SENATE FINANCE COMMITTEE February 27, 2014 9:08 a.m. 9:08:44 AM CALL TO ORDER Co-Chair Kelly called the Senate Finance Committee meeting to order at 9:08 a.m. MEMBERS PRESENT Senator Pete Kelly, Co-Chair Senator Kevin Meyer, Co-Chair Senator Anna Fairclough, Vice-Chair Senator Click Bishop Senator Mike Dunleavy Senator Lyman Hoffman Senator Donny Olson MEMBERS ABSENT None ALSO PRESENT Michael Pawlowski, Deputy Commissioner, Strategic Finance, Department of Revenue; Joe Balash, Commissioner, Department of Natural Resources; Janak Mayer, Partner, enalytica; Nikos Tsafos, Partner, enalytica. SUMMARY SB 138 GAS PIPELINE; AGDC; OIL & GAS PROD. TAX SB 138 was HEARD and HELD in committee for further consideration. PRESENTATION: SECTIONAL, LONG and SHORT TERM FISCAL IMPACTS PRESENTATION: DECISIONS, ALIGNMENT, PRICE, COST and RISK SENATE BILL NO. 138 "An Act relating to the purposes of the Alaska Gasline Development Corporation to advance to develop a large- diameter natural gas pipeline project, including treatment and liquefaction facilities; establishing the large-diameter natural gas pipeline project fund; creating a subsidiary related to a large-diameter natural gas pipeline project, including treatment and liquefaction facilities; relating to the authority of the commissioner of natural resources to negotiate contracts related to North Slope natural gas projects, to enter into confidentiality agreements in support of contract negotiations and implementation, and to take custody of gas delivered to the state under an election to pay the oil and gas production tax in kind; relating to the sale, exchange, or disposal of gas delivered to the state under an election to pay the oil and gas production tax in kind; relating to the duties of the commissioner of revenue to direct the disposition of revenues received from gas delivered to the state in kind and to consult with the commissioner of natural resources on the custody and disposition of gas delivered to the state in kind; relating to the authority of the commissioner of natural resources to propose modifications to existing state oil and gas leases; making certain information provided to the Department of Natural Resources and the Department of Revenue exempt from inspection as a public record; making certain tax information related to an election to pay the oil and gas production tax in kind exempt from tax confidentiality provisions; relating to establishing under the oil and gas production tax a gross tax rate for gas after 2021; making the alternate minimum tax on oil and gas produced north of 68 degrees North latitude after 2021 apply only to oil; relating to apportionment factors of the Alaska Net Income Tax Act; authorizing a producer's election to pay the oil and gas production tax in kind for certain gas and relating to the authorization; relating to monthly installment payments of the oil and gas production tax; relating to interest payments on monthly installment payments of the oil and gas production tax; relating to settlements between producers and royalty owners for oil and gas production tax; relating to annual statements by producers and explorers; relating to annual production tax values; relating to lease expenditures; amending the definition of gross value at the 'point of production' for gas for purposes of the oil and gas production tax; adding definitions related to natural gas terms; clarifying that credit may not be taken against the in-kind levy of the oil and gas production tax for gas for purposes of the exploration incentive credit, the oil or gas producer education credit, and the film production tax credit; making conforming amendments; and providing for an effective date." 9:10:05 AM ^PRESENTATION: SECTIONAL, LONG and SHORT TERM FISCAL IMPACTS 9:10:26 AM Co-Chair Kelly welcomed the presenters. 9:11:39 AM AT EASE 9:12:36 AM RECONVENED MICHAEL PAWLOWSKI, DEPUTY COMMISSIONER, STRATEGIC FINANCE, DEPARTMENT OF REVENUE, (DOR) explained the document titled "CS FOR SB 138 (RES): Commercial Production of North Slope Gas SECTIONAL ANALYSIS: 28-GS2806\O" (copy on file): Section 1 sets out the legislative findings that the commercial production of gas deposits from the North Slope is of vital public interest that will provide benefits to the state; therefore it is the intent of the legislature that further progress towards this goal incorporate consideration of the provisions as set out in this section. Section 2 amends AS 31.25.005, related to the purpose of the Alaska Gasline Development Corporation (AGDC), to add new subsections (4) and (5) for the advancement of a large-diameter natural gas pipeline project through acquiring an equity interest in the large- diameter pipeline project and developing treatment and liquefaction facilities through the subsidiary created in new AS 31.25.122. Section 3 conforms AS 31.25.010, the structure of AGDC related to dissolution, to include reference to a large-diameter natural gas pipeline project. Section 4 amends AS 31.25.080(f) to allow the AGDC in- state gas pipeline project developers to continue to coordinate with the developers of large-diameter natural gas pipeline to the maximum extent practicable without delaying the progress of developing the in- state natural gas pipeline. In coordinating with the developers of a large-diameter natural gas pipeline, AGDC may use money appropriated for that purpose under AS 31.25.110 but may not use money appropriated for the in-state gas pipeline fund in AS31.25.100. This section removes the description of a large diameter natural gas pipeline, the 'common' status of pipeline facilities, and portions of the area description related to a gas pipeline from the North Slope. Section 5 amends AS 31.25.100 to direct that money appropriated to the in-state natural gas pipeline fund may not be used for the large-diameter natural gas pipeline project under new AS 31.25.005(4) and (5) and AS 31.25.080(f). Section 6 establishes AS 31.25.110, the Large-Diameter Natural Gas Pipeline Project fund in order to fund the purposes of the subsidiary established in AS 31.25.122. Money appropriated to the Large- Diameter Natural Gas Pipeline Project fund may not be used for the purposes of the in-state natural gas pipeline under AS 31.25.005(1). Money appropriated to the Large-Diameter Natural Gas Pipeline Project fund for the purpose of AS 31.25.005(4) and (5), the large- diameter natural gas pipeline project, is to be held in an account created within the fund for that purpose. Section 7, related to subsidiaries created under AS 31.25.120 to specify that a subsidiary corporation under this section may only use money appropriated for the in-state natural gas pipeline under AS 31.25.100. 9:18:29 AM Senator Dunleavy wondered if the subsidiary was modeled after an existing model elsewhere in the world. Mr. Pawlowski replied that the subsidiary was not modeled after an existing structure. It was modeled with support from contract counsel on corporate structures with the Department of Law (DOL) with specific intent to provide as bright a line within the Alaska Gasline Development Corporation (AGDC) as possible. Recognizing that there would be a discussion with the legislature how the relationship should be structured for AGDC to fulfill the mission that the legislature had tasked. He stated that the AGDC sections understood that the subsidiary was based on Alaska corporate law. 9:19:28 AM AT EASE 9:20:16 AM RECONVENED Mr. Pawlowski looked at Section 8: Section 8 adds new section AS 31.25.122 to establish a subsidiary for a large-diameter natural gas pipeline project as a public corporation and a government instrumentality for administrative purposes but with a legal existence independent from the state and the AGDC. The purpose of the subsidiary is to acquire state equity interests in components of a large- diameter natural gas pipeline project, including pipelines, treatment, liquefaction and marine terminal facilities. The subsidiary may use money appropriated under AS 31.25.110 and may not to use money appropriated to the in-state natural gas pipeline project fund in AS 31.25.100. Subsection (b) creates a seven member board of directors of the subsidiary. Subsection (d) sets out purposes, (e) allows the AGDC to transfer assets, except for revenues as restricted by AS 31.25.100 to the subsidiary created under this section. Some of the statutory provisions applicable to the AGDC are incorporated to aid in the operation of the subsidiary. Subsection (f) relates to employees of the subsidiary while (g) describes the conditions of termination of the subsidiary. Mr. Pawlowski explained Section 9: Section 9 amends AS 31.25.390(5), the definition of "in-state natural gas pipeline", by adding a reference to AS 31.25.005(1). Mr. Pawlowski looked at Section 10: Section 10 adds new definitions in AS 31.25.390. New subsection (7) defines a "large-diameter natural gas pipeline project" and (8) defines a "subsidiary board" as meaning a subsidiary under AS 31 25.122. Mr. Pawlowski explained that the next sections would focus on the process of the project, rather than the state's specific involvement. 9:22:55 AM JOE BALASH, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, (DNR) looked at Section 11: Section 11 amends the authority of the commissioner of the Department of Natural Resources (DNR) by adding new paragraphs (10) - (13) to AS 38.05.020(b). Effective immediately, the DNR commissioner may enter into commercial agreements of not more than two years duration for project services related to the North Slope natural gas project. In consultation with the Commissioner of Revenue, the DNR commissioner may participate in negotiations associated with a North Slope natural gas project. A contract negotiated in which the state is a party would not be effective against the state without legislative authorization for the governor to execute the contract. Paragraph (12) permits the DNR commissioner to enter into confidentiality agreements to maintain confidentiality throughout contract negotiations and contract implementation. Confidential information obtained under paragraph (12) shall be shared with the legislature only in committees held in executive session or under confidentiality agreements. Final contracts subject to approval by the legislature would not be confidential. Commissioner Balash looked at Section 12: Section 12 adds new paragraph (13) to allow the DNR commissioner, in consultation with the commissioner of revenue, to take custody of gas delivered to the state under new AS 43.55.014(b), to manage project services and the disposition of gas delivered to the state under new AS 43.55.014(b). Mr. Pawlowski explained effective dates were often the reason that a section may seem like a repeat of a previous section. He stressed that taxation was based on the calendar year, not the fiscal year. 9:26:15 AM AT EASE 9:27:01 AM RECONVENED Commissioner Balash looked at Section 12, page 15, lines 23 through 26. He stressed that the language was attempting to ensure that there were no duplicating efforts between DNR and DOR. Commissioner Balash explained Section 13: Section 13 clarifies AS 38.05.180(i) with a conforming amendment that the exploration incentive credit may be applied against the oil and gas production tax levied under AS 43.55.011. Commissioner Balash looked at Sections 14 and 15: Sections 14 and 15 adds a new subsection (hh) to the Alaska Land Act, AS 38.05.180, which deals with oil and gas leasing, to permit the DNR commissioner to propose modifications to existing oil and gas leases relating to the state's ability to take royalty gas in kind or in value, the establishment of values for the state's royalty gas and deductions for transportation costs, and the fixation of royalty rates of not less than 12.5 percent and modifications to net profit share terms in oil and gas leases. Modifications to existing oil and gas leases would require a written determination by the DNR commissioner that a North Slope natural gas project has sufficient financial commitment and commitment of gas from the leases to be modified, in addition to concurrence of the lessees to the modification. Mr. Pawlowski explained that had been some mention of "tax as gas." The Heads of Agreement (HOA) stated that in addition to taking royalty in-kind, there would be an opportunity instead of tax payments for the state to receive a larger share of the molecules. The legislation would allow DOR to leverage the expertise and the existing mechanisms that DNR to dispose of royalty. There was no desire to recreate a royalty and commercial section in DOR to handle the molecules that would be received as tax payments. Commissioner Balash explained Sections 16 through 19: Sections 16 through 19 amend AS 38.05.183, related to sales of royalty oil or gas, by adding references to gas delivered to the state under AS 43.55.014(b), the levy of production tax on gas to be paid in gas for certain North Slope leases. Commissioner Balash highlighted Section 20: Section 20 adds two new subsections (26) and (27) in AS 38.05.965. Subsection (26) defines "North Slope natural gas project;" subsection (27) defines "project services." 9:32:32 AM Mr. Pawlowski shared that the following sections referred to specifically to tax provisions. Mr. Pawlowski outlined Section 21 and 22: Sections 21 and 22 amend AS 40.25.100 related to the confidentiality of tax information to clearly establish as confidential information related to contract negotiations for a North Slope natural gas project. Section 21 references new subsection (k) in AS 43.05.230 to except from taxpayer confidentiality provisions the name of each person that makes an election to pay the gas production tax from modified North Slope leases in gas and the amount of gas subject to that election. Mr. Pawlowski explained Section 23: Section 23 amends AS 40.25.120(a) to establish an exception in public records for information confidential under the new provisions of AS 38.05.020(b) (related to contract negotiations for a North Slope natural gas project). Mr. Pawlowski addressed Sections 24 and 25: Sections 24 and 25 amend the authority of the commissioner of the Department of Revenue (DOR) by adding new paragraphs (16) and (17) in AS 43.05.010. Effective immediately, paragraph (16) provides that the DOR commissioner may consult with the DNR commissioner on negotiations associated with a North Slope natural gas project. Section 24 amends AS 43.05.010 by adding paragraph (17) to provide that the DOR commissioner direct the disposition of revenues received from gas delivered to the state under AS 43.55.014(b) by entering into agreements with the DNR commissioner. Mr. Pawlowski outlined Section 26: Section 26 adds new subsection (k) to AS 43.05.230 to except from taxpayer confidentiality provisions the name of each person that makes an election to pay, after 2022, the gas production tax in gas and the amount of gas subject to that election. Mr. Pawlowski discussed Section 27: Section 27 amends AS 43.20.144(f) to clarify that gas subject to an election to pay the oil and gas production tax on gas as gas under AS 43.55.014 is included the extraction factor in the Alaska Net Income Tax Act. Mr. Pawlowski looked at Section 28: Section 28 amends AS 43.55.011(e), the levy of the oil and gas production tax, to add reference to the separate levy under AS 43.55.014 for certain North Slope gas. For oil and gas produced after January 1, 2014 and before January 1, 2022, AS 43.55.011(e)(2) would levy on producers of oil and gas produced each calendar year a flat rate tax of 35 percent of the production tax value of taxable oil and gas produced from each lease or property in the state. No change is made to current tax ceilings that apply to Cook Inlet oil and gas, gas produced outside the Cook Inlet basin and used in the state, and oil and gas produced from new fields outside the Cook Inlet basin and south of the North Slope. For oil and gas produced on or after January 1, 2022 (after expiration of the tax ceilings for Cook Inlet oil and gas, and gas produced outside the Cook Inlet basin and used in the state), AS 43.55.011(e)(3) would levy on producers of oil produced each calendar year a flat tax rate of 35 percent of the production tax value of taxable oil produced from each lease or property in the state and on producers of gas, and a flat tax rate of 10.5 percent of the gross value at the point of production of gas produced from each lease or property in the state. (Oil and gas subject to AS 43.55.011(p) continue to be taxed at no more than four percent of gross value at the point of production until 2027.) The tax on gas for which the DOR commissioner has approved an election to pay in gas would be levied under AS 43.55.014. 9:38:57 AM Mr. Pawlowski outlined Section 29: Section 29 amends AS 43.55.011(f), the alternate minimum tax on North Slope oil and gas, to retain the current minimum tax until January 1, 2022. After that date, the minimum tax would apply to oil produced on the North Slope. A minor amendment adds the reference to the tax applying to leases or properties "that include land" to ensure that property that straddles 68 degrees North latitude will be considered north of 68 degrees North latitude for purpose of the alternate minimum tax. Co-Chair Kelly asked for clarification of page 27, line 14. Mr. Pawlowski responded it was in Section 29, and stated the minimum tax on oil after January 1, 2022, because there was a "carving out" of a minimum tax that was higher than the 4 percent. Mr. Pawlowski addressed Section 30: Section 30 adds AS 43.55.014 which allows producers to make an irrevocable election, under regulations adopted by DOR, to pay the oil and gas production tax in gas for gas produced from oil and gas leases whose terms have been modified under proposed AS 38.05.180(hh). 9:43:38 AM AT EASE 9:46:26 AM RECONVENED Mr. Pawlowski continued to discuss Section 30: The levy would be 10.5 percent of the taxable gas when and as the gas is produced. The producer would pay the tax by delivering the gas to the state at the point of production. The DNR would manage the custody and disposition of gas delivered to the state. Gas subject to this provision would not include gas flared, released, or allowed to escape upstream of the point of production, or to gas used in lease operations or for repressuring. Tax deficiencies and interest and penalties on any tax deficiency would be accounted for as if the tax was levied for money under AS 43.55.011(e). This section would take effect on January 1, 2015 to be applied to gas produced from certain North Slope leases on and after January 1, 2022. Mr. Pawlowski discussed Sections 31 and 32: Sections 31 and 32 are conforming amendments to the oil and gas producer education credit, AS 43.55.019, to clarify that the credit can be applied to tax liability under AS 43.55.011(e) only. Commissioner Balash explained the construct was for the state to participate in the project and take a share of the gas. He stated that the gas was needed in order to run the state's share of the infrastructure. There were contracts with providers, so it was important to maintain consistent and predictable gas production throughput. Mr. Pawlowski spoke to Section 33: Section 33 amends AS 43.55.020(a), monthly installment payments of estimated tax, to add provisions for payment of tax after January 1, 2022 and to clarify the tax rates that apply to oil and gas produced after a certain date. Monthly installment payments for oil and gas produced on or after January 1, 2022 are in new subsection (a)(7). Mr. Pawlowski explained Sections 34 and 35: Sections 34 and 35 are conforming changes to AS 43.55.020, monthly installment payments. Subsection (g) is amended to account for new tax provisions for oil and gas produced after January 1, 2022. A similar conforming change is made in AS 43.55.020(h) to account for interest on overpayments of installment payments. 9:51:07 AM Mr. Pawlowski addressed Sections 36 and 37: Sections 36 and 37 amends AS 43.55.020(l) and adds subsection (m), related to making settlements by a producer with private landowner royalty owner, to account for making a settlement with the royalty owner for gas taxable before January 1, 2022 and under new AS 43.55.014. Mr. Pawlowski highlighted Section 38: Section 38 amends AS 43.55.030, annual statements by producers and explorers, to require reporting of the amount of gas produced from a lease or property for which tax is levied under AS 43.55.014 and the amount of gas delivered to the state under AS 43.55.014. Mr. Pawlowski discussed Section 39: Section 39 amends AS 43.55.160(a), calculation of annual production tax values, to clarify and conform to the levy of tax under AS 43.55.011(e)(2) for oil and gas produced before January 1, 2022. Mr. Pawlowski outlined Section 40: Section 40 amends AS 43.55.160(e), related to determination of excess lease expenditures for the purpose of calculating a carried-forward loss credit, to account for annual production tax values for oil produced on and after January 1, 2022. Mr. Pawlowski looked at Section 41: Section 41 amends AS 43.55.160(f), a 20 percent gross value reduction for certain oil and gas produced north of 68 degrees North latitude, so that gas produced on and after January 1, 2022 would not qualify for the gross value reduction in this section. Mr. Pawlowski discussed Section 42: Section 42 amends AS 43.55.160(g), a 10 percent gross value reduction for certain oil and gas produced from a unit north of 68 degrees North latitude made up solely of leases that have a royalty share of more than 12.5 percent in amount or value of the production removed or sold from the lease so that gas produced on and after January 1, 2022 would not qualify for the gross value reduction in this section. Mr. Pawlowski highlighted Section 43: Section 43 amends AS 43.55.160, calculation of annual production tax values, to add a new subsection (h) for calculation of annual production tax values for oil produced on and after January 1, 2022. On and after January 1, 2022, gas would be taxed at a percentage of gross value. Accordingly, there would be no need to calculate a production tax value (gross value at point of production less lease expenditures) for gas. Producers would still calculate a production tax value of oil taxable under AS 43.55.011(e) for the segments set out in AS 43.55.160(h). Mr. Pawlowski explained Section 44: Section 44 makes a conforming amendment to AS 43.55.165, lease expenditures, to exclude as a deduction from lease expenditures the tax levied under AS 43.55.014. Mr. Pawlowski discussed Sections 45 through 47: Sections 45 through 47 amend, for purposes of the oil and gas production tax, the definitions of "gas processing plants" and "point of production" for gas to be upstream of either the first point where accurately measured, the inlet of a pipeline transporting the gas to a gas treatment plant, or the inlet of any gas pipeline system transporting gas to market. Section 46 adds a definition of "gas treatment plant". Co-Chair Kelly asked what section was currently being discussed. Mr. Pawlowski stated that he was broadly speaking to Section 45. 9:58:40 AM Mr. Pawlowski outlined Section 48: Section 48 makes conforming amendments to AS 43.98.030, the film production tax credit, to limit the applicability of the credit to the tax levied by AS 43.55.011. Mr. Pawlowski spoke to Section 49: Section 49 amends uncodified law to add a new section related to direction that at the time the commissioner of natural resources submits the first contract to the legislature for approval, the commissioner of revenue shall present a plan and suggested legislation to allow a resident of the state to participate as a co- owner in a North Slope natural gas pipeline, and sets out factors that must be in the plan. Mr. Pawlowski outlined Section 50: Section 50 allows the DNR and the DOR to adopt regulations to implement this Act. Mr. Pawlowski explained Section 51: Section 51 instructs the reviser of statutes to make a title change to AS 38.05.183 to include AS 43.55.014(b). Mr. Pawlowski discussed Sections 52 and 53: Sections 52 and 53 set effective dates for different sections of the bill. Sections 1 -10, 12, 13 19, 20, 22, 23, 30, 31, 47 and 48 would be effective immediately. The other sections would be effective January 1, 2015. 10:00:58 AM Co-Chair Meyer wondered if the state received 10 percent of the gas that was produced on federal land. Mr. Pawlowski replied that the tax for that gas would be 10.5 percent of the gross value of that gas. Co-Chair Meyer queried the federal take of the gas. Mr. Pawlowski responded that he did not know the specific royalties of the federal take, but shared that the federal government received corporate income tax. Co-Chair Meyer wondered if there would be problems administering the public management. Mr. Pawlowski replied that the provision in the legislation was uncodified direction to DOR to manage those issues. He felt that there may or may not be an administrative burden. He stressed that it would not be determined until the work was complete. He felt that the provision allowed for DOR to conduct the due diligence in order to determine the possibility of the management. 10:02:58 AM Vice-Chair Fairclough noted that there had some conversation about the subsidiary. She referred to the Denali Project, and remarked that there was a partnership. She wondered why AGDC was not considered a subsidiary. Mr. Pawlowski replied that the administration looked at the HOA as a proposal. He stressed that there was a focus on how the stated participated in the project. He stated that the pipeline was in recognition that AGDC was required by statute to develop a standalone pipeline. Vice-Chair Fairclough surmised that attorneys would be evaluating those proposals. She looked at Section 13, and queried the maximum credit that could be obtained at that allowance. Commissioner Balash replied that the credit was considered a DNR credit. Mr. Pawlowski looked at page 16, line 5 and remarked that the credit may not exceed 50 percent of the cost of the drilling or geophysical work. Additionally, on page 16, line 9 stated that the credit may not exceed 50 percent of the payment. Therefore, one could only offset 50 percent of the tax payment. 10:08:47 AM Vice-Chair Fairclough wondered if there was a cap on the credits that were taken against the oil revenues. Mr. Pawlowski replied that he would provide more information about the state's credit system. He furthered that the state had many different credit provisions, and each one may have specific limitations. Vice-Chair Fairclough stressed that she was concerned about returning value to the people of Alaska for participation in the process. She wanted to ensure the best partnership in a commercial relationship. She understood that gas was used to run the oil producing facilities, and was not calculated in a tariff. Mr. Pawlowski agreed. Vice-Chair Fairclough surmised that the best practice for gas production was receiving 25 percent value and 25 percent expense in a full partner in the commercial relationship. She wondered if it was wise to allow monetization of upstream gas on the downstream, but not have it count in the project. Mr. Pawlowski responded that Section 30 of the legislation addressed that issue. Vice-Chair Fairclough agreed and added Section 43 also addressed a similar issue, which dealt with lease expenditures not counted as oil or gas. Mr. Pawlowski agreed, and felt that Section 30 addressed more of her concerns. He stated that the key difference was 10.5 percent of the gas produced at the point of production. He stated that it was included to recognize that there was gas used in the project as fuel for running the oil facilities. A gross value calculation would have deducted the fuel expenses. He stated that DOR wanted to ensure that the state had the full molecules on the downstream side. He explained that the upstream use was meant for molecules to run the power and lifting the oil as part of normal oil field operations. Development of the in kind provision was careful to state that it was 10.5 percent of the gas produced at the point of production, so DOR would not undercount the molecules that the state was entitled to meet its share of fuel cost and movement in the project. Vice-Chair Fairclough perceived that if there was a penalty or dispute, the interest would not be in molecules, but rather be in cash. Mr. Pawlowski responded that the provision was on page 28, line 18, and agreed that the deficiency would be in cash. Vice-Chair Fairclough understood that Commissioner Balash said that the state must maintain its throughput of gas moving through the line to protect the state's interests. She wondered if the reason for taking the gas in kind rather than in value at the point of sale was because, as a full commercial partner, the state would carry the expenses of the entire project. The state must ensure that the throughput was high, so it would receive the maximum benefit of being a full partner. If the state's percentage of gas dropped below its ownership equity interests, the state would carry a different burden of those expenses because it did not receive the full value of what was moving through the line. Commissioner Balash responded that the HOA spoke to the offtake and balancing agreements that were necessary for DOR and DNR to be comfortable entering into those project services agreements downstream for all facilitations. He stressed that the state would be seeking its own certainty, in order to ensure that it could deliver on the obligations to customers and citizens. 10:17:09 AM Vice-Chair Fairclough surmised that Alaska would attempt to hire someone to manage and purchase the throughput. Mr. Pawlowski replied that the state would need certainty for the gas coming into the project, and it would need certainty for the LNG leaving the project. He stressed that both ends of the equation was necessary. Vice-Chair Fairclough felt that there could be a perception in a few years about the energy company partners making more money than Alaska. The perception may be a result of the attempt to bring affordable to energy Alaskans. She stressed that the partners were global organizations that did not necessarily report profits in the same way that the state reported profits inside of revenue books. Mr. Pawlowski responded that her summation was very accurate. Senator Bishop was not convinced that AGDC should be considered a subsidiary. He felt that there should be further analysis of the necessity of having AGDC as a subsidiary. He felt that there needed to be extremely qualified people to be a part of the board and run AGDC. He stressed that there were a limited number of qualified people in the state. Senator Dunleavy wondered if it would be an all or nothing proposal when the offtake and balancing agreements were presented to the legislature. Commissioner Balash responded that the interdependencies of all of the agreements would be such that it would be difficult to modify an aspect of one agreement, and not have it impact another agreement. The expectation was that the contracts that would come back to the legislature would look similar to the royalty sale contracts. 10:23:23 AM Senator Dunleavy surmised that the committee should not consider amendments. Mr. Pawlowski responded that the ultimate contract vote was taken differently than a bill vote. The opportunity for legislative engagement was not at the end of the process, and felt that interaction with the legislature was imperative in the executive sessions. Senator Olson remarked that there was a concern of the North Slope Borough and other boroughs regarding what would happen in the future. He did not see any provision giving those boroughs satisfaction and stability. He felt that those boroughs should be consulted regarding their real estate taxing status. He wondered if there could be a definition of the consultation, so those communities could be comfortable with the legislation. Mr. Pawlowski replied that when the administration and the companies engaged in the development of the HOA, it was a problem solving exercise. He stated that there were certain problems that were not the responsibility of the parties involved in the HOA. He stated that property tax was provided by the legislature and local governments. Senator Olson wondered if there would be opposition to an amendment that would further define consolation with municipalities. Mr. Pawlowski responded that DOR would be open to discussion regarding that issue. 10:27:40 AM AT EASE 10:41:26 AM RECONVENED 10:41:45 AM AT EASE 10:41:59 AM RECONVENED 10:42:07 AM ^PRESENTATION: DECISIONS, ALIGNMENT, PRICE, COST and RISK 10:42:20 AM JANAK MAYER, PARTNER, ENALYTICA, discussed the PowerPoint, "In Kind vs. in Value, Risks and Midstream Options" (copy on file). He stated that there was an attempt to provide a high level overview the week prior, of some of the key issues that the legislature needed in order to consider the legislation. There was a discussion regarding some of the questions associated with the choice of the state as a taxing authority that took royalty and tax at the well head, and the issues of the overwhelming value of the project consumed at the midstream, leaving a relatively low residual value at the well head. He felt that the state might want to consider participating more broadly across the value chain. Mr. Mayer highlighted slide 4, "In Kind Vs. in Value: Project Options." He stated that the slide reflected the world of the HOA. It contrasted the status quo, of the state taking value through the royalty and taxing with a profit based production tax with value at the well head. It was contributing to upstream costs solely and directly through taxes and/or deductions in taxes and credits at the well head, but had no share of the subsequent gas treatment facility, pipeline, and liquefaction project. The state did not have to take on any debt to finance any commitment, because it did not have to contribute any of the capital cost of the facilities. He stated that the slide also dealt with the issue of the question of the tariff, subsequently on the entirety of the midstream - gas treatment processing, pipeline, and liquefaction. Those processes were crucial to the question of how much residual value, if any, there was for the state to tax at the well head. He stated that the slide conversely envisioned the end point of the HOA process, if the HOA could be successfully negotiated. The state would define a share of gas that it took through royalty and the growth production taken instead as gas instead of tax, where it had defined a share of ownership in the entirety of the midstream 10:49:22 AM Mr. Mayer discussed slide 5, "RIV: Upstream Absorbs All the Price Risk, Fixed nature of tariff in 'in value' alternative amplifies impact of price movement on state returns." He stated that the slide was a graphical version of some slides from the Revenue Sources Book calculation in the previous presentation. If the state was simply a taxing authority, that took its royalty in value and took production tax on a profit base, the state would, counter- intuitively, become a "shock absorber." He stated that the slide would show how the state should not be fully in and transparent. He stressed that there was a large fixed tariff payment, which was a very large portion of the total value. He stated that the graph showed a barrel of oil (BOE) equivalent terms and in corresponding dollar per BTU terms to an LNG form delivered to an Asian market. He stated that, when prices were high, there would be a higher net price of oil, because LNG was priced at a discounted relationship to oil. 10:52:33 AM Mr. Mayer looked at slide 6, "'In Kind' with Equity Offers More Downside Protection, 'In value' structure protects producers, not sate, in low price environment because of tariff component, Higher State of Alaska (SOA) equity pushes up the price at which 'in value' is better than equity." If one took slide 5's understanding and looked at more results of what he saw as the overall assumptions through an economic model through a lifetime of a project. He felt that the slide reflected the outcomes of the choices that the state faced about the value that it could receive from the project through different modes of participation, either as a taxing entity or as an in kind participant. The green line was the accrued value in terms of cumulative cash flows over the life of the project. If all of the off tax cash flows that would come from the project, the graphs showed what it would look like for each participant. The left graph was the state of Alaska, the middle was the producers, and the right graph was the federal government. The Y-axis was the total cash flow value across time to each party, and the X-axis was the price of LNG delivered into Asia on a scale from $10/MMBTU to $18/MMBTU. He stated that the slope of the green line of the left chart was a much deeper slope. He stressed that the state would have the greatest share of price risk in the status quo in value scenario, because so much value could disappear at the well head when prices decline due to the fixed tariff that applied to the gas treatment, pipeline, and liquefaction. The red and yellow lines represented the world of in kind participation. The red line represented a 20 percent share, and the yellow line represented a 25 percent share. It showed that, at high prices, the state was not as well off as it would be in an in value world. Conversely, at low prices, the state was substantially better. He remarked that in kind participation protected the state better from price risk than in value participation, because of the intuition in the previous slide. 10:57:26 AM Mr. Mayer explained slide 7, "SOA Share of value Higher than Equity Share, SOA participation in midstream means fixed tariff for producers no longer 'guaranteed'." He stated that it was easy to look at the state bearing 25 percent of the cost, if the state had 25 percent of the cost, and therefore the state had 25 percent of the overall value that the project created. He stressed that that assumption was not accurate. He pointed out that the state would take much more than 25 percent in most circumstances. The slide showed the net present value of those same cash flows over the life of the project, and looked at the total economic value accrual on a percentage basis. He pointed out that in all cases, there was substantially more than 25 percent at the total value going to the state of Alaska. HE stressed that there was a focus of a range from 30 to 50 percent depending. The state would have the highest share of value in the lowest prices and would fall at higher prices in-kind scenario. The in value scenario reflected an opposite outcome for the state. Mr. Mayer highlighted slide 8, "SOA Equity Leads to higher Government take on Average; 'In value' entails lowest government take, especially in low prices as cash goes to producers; Split between Fed vs. SOA split depends on both 'in value vs. 'in kind' as well as SOA equity share." The state showed the same figures in cumulative cash flows over the life of the project in terms of the share going to the state, producer, and federal government in the three different scenarios: in value, 20 percent equity, and 25 percent equity. Co-Chair Kelly handed the gavel to Co-Chair Meyer. 11:03:16 AM Senator Bishop looked at the left column, and noted that it showed 50 percent in value total government take between the green and yellow bars. Mr. Mayer agreed, and stated that it was at the lower price levels, but rose to the mid- fifties at the higher levels. Senator Bishop wondered if there could be a reflection of the cash returned to the state, if there was an assigned cash value. Mr. Mayer remarked that one should not look at the sum of the green and yellow bars, but rather the take to the state of Alaska. He remarked that there would be a dramatic drop at lower price levels, and it was taken by the federal government. He stressed that the state was taking most of its value from taxing at the well head, but the federal government was taxing at the entire value stream. Co-Chair Meyer handed the gavel to Co-Chair Kelly. 11:06:27 AM Co-Chair Meyer looked at the price per BTU starting at $10, but there were other contracts that were below $10. He wondered why that was the case. NIKOS TSAFOS, PARTNER, ENALYTICA, responded that, looking at gas pricing, North America had some of the lowest gas prices in the world. He stated that Europe was somewhere in the middle, with pricing of between $9 to $12. Asia was fairly high, with pricing near between $13 to 16. He announced that there were some slides later in the presentation that dealt with the structure of pricing. Co-Chair Meyer felt that there should be a worst case scenario represented in the presentation. He wondered if the supply of gas was becoming more plentiful, so he wondered if there would be more downward pressure put on the prices rather than the upward price. Mr. Tsafos replied that a worst case scenario would be beneficial to the analysis. He stated that there could be a point where the project was built, and the day the project goes online when the prices would be much lower than expected. He agreed to provide a worst case scenario analysis. Co-Chair Meyer expressed concern with Russia, and their aggressive low-rate contract acceptance. Mr. Tsafos replied that Russia was not going to "under cut" Alaska, because Russia had a very high cost structure do to environmental and technical issues bringing the gas to market. 11:12:17 AM Vice-Chair Fairclough remarked that Alaska had participated in many different oil tax regimes, so as the worst case scenarios were modeled, she stressed that there would not be final investment decisions until the contracts were signed. Mr. Tsafos agreed, and furthered that there would be a slide related to how the state could contractually protect itself from adverse effects. Vice-Chair Fairclough looked at the bars on slide 8; it appears that the producers make more than the state. She felt that the producers should be reflected as three different companies. Mr. Mayer agreed that the red bars were the combination of three companies. Mr. Mayer addressed slide 9, "Equity Boosts SOA Outlays to $10.2 billion to $12.3 billion; Annual outlays could peak at $2.7 billion (20 percent equity) to $3.3 billion (25 percent equity), assuming no debt; Even in status quo ('in value'), state has outlays through the tax system." The HOA set out a possibility of a total state share. 11:20:16 AM Mr. Tsafos explained slide 10, "Price and Cost Risks; Cost Escalation/Delays." When the state takes equity, it functions like an oil and gas company. The slide was meant to identify what could go wrong in the equity world. It showed a list of LNG projects that were developed over the previous decade, and what kind of delays they faced. Mr. Tsafos discussed slide 11, "Buyers Often Take Equity in LNG Projects." In half of the world's LNG capacity, a share of the LNG is sold to equity partners Such deals can mitigate risk by aligning supplier - buyer interest (e.g. output shortfall) Buyers get sense of supply security, and these deals often open up the project to third-party financing Mr. Tsafos spoke to slide 12, "Project Finance Well Established in LNG." IHS estimates that LNG projects raised over $97 billion in third-party financing since 2000 Financing from project sponsors, export credit agencies, multilateral banks and commercial banks Commercial loans can also secure sovereign guarantees as insurance The Japan Bank of International Cooperation (JBIC) is the largest single provider of funds 11:24:35 AM Mr. Tsafos highlighted slide 13, "SOA Cash Call $4.8 billion - $5.5 billion with 70/30 debt/equity; Peak outlays shrink to $1.2 to $1.3 billion depending on equity level (20 percent or 25 percent)." He stated that the slide compared a world along standard practice in LNG, which showed that the peak outlays may be closer to $1.5 billion. He remarked that the slide was not intended to downplay the state commitment, but to take the overarching number and qualify it based on standard industry practices. Vice-Chair Fairclough referred to a presentation that discussed a pipeline structure. She wondered if the 70/30 debt/equity was the best option for Alaska. Mr. Mayer replied that it was important to differentiate between capital structures for the purpose of tariff setting versus capital structures for the state's share and how it chooses to finance its obligations. Capital structures for rate setting were reflective of the actual capital structure underlying the project. He furthered that there was some regulatory legal fiction that stated that regardless of the actual capital structure, it would be treated as though it was the set tariff. He stated that the MOU showed that there was an assumption that started with the cost of debt was 5 percent, cost of equity was 12 percent, and there would be a capital structure of 75/25 percent split. As a result, there would be a higher leverage with a lower tariff from the state's perspective. 11:29:51 AM AT EASE 11:30:07 AM RECONVENED 11:30:45 AM RECESS 5:05:20 PM RECONVENED Mr. Tsafos addressed slide 14, "Price Exposure Defined at Contract Signing." Oil linkage does not mean identical linkage to oil (e.g. Taiwan, below); bargaining power defines linkage New contracts do not impact existing deals (e.g. new Henry Hub-based LNG vs. existing oil-linked SPAs) But if price is seriously out of sync with fundamentals, parties can trigger a review clause Mr. Tsafos explained slide 15, "Expensive Projects can Hedge Against Volatility." "S-curves" are clauses that change the relationship between oil and gas above or below thresholds Instead of a linear link, gas prices do not rise/fall as much if oil prices rise/fall above certain thresholds They reduce downside risk by forgoing some upside-they can even provide a floor/ceiling on prices 5:16:09 PM Mr. Tsafos looked at slide 16, "Midstream Options: Project Structure." The slide was a simplification of the project, breaking it into four components. He stated that there was a status quo, HOA, MOU Option 1, and MOU Option 2. The status quo was in value and the state had no ownership in the facilities. The state took no debt, and there was a tariff to haggle over matters of valuation. The HOA changed in value to in kind, but not definitively. The HOA took the GTP and LNG ownership from zero to 25 percent. Because there was an ownership interest in the first column of upstream GTP and LNG, the state was required to invest to correspond with the equity. The MOU contemplated two different options, but the in kind, up stream, and LNG ownership stayed the same. The only thing that changed was the ownership of the GTP, treatment plan, and the pipeline. There were two options. The state had a starting point of 25 percent, and the 25 percent would be moved to TransCanada. Therefore, TransCanada was responsible for paying for the 25 percent of the costs of the studies that were linked to the GTP and pipeline. There was an option to buy back, so consider staying with zero or buy back a share of the equity. Mr. Tsafos explained slide 17, "Midstream Options: Options." He remarked that there was an analysis necessary to understand that there was gas in the North Slope and the gas should be brought to market. A liquefaction plant needed to be constructed. He stated that there were, broadly speaking, four ways to structure the midstream, and they were displayed on the slide. 5:23:25 PM Mr. Tsafos discussed slide 18, "Midstream Options: State Interests." Producer-SOA Alignment Minimize disputes over where value is allocated Tariffs reflect value maximization across the entire chain Third-Party Expansion Midstream becomes an enabler for further exploration and development Expansion principles favor development of additional transportation capacity In-state Deliveries Alaskan consumers receive cost at the lowest cost possible (given adequate returns on investment) Execution Pipeline is delivered on time and at the lowest possible cost Continuity and Momentum Project maintains and accelerates current investment interest Project leverages work to date and is not delayed by possible litigation Mr. Tsafos displayed slide 19, "Producer Only: Alignment." Producer-SOA Alignment Significant potential for disputes over allocation of value, and optimal level for midstream tariff Third-Party Expansion Focus on commercializing producers' resources over gas belonging to third parties In-state Deliveries Uncertain tariff for in-state deliveries (of SOA's gas) Execution Strong and proven ability to execute, but midstream becoming less of a core focus for majors Continuity and Momentum Uncertainty about possibility of litigation and loss of work done to date Mr. Tsafos explained slide 20, "SOA Equity: More Expansion Bias but Burdon on SOA." Producer-SOA Alignment Strong alignment between producers and SOA Third-Party Expansion Relies on SOA to drive expansions, seeking new entrants and / or new partners; SOA may not be best placed to fill this role In-state Deliveries SOA can use its equity-entitled capacity to carry gas to local markets at lower cost Execution Strong and proven ability to execute for initial investment; expansion will depend on securing capabilities and/or another party Continuity and Momentum Uncertainty about possibility of litigation and loss of work done to date Co-Chair Kelly handed the gavel to Co-Chair Meyer. 5:27:54 PM Mr. Tsafos looked at slide 21, "MOW: expansion Bias and Momentum; Bus Best Deal?" Producer-SOA Alignment Strong alignment between producers and SOA; capital structure for rate-setting purposes appears within norm, but unclear if new bidding could have produced lower tariff Third-Party Expansion TransCanada will be advocate for a project structure that encourages expansion and will have incentive to drive expansion of the infrastructure based on market interest In-state Deliveries SOA can use its equity-entitled capacity to carry gas to local markets at lower cost; proexpansion bias further incentivizes possible in-state deliveries Execution TransCanada brings execution knowhow and expertise, while producers reinforce cost discipline (to ensure lowest possible tariff) Continuity and Momentum Project maintains and accelerates investment interest and leverages work done to date 5:31:08 PM Mr. Tsafos discussed slide 22, "Bid: Will Reward Compensate for Cost in Time and Money?" Producer-SOA Alignment Strong alignment between producers and SOA; new bid could lead to a lower tariff, but it could also lead to a higher one; low investor interest could also slow down entire process Third-Party Expansion Third party will have incentive to drive expansion of the infrastructure based on market interest, but would likely have less influence over current negotiations In-state Deliveries SOA can use its equity-entitled capacity to carry gas to local markets at lower cost; proexpansion bias further incentivizes possible in-state deliveries Execution Third party would presumably bring execution knowhow and expertise, while producers would reinforce cost discipline (to ensure lowest possible tariff) Continuity and Momentum Uncertainty about possibility of litigation and loss of work done to date; HOA negotiations could slow down in anticipation of new bidding process and license award Mr. Tsafos explained slide 23, "SOA Needs to Carefully Weigh Key Questions." What compensation might the SOA have to pay and what intellectual property will Alaska LNG retain? Will the HOA process slow down if the midstream is tied in litigation? What are the odds that a new selection process will deliver better terms than those available today? To what extent was the AGIA process representative of the industry's interest in an Alaskan pipeline? Would a new tariff offset absence from negotiating table; reduced momentum; cost to dissolve AGIA? Mr. Tsafos highlighted slide 24, "Financially, TransCanada Deal is Akin to a Loan." TransCanada shoulders a share of SOA's capital commitments and Alaska repays over time with tariff SOA outlays fall by $1,700 million (no buyback) to $1 billion (buyback) during development period Mr. Tsafos explained slide 25, "TransCanada Lowers SOA Outlays by $3 billion to $5 billion." TransCanada's participation would lower SOA peak outlays by $0.8 billion to $1.4 billion Buyback option also lowers outlays before FID (pre- 2019) 5:44:05 PM Co-Chair Meyer wondered what it would look like if TransCanada was not involved, and it was only the three producers and the state of Alaska, with one of the producers building the pipeline. Mr. Tsafos responded with slide 20. He stressed that the producers were in the business of finding and developing oil and gas. The infrastructure was generally seen as what the facilities do to find and produce oil and gas. TransCanada was in the business of building pipelines. Co-Chair Meyer wondered if there may be more motivation to get more involvement in the pipeline, if a producer owned the pipeline. Mr. Tsafos responded that a producer built a pipeline with a great capacity, but only used a limited amount of the space, one could approach the producer to use the spare capacity and the producer could make that allowance. 5:50:26 PM Mr. Mayer furthered that financially, the deal was equivalent to a 7 percent interest loan. The state would put up less capital and take slightly less of the subsequent cash flows, because it needed to pay the tariff to TransCanada. If there were no other benefits of TransCanada's involvement, one may look at it and believe that it was an expensive loan, because the state could raise the capital more cheaply. He stated that one of the benefits was that it is not a loan that the state would carry on its balance sheet, so the overall calculation would be considered based on many factors. He stressed that there were considerations regarding expansion orientations that were possible with the contract with TransCanada. It could be argued that the state had a strong pro-expansion orientation. He felt that the question was how much the state wants to or thinks it is capable of becoming an effective pipeline company. He stated that the current issues were different for the pipeline and GTP than they were for the liquefaction. He felt that the differentiation was essential to determine where the third party involvement would be in the different components of the project. 5:55:04 PM Co-Chair Meyer surmised that a partnership with TransCanada may encourage expansion of the project in the future. He wondered if RCE oversaw the expansion. Mr. Mayer deferred to the administration for regulatory information. He stressed that that MOU would codify in contract the actual capital structure. Vice-Chair Fairclough had a constituent that had concerns regarding whether or not gas could be committed to the project. She hoped that there would be an opportunity to present the available of gas when the project goes online for production. She shared that Larry Persily had contacted her office regarding the federal guarantee. The federal guarantee was for a North American project specifically. It was his estimation that congress would probably not be amenable to help the state move the gas to another country. Co-Chair Meyer looked at the "TransCanada Capital Project Performance" (copy on file). He stated that TransCanada's history was substantial and impressive. Vice-Chair Fairclough remarked that TransCanada was the only North American pipeline company that had worked in the Arctic. Co-Chair Meyer pointed out that their history seemed very impressive. Vice-Chair Fairclough remarked that the federal government may have some issues regarding the cost overruns of TransCanada and the Keystone project. SB 138 was HEARD and HELD in committee for further consideration. ADJOURNMENT 6:01:48 PM The meeting was adjourned at 6:01 p.m.