Legislature(2007 - 2008)SENATE FINANCE 532
11/07/2007 01:00 PM Senate FINANCE
| Audio | Topic |
|---|---|
| Start | |
| HB2001 | |
| Adjourn |
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
| += | SB2001 | TELECONFERENCED | |
SB 2001 "An Act relating to the production tax on oil and gas and to conservation surcharges on oil; relating to the issuance of advisory bulletins and the disclosure of certain information relating to the production tax and the sharing between agencies of certain information relating to the production tax and to oil and gas or gas only leases; amending the State Personnel Act to place in the exempt service certain state oil and gas auditors and their immediate supervisors; establishing an oil and gas tax credit fund and authorizing payment from that fund; providing for retroactive application of certain statutory and regulatory provisions relating to the production tax on oil and gas and conservation surcharges on oil; making conforming amendments; and providing for an effective date." SB 2001 was HEARD & HELD in Committee for further consideration. SENATE BILL NO. 2001 "An Act relating to the production tax on oil and gas and to conservation surcharges on oil; relating to the issuance of advisory bulletins and the disclosure of certain information relating to the production tax and the sharing between agencies of certain information relating to the production tax and to oil and gas or gas only leases; amending the State Personnel Act to place in the exempt service certain state oil and gas auditors and their immediate supervisors; establishing an oil and gas tax credit fund and authorizing payment from that fund; providing for retroactive application of certain statutory and regulatory provisions relating to the production tax on oil and gas and conservation surcharges on oil; making conforming amendments; and providing for an effective date." 1:31:22 PM DUDLEY PLATT, CONSULTANT, DEPARTMENT OF REVENUE, informed the committee of his experience as a petroleum engineer and his current position as a consultant to Department of Revenue. He outlined his experience as a forecaster. 1:33:57 PM Mr. Platt gave a presentation titled, "North Slope Crude Oil & Natural Gas Liquids Production Forecast, Department of Revenue Fall 2007" [copy on file]. He explained to the committee the things that he does not forecast and provided a list. Resources not included in fall 2007 Forecast: · No undiscovered resources. · 100% Ugnu viscous oil (20 billion barrels) · 96% of West Sak viscous oil · 88% of Schrader viscous oil · Federal Outer Continental Shelf (Sivillug, Kuvlum, Sandpiper) · NPR-A (except known pools near Alpine) · Slope wide implementation of low salinity water flood Some addendums to the list include: Resources that have been discovered but due to the sensitivity of the information are not available for discussion. ƒSome forecasts (420 million barrels) from West Sak core area. ƒHe noted the importance of considering that he does not forecast any known discoveries in the Federal Outer Continental Shelf (OCS). The list includes those slated for non commercial. ƒHe does forecast some known pools near Alpine such as Spark, Rendezvous, and Moosestooth. He commented on the new technology barrels from low salinity water flood. He went on to say that currently there is a demonstration project at Endicott that could prove to be very viable. The new technology would allow for 20-30% recovery of oil remaining in fields. 1:36:21 PM Mr. Platt addressed page 3, Methodology: · Production forecast is a "bottoms up" approach · Forecast 3 types of production - Currently producing - Under development - Under evaluation · Combines the following: -Decline curve analysis -Engineering principles -Site inspections -Discussions with operators -Use of private & public information · Operators are given an informal opportunity to review and comment on forecast assumptions · Continually review forecast assumptions and update daily production volumes. Mr. Platt stated that each field behaves differently noting that each has different size, complexity and drive mechanisms. He underlined the importance of looking at each field every six months to really understand it. 1:37:10 PM He extrapolated definitions from the Department of Revenue Spring Forecast 2007. Currently producing: baseline production; and presumes a continued level of expenditures sufficient to promote safe, environmentally sound operations. He added that "currently producing" presumes continued injection of water and gas for pressure support. Under development: based on new projects either currently funded or awaiting project sanctioning in the very near future. (Read from Department of Revenue Spring 2007 Forecast page 35). He sited examples: development drilling, enhanced oil recovery, either operating or projected to be operating. The category also includes roughly 180 million more barrels attributed to injecting water into Prudhoe Bay gas cap. Under evaluation: includes technically viable projects currently in the "pencil sharpening" stage where engineering, cost, risk, and reward are all being actively evaluated. This includes certain enhanced oil recovery projects at certain satellite fields. Includes certain expanded heavy oil development at Trador and Westsak. He explained that these are the three types of production he forecasted. He pointed to page 4 of the handout illustrating the amount of production over ten years for each type. Mr. Platt explained that the curve upward on the chart in 2018 for "under evaluation" is the projected time for Point Thompson to come online. Co-Chair Stedman noted the legislature has struggled with Point Thompson for the past decade. He asked if the project just keeps getting pushed forward. 1:40:59 PM Mr. Platt responded by saying that Point Thomson is "very elusive". He pointed out that 2-3 years ago with negotiations on the gas pipeline, Point Thompson went from a gas cycling project to a project that would only be commercial under major gas sales. He explained that it is a very high pressure reservoir with significant costs associated with it. He explained that even if a gas contract was available immediately, it would still be nine years before production, hence the 10- year projection chart. He emphasized the magnitude of oil available and the amount of effort it would take to capture it. He explained that he uses the decline curve analysis approach using industry accepted software, augmented with basic engineering principles. He then inspects all the oil fields and has detailed discussions with the operators. In addition, he attends meeting on field development with oil companies. When the forecasting effort is completed, plant managers are given the opportunity to comment on the findings. 1:45:17 PM Mr. Platt continued with page 5, titled, Alaska North Slope: The chart denotes both the spring and fall projections expressing a steady decline in production, ultimately resulting in a negative 500,000 barrels per day. He suggested that 6 months from now the lines would likely change to express something different. He elaborated noting the discrepancies in the projections from 2008-2013. He explained that when there are mistakes or differences in the projections he attempts to reconcile the difference, or at least understand it. He reiterated the process in which he collects data. He identified 3 main reasons for the discrepancies in the forecast between the spring and fall forecasts: 1) Additional information was made available that suggested the timing of new developments had changed. 2) Planned maintenance: He noted that 2006 was identified as year of integrity management highlighted by the shutdown. The calendar year 2007 was the year of infrastructure renewal, life cycle and replacement costs. Mr. Platt maintained that even healthy, producible reservoirs can have many things that prevent it from performing to expectations of both the forecaster as well as the operator. He pointed out that the difference in the chart from page 5 and that of page 6 is the removal of the federal oil variable (NPR-A and Liberty). He maintained that without the federal oil variable the forecast is more accurate. The fact that the federal lands do not bring great return in terms of tax revenue and are difficult to produce, their significance is not as great in terms of forecasting production {for the sake of understanding return in revenue to the state}. 1:50:27 PM Co-Chair Stedman asserted that projections tend to be overly optimistic on production and pessimistic on price. He asked if the North Slope basin is in a time of its life cycle that is difficult to forecast. 1:51:20 PM In response, Mr. Platt suggested that the state is transitioning into a time of greater challenges in forecasting price, cost, and production. He observed that prior to the era (6 years ago) of infrastructure renewal and integrity management, he could forecast fairly accurately. He revealed that with the amount of uncertainty associated with the near term of continued reinvestment, not necessarily in barrels produced, but to repair facilities to maintain current production, forecasting becomes more difficult. 1:53:02 PM Co-Chair Stedman asked if he understood correctly that the reservoirs are capable of production at 700,000 barrels per day with proper reinvestment. Mr. Platt responded that everything at Prudhoe, Kuparik, and Alpine are producing. He clarified that the issue is not the ability to produce, but what may go wrong to slow it down. 1:54:30 PM Co-Chair Stedman offered that regardless of the incentive credits, producers have the ability to maintain production at 700,000 barrels per day versus what is reflected on the chart illustrating 600,000. Mr. Platt responded that the 600,000 reflects the amount produced without the inclusion of federal oil. He continued his presentation with page 8, Production Volume Forecast Reduced for the Next 8 Years · Additional volume Reductions from: -unplanned interruptions -planned infrastructure renewal · Slowed the pace of heavy oil · Delayed timing of new projects to reflect revised industry estimates 1:56:43 PM Mr. Platt explained what is meant by "slowed the pace". He stated that reports from the industry suggest that there are plenty of capital funds available but they are not necessarily put towards enhancement projects. He provided examples: Milne point is challenged because there is near term rate reduction. This information was accommodated in the projection. He noted Westsak has great opportunities, but recently suffered from some reservoir issues. He noted the technical issues impacting the pace of development are not the only concern. He further clarified by saying that a producer may want to proceed with a project, but they may not receive the support from co-owners. This is something happening at Westsak presently. How that is accommodated in the projections is he stretched out the development overtime and represents a delay of 10-15 thousand barrels of oil a day. 1:59:11 PM He also added that "delayed timing" of new projects as a variable to reflect new information regarding maintenance and integrity management. Senator Elton stated an assumption on planned infrastructure renewal. He asked if the increased estimation of planned infrastructure renewal projects are due to problems occurring from deferred maintenance. 2:00:26 PM Mr. Platt agreed with Senator Elton's assumption but added that any prudent operator would look at all infrastructures. The integrity management plan leads to an infrastructural renewal plan and the implementation of the plan will take years. Mr. Platt explained that his discussions with field managers revealed that in Prudhoe Bay alone there are 1,100 miles of pipeline and flow lines. At Milne Point over the next 3-5 years certain flow lines will need to be replaced at a regularly scheduled pace. This project will slow production, but ultimately extend the life of oil production. Senator Elton asked about delayed timing of new projects to reflect revised industry estimates. He emphasized the expectation in PPT deliberations was based on the premise that if a net tax was adopted the pace of investment would increase. He expressed confusion over the delayed timing of new projects. Mr. Platt distinguished between Senator Elton's concerns and what is meant by delayed timing of new projects. He pointed out that when companies assess future projects, there are a number steps in the process. Often one or two wells are drilled to determine what, how much, and under what circumstances production can occur. A producer's plans can be revised at any step in the process and potentially "delay timing" of the project. He emphasized the delay of a project does not mean abandonment of a project. He provided examples of new projects. {Liberty BP thought they would develop as a stand alone (more expensive) facility - one to two drills a year to determine the success rather than a rapid rise to a peak (delayed production). Further evaluation revealed there was surplus capacity at the Endicott facilities where extended reach drilling could capture that. He also delayed 6 months because due to BP submission to the Mineral Management service that stated the 6 month time period.}//////// 2:05:06 PM Currently there is drilling for heavy oil in Ugurik with a facility sharing agreement pending with Conoco Phillips. Initially, first oil was projected in the fourth quarter for 2007. When that did not happen, forecasts were adjusted. He supplied further examples of the difference between expectations and the actualization of the expectation. He could not comment on what type of behavior PPT might encourage or discourage. 2:08:10 PM Mr. Platt addressed page 8 of the handout and explained that he wanted to express some of what led to the judgments made in forecasting. The plot represents the fluctuations in production for 2005 and 2007, January 1 - November 6. He explained that a single dip in the chart represents maintenance. A double dip or dips close together represent an unanticipated event. The chart illustrates significant volatility in 2005. 2:09:30 PM Mr. Platt expressed the difficulties in making forecast projections by explaining Page 10, Volume Volatility. The chart denotes barrels per day produced from September 2006 - September 2007. The dips in the chart represent a TAPS shutdown in 2006 slow output due to tanker traffic delay of North Slope delivery in November 2006, and planned maintenance at Alpine, August 2007. 2:11:07 PM He addressed the final page: Changes from spring 2007 in bpd. One column represents barrels produced per (bpd) day on both state and federal lands; the other represents bpd for state lands only. The chart spans from Fiscal Year 2008 to Fiscal year 2015. He elaborated noting the decrease in production over the next 5 years and the shift to a production increase in 2014. In referencing FY 2008, he said it is quite possible the state would fare better than what is expressed in the chart. Senator Huggins addressed page 8 and said the assumptions for 2007 were not surprising. He asked Mr. Platt if he was surprised by what the chart illustrated. 2:13:30 PM Mr. Platt responded that he was surprised at the number of dips in the colder months, noting that generally companies perform maintenance projects in the warmer months. Senator Huggins asked if there were other elements, other than water, that are expected to come into play with regards to the extraction of heavy oil. Mr. Platt explained that old oil fields produce more water per unit of oil and they produce more gas. The facilities in Prudhoe Bay and Kaparak are maxed out on how much gas can be handled. These fields are also approaching the maximum of water they can handle. He explained that if companies don't expand their ability to handle these non-sellable items, the oil production will continue to go down. He asked for clarification from Senator Huggins on the question. 2:15:35 PM Senator Huggins asked if there were any other variables on the horizon that may impact heavy oil extraction and production. Mr. Platt elaborated on the issues of heavy oil. He noted that production costs are higher, but the value is lower due to the quality. He discussed the various technologies available for creating higher quality heavy oil. Senator Huggins asked Mr. Platt to discuss the possibility for gas off-take with regards to the possibilities of a gas pipeline. 2:17:04 PM Mr. Platt said in Prudhoe Bay there are approximately 25-40 trillion cubic feet (tcf) of gas; Point Thompson as has 4-8 trillion cubic feet of gas. The amount of gas in Point Thompson could provide 4.5 billion cubic feet (bcf) a day for approximately six years without having to tap Prudhoe Bay. He pondered the choices of investment in reinjection, or producing fuel from Point Thompson to send to Prudhoe Bay for operations. He noted gas reserves in NPR-A, the trillion feet of cubic gas in the vicinity of Alpine. He also informed the committee that Kuparuk will need to start buying gas just to run operations. Senator Thomas said he understood the term "low salinity water flood" and asked for the source of the low salinity water. 2:19:11 PM Mr. Platt understood that British Petroleum (BP) is trucking fresh water to Endicott Island. This is a demonstration project and is following successful laboratory test. He said that it is possible that companies will be able to build desalinator plants. 2:20:27 PM Senator Thomas referenced the chart illustrating Alaska North Slope oil production, page 6. He asked if the dip in 2017 represents a particular event. Mr. Platt said it represented Point Thompson and its associated satellite. Senator Thomas reference page 8 and asked Mr. Platt to explain "slowed development" and "delayed development". 2:21:20 PM Mr. Platt named two areas he used when considering the production forecast: Schrader Bluff at Milne point and Westak. He noted the first area has funds budgeted for integrity management, not production. The challenge at Westsak is the extraction of heavy oil. This requires not only funds, but a willingness by the company to pursue the project. Senator Thomas referenced the volatility chart on page 9 of the handout. He asked Mr. Platt how he determines what is factored into the chart. 2:22:47 PM Mr. Platt provided some perspective. When production was at 1 million barrels per day, 5 events per winter season was the norm for factoring. He explained that at 750,000 barrels per day there is generally less incident, hence a lesser number of incidents factored in. He further explained that in order to track accuracy, he reviews the previous 3 years. If an influential factor was not foreseen and there is a relatively constant trend, the forecast is adjusted accordingly. He noted that in years past he felt his forecast were proactive where more recently the forecast has been more reactive due to a number of changing variables, specifically the maintenance and integrity management. 2:24:16 PM Co-Chair Hoffman questioned how much the price of oil, tax structure and particular incentives factor into the production forecast equation. Mr. Platt responded that his forecast is based on technically recoverable barrels, compared to what is reported by the industry as recoverable. The variables in the equation are as follows: new information from economic research section of DOR including price, feeder pipeline tariff, and TAPPS tariff. From these a model is built on indicative economics: Forecasts from DOR, plus information from Cambridge energy of operating costs. For the fields that have a negative economic life, a 4% gross minimum is applied. 2:25:54 PM Co-Chair Hoffman asked, what is used to determine barrels per year increase, when establishing assumptions. 2:26:35 PM Mr. Platt answered that the total amount of recoverable reserves has either stayed the same or increased every year for 10 years. He underlined that he can not estimate the level of investment. He maintained that if a company knows they can get 13.8 billion barrels out of Prudhoe Bay they will do whatever it takes to get the barrels out of the ground. Co-Chair Stedman asked if the model could track the impact of PPT credits and incentives. 2:27:30 PM Mr. Platt offered that initial funds go towards, infrastructural renewal in order to maintain base production. There is significant incremental production only after the companies have a comfort level that they can produce what they have projected. He reminded the committee that there are some new projects and provided examples. 2:28:27 PM Mr. Platt said he would like to see Westsak develop 4 or 5 more drill sites. The companies consider the flow station integrity first. He purported that companies are spending now to ensure there is not another major incident that impedes production. Senator Elton asserted that throughout the tax debate he had never heard that net profit tax, with credits, was intended for infrastructure renewal. He further underlined that the net profits tax and credits are needed for companies to invest in new production. The message gleaned from the chart is that the state should not count on new production but on infrastructure renewal. He emphasized that the message is a significant shift from what had been discussed. Mr. Platt acknowledged the challenge. He noted that companies would feel more comfortable producing if the equipment could sustain it. He reiterated that there currently are new projects underway and provided examples. 2:31:14 PM Senator Elton asked if Mr. Platt's assumptions are correct, why credits are given to companies that could have spent less on integrity management if it weren't a matter of deferred maintenance. 2:32:35 PM Mr. Platt elaborated that every year for the past 5 years there has been more production made in heavy oil which can be quantified. He acknowledged the pace is slower than originally assumed, but there is more heavy oil produced. He emphasized the point that new projects are still relying on old equipment to be commercial. He underlined that even though there is oil available to produce; facilities have to be in a condition to make the project viable. Co-Chair Stedman asked Mr. Platt how many barrels per day would be produced for rest of FY 2008. 2:34:12 PM Mr. Platt said his projection is 732,000 bpd. AT EASE: 2:34:55 PM RECONVENE: 2:47:17 PM 2:48:50 PM JON IVERSON, DIRECTOR, DIVISION OF TAX, DEPARTMENT OF REVENUE, provided an overview of tax credits available under PPT and how they are affected under ACES. He reiterated the PPT Tax calculation presented by Steve Porter, Legislative Consultant, Legislative Budget and Audit Committee, Legislative Affairs Agency handout: Gross value minus transportation costs; allowable deductions, lease expenditures are subtracted from the gross value to reach the production tax value. That, in turn, is multiplied by the rate of 25 percent under ACES (PPT the rate is 22.5 percent). From that point the credits are subtracted out. There are three main statutory sections that address credits: qualified capital expenditure credit (QCE) in section AS 43.55.023, nontransferable credits, AS 43.55.024, exploration incentive credits, AS 43.55.025, (in effect prior to the enactment of PPT). 2:51:12 PM The qualified capital expenditure credits in AS 43.55.023, Section (a) are 20 percent of qualified capital expenditures. He explained these are expenditures that have not been used for credits under other sections. 2:51:57 PM In AS 43.55.023 (b) are the loss carry-forward (or net operating loss credits). These are based on prior years' lease expenditures; 20 percent of the amount of adjusted lease expenditures. These are expenditures that are not deductable for the previous calendar year because the tax would have been less than zero. To the extent the taxpayer has remaining credits they can take 20 percent and convert into a loss carry- forward to be used against subsequent year's tax liability. 2:53:10 PM Both types of credits are transferable through credit certificates that are issued by DOR. Under current rules the department must grant or deny the application no later than 60 days after the following: March 31 of the year following the year the expense was incurred, the date the statement was filed, or the date the application was received by the department. The CS SB2001(JUD) would change 60 to 120 days, allowing additional time to exam the credit applications. Mr. Iverson continued to explain AS 43.55.023 (e) sets forth the authority for an owner of a transferable credit to apply the credit against their tax liability. Once a transferable credit is issued by the department, it could be resold and, in certain circumstances could be refunded under PPT. He said there have been questions put forth regarding the marketing of the credits. In answer to that he explained that the department does not receive information on every credit transferred. The terms are confidential between the buyer and the seller, and the department is not privy to that information. He said based on information that is available, the credits are worth between 90 and 100 percent of market value. 2:55:17 PM Senator Elton asked why someone would buy a credit at 100 percent. Mr. Iverson was uncertain and said there must be some other reason than market value. He added that with transaction costs, it would not make sense to purchase a credit at 100 percent. Senator Olson asked if a net operating loss converted to a credit, could be sold. Mr. Iverson said yes and elaborated. Once a net operating loss credit is received it can be converted into a transferable credit certificate that can then be sold. 2:56:28 PM Mr. Iverson continued with an explanation of AS 43.55.023(f). This section addresses refunds of credits for small producers. A small producer is considered a company producing less than, or equal to, 50,000 barrels per day. The refund is limited to the amount spent on capital investments or on bids for state oil and gas leases within 24 months after applying for transferable credit certificate. Criteria for the refunds are as follows: Applicants must not have unpaid delinquent production taxes. There is a limit of 25 million per calendar year. The amount in total available for refund is subject to legislative appropriation. Issuance of transferable credits does not limit the ability to audit. In current law AS 43.55.023(i) establishes the Transitional Investment Expenditure (TIE) credits. These are not transferable and can only used once (cannot be claimed under any other section as a credit). TIE credits are available for 20% of qualifying investments (qualified capital expenditures) that are made during the 5 years prior to the effective date of PPT, April 1, 2006. A credit is limited to 1/10 of producer's new investment for each year after. 2:59:13 PM Co-Chair Stedman asked if Mr. Iverson could comment on what the expectations were for the application of TIE credits. Mr. Iverson deferred to Cheryl Niehnuis. CHERYL NIEHNUIS, PETROLEUM ECONOMIST, TAX DIVISION, DEPARTMENT OF REVENUE, testified that the expectations were approximately $5 billion dollars over the 5-year period. Under the TIE credits $6.2 billion was applied for under TIE credits, a difference of $1.2 billion. Co-Chair Stedman asked about the projections being not 20 percent off but 100 percent off. 3:01:26 PM Ms Niehnuis explained the capital expenditures were assumed to be $1 billion a year when in fact they were $2 billion per year, increasing the amount of applicable expenditures. Co-Chair Stedman asked if the department recommended removal of the TIE credits. 3:02:01 PM Mr. Iverson said the department was in support of removing the TIE credit. Mr. Iverson moved on to the AS 43.55.024 credits. Of the two credits the first is an annual $6 million credit to producers operating in areas other than North Slope or Cook Inlet. The credit expires 2016 or the ninth calendar year post first commercial production. The second credit is for small producers who have an average daily production less than, or equal, to 50,000 barrels a day. This is a $12 million credit annually and is phased out when a producer reaches 100,000 bpd. The credits are nontransferable and do not carry-forward. 3:03:30 PM He added that the credits are Pre-PPT and transferable, though there is no provision for them to be refunded in PPT. The criteria for the credits are either a 20 percent credit or 40 percent credit depending on activity. The credits are targeted toward exploration activities. He provided examples: 20 percent allowable credit for a well drilled not less than 3 miles away from a currently existing well, another 20 percent credit would be for 25 miles away or more from the boundary of the unit. If it meets both criteria then the result is a 40 percent credit. To the extent a seismic shoot is made outside production or exploration unit boundary, the cost for the shoot are also available for a 40% credit. He explained there are significant information requirements in AS 43.55.025. There have been some suggested revisions from the department based on the need for DNR to obtain more information. 3:05:18 PM Mr. Iverson addressed the changes proposed in the ACES bill. First the loss carry-forward credits are set in PPT legislation at 20 percent; SB2001 recommended that the percentage change to match the base tax rate was 25 percent. This provided the opportunity for companies unable to apply a deduction (lease expenditures) in the year incurred at the rate that is the tax rate. If companies are not able to do that then they are disadvantaged by having a lower credit rate in the subsequent year for expenditures they would otherwise be able to apply. This allows for the same benefits in subsequent years for new entrants who have no tax liability in the previous year. 3:06:51 PM Co-Chair Stedman asked how net operating losses are dealt with. 3:07:06 PM Mr. Iverson said there is no estimate of net operating loss carry-forward. Ms. Niehnuis said there are forecasts, not estimates. What is available is information on the true up return, which is actual data from calendar year 2006. Mr. Iverson said the amount is approximately $26 million. He clarified that this is for the actual 9 months ending 12/31/06, subject to PPT. Co-Chair Stedman asked for more information. Ms. Niehnuis informed Senator Stedman that there are estimates available by field, not by company. There are estimates in the model the expectation of loss carry forward credits as well as other credits. 3:08:50 PM Mr. Iverson wanted to point out that net operating loss carry forward of $26 million is not as significant an amount as the regular capital expenditure credits at $250 million. Mr. Iverson summarized that an important change in SB 2001 is the change of the loss carry-forward rate equal to the tax rate. An additional change is that tax-exempt entities can not obtain transferable credits certificates under either the capital expenditure section or the exploration incentive credit section. He did point out that if an entity is tax exempt by statute and then qualifies, an exploration, production, or development entity could apply for transferable or refundable credits. 3:10:27 PM. Mr. Iverson reiterated that the department proposed the elimination of transitional investment tax credits as it was felt that the producers are being rewarded for past expenditures. Mr. Iverson outlined another important piece; linking issuance of the credit with filing of annual statements, enabling the department to get the needed information. An additional provision that has been an issue is the spread of credits over 2 years. He explained that a credit can be use 50 percent each year. Noting there had been debate on the provision, he explained both sides. The positive side is a "revenue smoothing effect". Typically credits are not allowed to be used in their entirety in a single year internationally. The difficulty with the provision is the reduction in the net present value of the credit due to it being extended out another year. Co-Chair Hoffman asked what the monetary difference is between and annual filing, versus what is currently in statute. Mr. Iverson clarified question a question regarding the calculation of progressivity on monthly versus an annual basis. Cheryl Niehnuis said based on historical information the amount is a minimum of $18 million depending on prices and other variables. Co-Chair Hoffman asked what the reason was for an annual tax basis. Mr. Iverson said the primary reason was simplification but also the smoothing out of price fluctuations. 3:14:01 PM Co-Chair Hoffman asked if progressivity increased to .4 as is suggested in SB 2001(RES), would the $18 million double. Mr. Iverson said that Senator Hoffman's observation was accurate in terms of noting an increase. Co-Chair Stedman recalled discussions from a previous meeting debating a monthly versus annual filing. The intention behind the monthly filings was to capture the revenue when there were spikes in price. Co-Chair Stedman commented on the timing of capital credit. He noted there has been some interest for establishing a zero credit in the first year, then 50/50 over the next two years. The purpose is to stabilize the state's forecasting ability. He acknowledged that there is an added cost with the 50/50, than 100% up front. He requested an estimate of an opportunity lost vs. the gain in the budgeting process if the credits were known ahead of time. He wanted to know the impact to the treasury, recognizing the difference between a calendar year and a fiscal year. 3:16:21 PM Mr. Iverson offered to provide further information regarding Senator Stedman's comments. Senator Stedman recognized that there was a time-value impact on the credit. He thought the 20 percent credit was substantial. Mr. Iverson related that SB 2001 also proposed clean up provisions regarding Cook Inlet. Regulations were put into place that weren't expressly set forth in statute, inserting lease expenditures and credits in Cook Inlet and interfacing with the Cook Inlet ceiling. He further noted AS 43.55.028, which establishes a fund mechanism to facilitate the credit refunds. Currently, the legislature appropriates funds for credits and the department then requests supplemental funds to handle the difference. The proposed fund is within the treasury and would be funded with a percentage of production tax revenue. The percentage would be between 15-20 percent depending on the price of oil on the West Coast. The department would use the fund to pay the credits. 3:19:10 PM Senator Elton asked who would manage the fund. Mr. Iverson said the fund would be managed by the treasury and receipts would stay in the fund to be used in subsequent years to pay other credits. Co-Chair Stedman asked for an explanation of seismic exploration incentive credits. Mr. Iverson deferred to the Department of Natural Resources and explained that DNR was instrumental in creating language on the exploration incentive credit program under the SB 80. 3:20:43 PM KEVIN GIBSON, PETROLEUM INVESTMENT MANAGER, ACTING DEPUTY DIRECTOR, DIVISION OF OIL & GAS, DEPARTMENT OF NATURAL RESOURCES, said he was available to answer questions. Co-Chair Stedman asked if he could explain the exploration incentive credits and their purpose. Mr. Gibson said exploration incentive credits predate PPT to encourage exploration. The credits are a substantial 20-40 percent. The seismic data information submitted is critical to understanding geotechnical information, which determines prospectivity of various state and federal lands. It is also valuable to the state, who as a working interest owner, secures the ability to access information and make it public after confidentiality expires. This provides value in terms of the state's long-term exploration goals and hinges on the ability to encourage new explorers to come in. He explained that as basins mature and larger players pull out, smaller companies can come in and have access to that information, which can defray costs. 3:24:31 PM Senator Thomas asked for the maximum credit amount that could be received by a taxpayer. Mr. Iverson said it is too early to tell as plans are made in advance and PPT has not been in effect for long. Exploration incentive credits, from inception to date, have been approximately $250 million in qualified expenditures; $23-25 million of that in seismic. To date there has been approximately $53 million in credits issued for wells. He concluded that over time there had been some substantial activity under the exploration incentive credit program. He added that the department has heard from companies that the credits are very valuable due to the net present value impact. He clarified that the CSSB 2001(RES) version allows companies that have investment costs, but no production, to have a two-year window to apply for
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