SENATE FINANCE COMMITTEE February 17, 2010 1:32 p.m. 1:32:F20 PM CALL TO ORDER Co-Chair Stedman called the Senate Finance Committee meeting to order at 1:32 p.m. MEMBERS PRESENT Senator Lyman Hoffman, Co-Chair Senator Bert Stedman, Co-Chair Senator Charlie Huggins, Vice-Chair Senator Johnny Ellis Senator Dennis Egan Senator Donny Olson Senator Joe Thomas MEMBERS ABSENT None ALSO PRESENT Cherie Nienhuis, Petroleum Economist, Department of Revenue; Marsha Davis, Deputy Commissioner, Department of Revenue. SUMMARY Oil and Gas Overviews: PRODUCTION TAX LEASE EXPENDITURE REGULATIONS OPERATING and CAPITAL EXPENDITURES ^OPERATING AND CAPITAL EXPENDITURES 1:33:25 PM CHERIE NIENHUIS, PETROLEUM ECONOMIST, DEPARTMENT OF REVENUE, informed the committee that she would present an update of operating and capital lease expenditures based on information acquired since the state changed its tax system to a net profit system. She explained that some of the information presented was acquired either through the former profits tax called the Petroleum Profits Tax (PPT) or through the Alaska Clear and Equitable Share (ACES) tax, which has been in place since the PPT. Ms. Nienhuis provided a PowerPoint presentation, "Operating and Capital Lease Expenditures, Senate Finance Committee, February 17, 2010" (copy on file), and outlined the agenda: · Lease Expenditure Sources · Total North Slope Lease Expenditures · Standard Deduction Provision · $0.30/barrel Capital Expenditure Exemption · Trends in North Slope Spending Ms. Nienhuis turned to slide 3, "Lease Expenditure Information Sources," and delineated the sources available to the department: · Capital expenditure information · Monthly expenditure estimates · Annual expenditure information, 2006 - 2009 · Future expenditure projections from North Slope operators · Manual processing of all expenditure information Ms. Nienhuis detailed that the capital expenditure information was historical, current, and projected. The Department of Revenue (DOR) receives monthly expenditure estimates from companies spending money in the state's oil and gas operations. The state has also received annual expenditure information from tax returns for calendar years 2006 through 2008; 2009 returns will be received March 31, 2010. Ms. Nienhuis explained that all the information regarding lease expenditures is received in various manual forms, including Excel sheets, PDFs, and sometimes hard copies. 1:37:02 PM Ms. Nienhuis provided more information related to capital expenditure information. She reported that during the PPT discussion, there was reference to transition investment expenditure credits (TIE); TIE credits still exist but have changed since the inception of ACES. The TIE credit set up a system whereby companies could receive credit for expenditures between the years of 2001 and 2006; the department received information regarding estimated capital expenditures during that time period. Ms. Nienhuis noted that the department began getting monthly expenditure estimates in May 2008. The ACES tax system set up a structure requiring companies that were spending money in oil and gas operations to submit monthly estimated expenditures and tax payments. She underlined that the monthly expenditures are only estimates, not audited documents. The numbers are used by the economic research group to forecast tax revenues for the state. Ms. Nienhuis listed details regarding annual expenditure information: · Auditable production tax returns, due March 31 of each year · First filing March 31, 2007 (first under PPT) · Second filing March 31, 2008 (first under ACES) · Third filing March 31, 2009 (second under ACES) Ms. Nienhuis emphasized that DOR had tax returns without some of the calculation information that would ordinarily be on a standardized return because during the whole period of time the department was working on regulations and defining such items as lease expenditures. Returns were submitted manually. The department hopes to have a standardized form developed within a year. Ms. Nienhuis reported that the department receives expenditures based on projections. Two forecasts are done each year, one in the fall and one in the spring. Prior to the forecast, operators are asked to submit their best projections for capital and operating expenditures, by unit, for up to five years. Statute limits the communications to what the operators share with working interest owners; a special projection is not prepared for DOR. As a result, projections vary by operator and by property. Some projections categorize costs and others do not. 1:40:37 PM MARSHA DAVIS, DEPUTY COMMISSIONER, DEPARTMENT OF REVENUE, added that the form for the annual return has been completed and issued, and will be required for March of 2011. The department will not require that the standardized form be used for March of 2010 because companies will need time to merge their software into an Excel format. Co-Chair Stedman requested more detail regarding transition credits. Ms. Davis replied that an individual breakdown of credits would be provided in the credit section of a future hearing. Ms. Nienhuis directed attention to a graph on slide 6, "North Slope Operating and Capital Expenditures, Reported and Projected." She noted that the numbers were not audited but totals received by looking at annual tax returns, and that the numbers shown for 2010 and 2011 are projections. Operating expenditures are shown in blue and capital expenditures in orange. She pointed out that capital expenditures have grown each year since the inception of the net profits tax and that operating expenditures are expected to decrease in the future. In general, there are overall increased expenditures for the North Slope. Co-Chair Stedman asked whether a future hearing would cover the sources of capital expenditures. Ms. Davis replied that detail regarding capital and operating expenditures would be covered at the present meeting and that the next day's hearing would cover how credits were applied for. Co-Chair Hoffman pointed out that the projected capital and operating expenditures for 2011 are the highest of the past five years. Ms. Nienhuis agreed that the projections were higher than any previous year. 1:44:01 PM Ms. Nienhuis turned to a graph on slide 7, "Capital Expenditures per Barrel, Total North Slope." She emphasized that capital expenditures, unlike operating expenditures, do not always coincide with active production. Capital expenditures normally precede production; the increase of capital expenditures per barrel depicted on the graph reflects spending and a steady or slightly declining production base. The fact that capital expenditures per barrel are on the rise says more about future production than about current production. Co-Chair Stedman asked whether the barrels were net or gross. Ms. Nienhuis replied that they were taxable barrels. Ms. Nienhuis noted that the graph on slide 8, "Operating Expenditures per Barrel, Total North Slope" shows total reported operating expenditures; the standard deduction provision is not included. The numbers reflect what was reported to the department through annual returns in some cases and through monthly returns in others. She highlighted a decrease starting in FY 10, and explained that operating expenditures are more or less costs to do day-to-day business on the North Slope; expenditures coming down could point to efficiencies or to services costing less. Senator Egan asked where maintenance costs fell. Ms. Nienhuis replied that maintenance generally falls into the operating expense category. Ms. Davis clarified that they would be talking later about the standard deduction, but she wanted to clarify related to the slide that shows the real, actual operating expenses. She noted that under the tax provision there was a temporary cap on the operating expense deduction at Prudhoe and Kuparuk; the capping is not reflected in the graph. Ms. Nienhuis added that the figures are unaudited, company- reported figures; they could change with an audit. 1:47:25 PM Ms. Nienhuis moved to slide 9, "Prudhoe Bay Operating Expenditures per Barrel, as Reported and Forecast," a graph covering 2003 to 2010. She commented that the chart is included in the department's ACES review. She highlighted the significant rise in operating expenditures in 2006 and 2007, numbers consistent with published documentation by Cambridge Energy Research Associates regarding similar trends worldwide. Costs are shown coming down in 2009 and 2010, reflecting operating expenditure trends everywhere. Co-Chair Stedman detailed for the public what the dollars- per-barrel figures on the graph represented. He pointed out that each 2010 penny translates to about $2.4 million; producing 240 million barrels per year has huge impact. Ms. Nienhuis observed that the price of oil needed to be considered when discussing operating expenses. She elaborated that there was an increase in the price of oil along with the increase in operating costs per barrel. The department believes that the price of oil and the price of doing business in oil and gas operations are directly correlated, although possibly lagged; increases in the price of services, lease expenditures, and various items are related to increases in the price of commodities, including oil. She hoped the price decline seen in 2008 and 2009 would help drive operating costs down. Ms. Davis elaborated that as the price of oil goes up, it becomes much more lucrative to be in the oil and gas business, and that the resulting pressure to move quickly is more costly. An intense amount of demand can be placed on services and equipment; a higher demand on the commodity can translate to increased prices. Conversely, when oil prices drop, demand goes down, commodities lag, and prices of services have to go down. 1:51:14 PM Co-Chair Stedman pointed out that the 2010 operating projection was roughly $2 billion. Ms. Davis added that the $2 billion was the total for the North Slope. Senator Thomas asked whether the significant increase in operating expenses was related to maintenance difficulties in Prudhoe Bay in 2006. Ms. Davis replied that in absolute dollars there is an increase in operating expenses associated with repair work. She added that the actual costs associated with the spill and corrosion event are not allowed to be deducted as lease expenditures and would not show up on returns. However, after a spill a company would proactively replace other lines. She cautioned that that alone would not explain the increase in operating expense on a per barrel basis. Co-Chair Stedman requested dollar per barrel information related to Prudhoe Bay as well as other expenditures outside of Prudhoe Bay. He wanted information separately for Prudhoe Bay and Kuparuk. Ms. Davis explained that there was data for Prudhoe Bay operating expenses and not for Kuparuk. Co-Chair Stedman suggested dividing the data up between Prudhoe Bay and all other units. Ms. Davis did not know if there was a total North Slope operating expense figure for 2003, 2004, or 2005. 1:54:45 PM Ms. Nienhuis observed that the department publishes material on a much higher scale in the Revenue Sources Book, including total North Slope expenditures. She believed the most recent projection split capital and operating expenses at about $9 per barrel. She offered to verify and get more information. Ms. Nienhuis directed attention to slide 10, "Standard Deduction Provision at AS 43.55.165(j)." She explained that the standard deduction provision refers to a limitation placed on lease expenditures in Prudhoe Bay and Kuparuk units. The amount was limited to the lease expenditures that were set in calendar year (CY) 2006, the first year of the net profits tax, and adjusted so that it could be inflated by 3 percent each year. The standard deduction was in place for CY 2007, CY 2008, and CY 2009; the provision sunset at the end of CY 2009. She reported that the department had not yet received its first monthly report without the standard provision; the first was due at the end of February. Ms. Nienhuis turned to slide 11, "Prudhoe Bay Opex per Barrel, as Reported and with Standard Deduction." The blue bars in the graph depict the same figures as the blue bars on slide 9, with the operating expenses (opex) per barrel allowed under the standard deduction shown in the orange bars from 2007 to 2009. She noted the clearly widening differences for those three years. The 2010 projection shows the gap narrowing, which she believed was related to operating expenses coming down in general on the North Slope and in Prudhoe Bay in particular. 1:57:34 PM Ms. Nienhuis considered the "Impact of Standard Deduction" (slide 12): · Held operating expenditures fairly level for 3 years · Expenditures more predictable for forecasting · Difference between standard deduction and total reported costs greater at Prudhoe Bay unit than Kuparuk unit · Impact on state revenues more significant as oil prices increase Ms. Nienhuis detailed that the monthly forms asked how much was deducted under the standard deduction and how much was actually spent in the unit. Ms. Davis added that one speculation about the difference in cost between the two units was that since Prudhoe Bay is in an active mode of repair and addressing corrosion issues, there was less discretion regarding what they would and would not spend relative to operating expenses, whereas the Kuparuk unit, which is not in a crisis, could shift expenditures elsewhere and had more ability to stay closer to the cap limit. Ms. Nienhuis moved to slide 13, "Increase to State Revenue from Standard Deduction Provision." The blue portions of the bar graph show the amount of North Slope production tax paid in FY 07, FY 08, and FY 09, and the impact of the standard deduction is shown in gold. She noted that the impact in FY 07 was fairly slight as the standard deduction was only in place for half of the year. In addition, oil prices were not as high as they were in subsequent years. In FY 08, there were high oil prices, which increased the tax rate and therefore the impact to the state of the standard deduction provision. In FY 09, the impact went down again, reflecting lower oil prices. Co-Chair Stedman queried the total for the standard deduction. Ms. Nienhuis answered [$611 million]. Co-Chair Stedman wanted to consider credits created in Prudhoe Bay and Kuparuk, and how various factors acted as stimulants and suppressants. He stated that one of the questions was the effect of the 20 percent credit in Prudhoe and Kuparuk, and how much the credit was offset by the standard deduction, if at all. Ms. Nienhuis replied that analysis has shown an operating expense component to capital expenditure. Ms. Davis added that a standard deduction only operated relative to the operating expenses, not the capital expenses, so it would not have had an impact on the value of capital investment in the 20 percent tax credit; it would have impacted the overall base tax rate of the 25 percent in the progressivity rate. Co-Chair Stedman asked how much the standard deduction diluted the credit stimulation. He thought that the purpose of the credit was to stimulate in-field drilling and to access heavy oil. Ms. Davis agreed. Co-Chair Stedman pointed out that $611 million was a lot of money. He understood that the standard deduction did not apply to the capital expenditure side, but may possibly have inhibited capital decisions to go forward and try to extract more oil at Prudhoe and Kuparuk. 2:03:32 PM Ms. Nienhuis directed attention to slide 14, "Capital Exemption of $0.30 per barrel at AS 43.55.165(e)(18)." · AS 43.55.165(e)(18) exempts $0.30 per barrel o Initially intended to address costs of maintaining and upgrading pipelines and facilities o Applies to all barrels produced, regardless of property · Impact of Capital Exemption o Reduced reported capital expenditures by close to $70 million per year o Expenditure forecasts indicate maintenance and upgrade of several hundred million o Maintenance and upgrade expenditures could be amortized over 10 to 20 years · AS 43.55.165(e)(19) addresses unplanned maintenance; Some reporting of unplanned maintenance expenditures by companies Ms. Nienhuis explained that the capital exemption was a provision retained in ACES from PPT that exempts $0.30 per barrel of capital deductions from the ACES tax calculation. The provision was added relatively late in the deliberations on the tax and was initially intended to address costs of maintaining and upgrading pipeline and facilities. Co-Chair Stedman asked for more information. Ms. Nienhuis believed the $0.30 per barrel exemption was a break for the state as the state would not have to pay to upgrade aged infrastructure and facilities on the North Slope concerning capital credits. Ms. Nienhuis noted that the exemption applies to all barrels produced, regardless of where the oil comes from. The impact to the capital exemption was that the state had reduced capital deductions by close to $70 million per year (the exemption is per barrel, so would go down as production decreases). The department was asked to evaluate whether the [exemption] was sufficient to cover the maintenance and upgrade of facilities on the North Slope. She reported that there has been some infrastructure renewal, which can cost from tens of millions to hundreds of millions of dollars. She observed that it was not clear whether the improvements were because of the aging infrastructure or were part of the project plan. The department calculates that a several hundred million dollar improvement would last 10 to 20 years, which could add up to enough to cover the maintenance and upgrade. Ms. Nienhuis pointed out that a provision added through ACES (AS 43.55.165(e)(19) addresses unplanned maintenance. The provision is an exemption; companies are not allowed to deduct capital or operating expenditures incurred because of an unplanned event such as an unforeseen equipment breakdown or malfunction. She noted that since ACES, some companies have self-reported unplanned events that they are not deducting. Ms. Nienhuis briefly reviewed slide 15, showing the per barrel decline in capital expense exemption, reflecting oil production decline. 2:07:32 PM Co-Chair Stedman noted for the public that a future meeting focusing on the credit will show how much of the credit is applicable to exploration development and how much for general maintenance; $0.30 per barrel was put in to help protect the state from the 20 percent capital credit that went to normal maintenance on an older field rather than going to getting more oil out of the ground. Ms. Nienhuis continued with slides 16-17, "Lease Expenditure Information Mixed Bag": · Is lease expenditure categorization required? o Monthly information forms NOT REQUIRED o Annual production tax returns - NOT REQUIRED o Future expenditure projection form North Slope operators - NOT REQUIRED; However… · SOME operators provide categorization in very broad categories on SOME properties Ms. Nienhuis explained that information is received about lease expenditures through hard copy, Excel, and other forms. The "mixed bag" refers not only to the different forms the information is received in, but the types of reporting. She pointed out that there have been questions regarding whether the lease expenditures are going towards maintenance, rate-adding, or other programs. She added that the reason there is inconsistency in the information received is that companies have not been required to report how they spend the money. The monthly information forms, the annual production tax returns, and the future expenditure projections do not include a break-out of expenditure types other than capital and operating. Ms. Nienhuis reported that some operators provide the information in the form of future expenditure projection; however the information is provided on some units, not all. She explained that the department does its best to sift through and classify the information, and she provided examples of categories: · Expense Workovers · Major Repairs · Seismic Acquisition and Testing · Major Accident Review · Facility Integrity · Wellwork Ms. Nienhuis added that the process of sorting the information is further complicated by the fact that different companies can give different labels to the same thing. Co-Chair Stedman sympathized. 2:11:56 PM Ms. Nienhuis turned to slide 18, "Composition of North Slope Capital Expenditures" and discussed the process of classifying information received from companies: · Based on review of company confidential cost information, capital expenditures are placed into two categories: · "Resource or Development-related" o Drilling & Wellwork o Enhanced Oil Recovery Projects o Seismic o Facilities at New Fields (e.g. PT Thomson, WRD at PBU) · Other Capital Expenditures o Major Repairs and Work on Existing Facilities o Corrosion-Related Expenditures o Safety Upgrades Ms. Davis interjected that one of the challenges in splitting the costs into categories was the question of the relevance of any given activity. She referred to requests from legislators regarding the cost of maintenance versus the cost of production. She urged people not to lose sight of the production impact of maintenance activities that upgrade existing infrastructure. She stressed that lengthening the life of existing fields flattens out the decline curve of a field. Co-Chair Stedman stated that he wanted to get a feel for the workability of the 20 percent credit and to discern what creates the capital credit and whether it enhances oil recovery or is used for maintenance. He understood that the operating and capital expenses were distinct. 2:15:57 PM Ms. Nienhuis agreed and noted that there is usually an operating component that compliments the capital; drilling and wellwork, for example, incur expenses on both the capital and operating sides. Ms. Nienhuis directed attention to slide 19, "Share of Planned North Slope capital Expenditures for 'Resource and Development' Related Costs." The graph, put together from the information received and categorized, shows projected expenditures reaching a peak of nearly 75 percent in 2010 and then tapering off. She warned that the numbers were based on projections that changed every six months. Co-Chair Stedman referred to slides 7 and 8, regarding total North Slope capital and operating expenditures per barrel, which show increases in FY 11, and asked how that relates to the decrease shown in slide (19). Ms. Nienhuis commented that the department is seeing increasing expenditures on the North Slope in general; from the received projections, some of the costs are declining percentage-wise, but only from 73 percent to 71 percent. The portion of expenditures going to non-resource development is still not significant. 2:19:06 PM Co-Chair Stedman asked for dollar amount comparisons in order to better understand the different slides, as two use dollar amounts, while slide 19 uses percentages. He suggested using gross dollars to avoid using the barrel conversion. Ms. Davis explained that the earlier slides depict the entirety of all lease expenditures, both operating and capital; the columns stand for the totality. Slide 19 shows the percentage, and says that of the totality, 74 percent of the column is associated with production-related costs, meaning the other 27 or so percent represents the maintenance or non-production activity. The slight dip in 2010 represents the total operating and capital expenditures; of the slightly reduced total, there is a tiny increase over the prior year associated with production-related expenditures. The 2011 projection of a record-high $5 billion includes 72 percent related to production-related expenditures. Co-Chair Stedman pointed to the 2012 bar showing about 68 percent. Ms. Davis explained that the percentage coming down means the relative mix between production-related and non-production-related expenditures is coming into better balance and is not as production driven. Co-Chair Hoffman noted an earlier statement that lower operating expenditures are good and higher capital expenditures are also good, but combining the two gets confusing. Ms. Davis agreed and offered to split operating and capital expenditures within the production and non- production elements. Co-Chair Hoffman pointed out the difficulty of telling when operating costs go down when they are combined with the capital expenditures. He suggested concentrating on the fact that even though every year the operating costs go down, they should be kept separate from the capital expenses. He emphasized that every year since 2008 there has been an increase in capital expenditures. Ms. Davis agreed. 2:24:03 PM Ms. Nienhuis agreed to come back with dollar amounts to provide clarity. Ms. Nienhuis directed attention to slide 24, "Recent Trends in North Slope Costs": · DOR has limited data to work with in analyzing historic cost trends. · Limited comparison of expenditures for three years before and after PPT. · Capital Expenditures at Prudhoe Bay o Maintenance and corrosion repair expenses are not the key driver behind the growth in capital expenditures. o Majority of the increase in capital expenditures is due to drilling, seismic and projects (such as development of the Western Region of Prudhoe Bay). · Operating Expenditures at Prudhoe Bay o Major Repairs were a small part of total operating expenditures pre-PPT&ACES and is still a relatively small part of total lifting costs. o Wellwork expenditures are the primary driver behind the rise in Operating Expenditures. Ms. Davis emphasized that the department currently has only projection-type data and no way to verify that what was projected to be spent was the way the spending actually occurred. In future, operators may be requested to provide data so that historical costs can be reported. She stated that given the projections, DOR has concluded (at least for Prudhoe Bay) that maintenance and corrosion repair expenses are not the key driver behind the growth in capital expenditures. She noted that maintenance and corrosion repair expenditures grew between 2003 and 2008, but they did not grow disproportionately. Ms. Davis added that capital expenditures associated with production-related activities also grew. In other words, the growth in total capital expenditures was not simply because of maintenance and corrosion repair expense. Ms. Nienhuis commented that the majority of the increase in capital expenditures was due to drilling, seismic, and projects such as the development of the western region of Prudhoe Bay. Ms. Nienhuis reported that for the periods between 2003 to 2005 and 2008 to 2010, wellwork expenditures were the main driver behind the rise in operating expenditures; major repairs are a part of operating expenditures, but a relatively small part. Co-Chair Hoffman asked the amount of maintenance and corrosion repair expenses relative to drilling, seismic, and other projects. He wanted more detail than the "majority of the increase in capital expenditures." Ms. Nienhuis replied that there was generally about a $500 million per-year increase in capital expenditures from the three-year period before PPT; about 60 percent of the increase was due to drilling activities. 2:28:33 PM Co-Chair Stedman questioned whether the increase included the entire Prudhoe Bay basin. Ms. Nienhuis responded that the numbers applied to the greater Prudhoe Bay/Pt. McIntyre unit. Co-Chair Stedman queried credits related to capital expenditures created outside the described unit. Ms. Nienhuis responded that the data over the longer time related primarily to Prudhoe Bay. The analysis pertains to Prudhoe Bay prior to and after PPT. 2:30:08 PM Ms. Nienhuis moved back to previous slides, beginning with slide 20, "Spending Trends": · Company projection of expenditures changing · Fall 2008 projected increased expenditures in most units · Fall 2009 projected divergence in plans o Currently producing units - projected lower expenditure o Developing units - projected higher expenditures Ms. Nienhuis detailed that the data is from company projections operating on the North Slope in the spring and fall of 2008, and the spring and fall of 2009. She reported that in the fall of 2008, operators for most units projected increasing expenditures in both capital and operating expenditures. There was a change in the fall 2009 projections: some operators reported that they would invest less in both operating and capital expenditures; others reported that they would spend more in their fields. Ms. Nienhuis remarked that DOR surmised that generally the currently producing units were the ones that had projected decreasing expenditures in fall 2009, while the developing units projected higher expenditures going forward. The developing units projecting higher expenditures going forward included Point Thompson, Oooguruk, Nikaitchuq, and the National Petroleum Reserve-Alaska (NPR-A). The remaining units, Prudhoe Bay, Kuparuk, Milne Point, Endicott, and Alpine, were projecting decreasing expenditures going forward. Ms. Nienhuis continued that the department thought it might be detecting a trend and considered the data historically as well as in projection. The bar graph on slide 21, "Capital Expenditures by Type of Property," shows that as far as the percentage of the total capital expenditures, in FY 08 the underdevelopment category was around 25 percent of the whole. In 2009 through 2010 (projected for 2011), the underdevelopment expenditures comprise a greater proportion of the total spending on the North Slope. Ms. Nienhuis turned to slide 22, "Capital Expenditures on Currently Producing Properties." She listed the currently producing properties: Prudhoe Bay, Kuparuk, Milne Point, Endicott, Northstar, and Badami. The fall 2008 projections for the years of 2010, 2011, and 2012 total about $6.8 billion; the fall 2009 projections show the three years totaling about $5.4 billion. She emphasized that the Colville River unit is excluded in the calculations in each bar because the department does not receive the same level of capital projection as the others. 2:34:05 PM Co-Chair Stedman believed that oil is more plentiful and easier to find in currently producing Prudhoe Bay, Kuparuk, Alpine, and Milne Point units, and that the state could realize higher revenues. Ms. Nienhuis agreed that the units provided the majority of the production tax. Co-Chair Hoffman referred to an earlier presentation regarding three categories of North Slope wells: wells drilled in 2008, wells drilled in 2009, and wells that were permitted and planned. He queried the relationship between the three categories and the properties represented on slide 21 ("Capital Expenditures by Type of Property"). Ms. Nienhuis replied that the wells described in the earlier presentation were exploration wells and would be under the development category. Co-Chair Hoffman asked whether that related to wells permitted and planned. Ms. Davis explained that the presentation was regarding exploration activity; under the department's analysis [on slide 21] the same wells would be called "under development." She added that the previous presenter did not include a description of the wellwork and extra wells being drilled in currently producing fields. Co-Chair Hoffman surmised that the oil industry is saying there is a lot less activity but in fact there is an increase every year since 2008, 2009, and projected for 2010 and 2011. Ms. Davis replied that he was correct. 2:36:52 PM Ms. Nienhuis concluded with slide 23, "Capital Expenditures of Developing Properties," which shows a similar breakdown on developing properties. The fall 2008 projections received from the operators totaled $1.6 billion for the three years; that increased significantly in the fall 2009 projections to $3.1 billion. She warned that the company projections are not guaranteed and could change. 2:38:37 PM AT EASE 2:43:04 PM RECONVENED ADJOURNMENT The meeting was adjourned at 2:43 PM.