $50 million, and the state would likely turn to FEMA for support on the additional amount. He reminded that it would be similar to the current scenario since $50 million was the most that insurance would pay. Senator von Imhof referenced the earthquake in November of 2018, and she imagined the losses exceed $50 million across Southcentral Alaska. Mr. Jordan stated that the losses to the state did not exceed $50 million but the losses to all of the state did exceed $50 million. Senator von Imhof asked if the state had been able to collect from FEMA in the scenario. Mr. Jordan affirmed that there were a few agencies that had gone to FEMA. He explained that FEMA had a requirement that the Risk Management Division could not request the funds; rather, the occupying agency of the building had to do the request. He mentioned that the Department of Corrections and the Department of Transportation and Public Facilities had to go directly to FEMA. Co-Chair Bishop asked if there had to be a federal disaster declaration in order to apply to FEMA. Mr. Jordan knew that Department of Military and Veterans Affairs stepped in for disasters, but he did not know if there had to be a disaster declaration. Co-Chair Bishop asked if Mr. Jordan could respond to the question in writing. Mr. Jordan agreed. Senator Wielechowski asked if the bill would apply to the University or the Court System. Mr. Jordan affirmed that the bill would apply to the Court System, but the University had its own program. Senator von Imhof asked if the State Insurance Catastrophe Reserve Account could be swept. Mr. Jordan did not know the answer. He offered to get the answer from the Office of Management and Budget. Senator von Imhof wanted to know if the fund could be swept and the reasoning behind the fund status. 2:40:25 PM PALOMA HARBOUR, FISCAL MANAGEMENT PRACTICES ANALYST, OFFICE OF MANAGEMENT AND BUDGET, OFFICE OF THE GOVERNOR, replied that the fund was not subject to the sweep because it spent without further appropriation. Once there was money in the fund, the actual expenditures from the fund did not require further appropriation. Mr. Jordan advanced to slide 5, which showed a bar graph entitled "10-year History of Property Premiums/Losses," which illustrated the property premiums the state had paid to losses and included FY 12 to FY 22. He pointed out that in most years premiums far exceeded what had been paid in losses, with the exception of FY 15 when the Crystal Lake Hatchery burned down and there was a $4.4 million loss. He pointed out that in FY 21 there was nearly zero premium because the previous year the state had been unable to get insurance because the market had not been able to meet the states capacity of $7.8 billion worth of property. In FY 22, the state had about a $7.1 million premium. There were losses in the current year that had not been recorded at the time the report was run. Mr. Jordan referenced slide 6, "10-year history of property premiums/losses," which showed a table and a graph entitled '10-year History of Property Premiums/Losses.' He pointed out the blue line showed the state had about $34 million in losses over the ten-year period. The orange line showed the property losses. Mr. Jordan showed slide 7, "Lapse Appropriations Summary": The State Insurance Catastrophic Reserve Fund, Fund # 3209, (Cat Fund) is part of the General Fund and Other Non-segregated Investments (GeFONSI). The GeFONSI are funds that have been pooled together for investment purposes. The Cat Fund is part of the Non-MOU group, which allows for the interest earned to be deposited back into the General Fund. Mr. Jordan noted that he had a fiscal note he could address. 2:44:03 PM AT EASE 2:44:31 PM RECONVENED Co-Chair Bishop set an amendment deadline of Friday, April 22nd at 5 oclock. HB 102 was HEARD and HELD in committee for further consideration. Co-Chair Bishop discussed the agenda for the following day. ADJOURNMENT 2:45:02 PM The meeting was adjourned at 2:45 p.m.