Legislature(2003 - 2004)

02/27/2003 03:21 PM House O&G

Audio Topic
* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
                    ALASKA STATE LEGISLATURE                                                                                  
             HOUSE SPECIAL COMMITTEE ON OIL AND GAS                                                                           
                       February 27, 2003                                                                                        
                           3:21 p.m.                                                                                            
MEMBERS PRESENT                                                                                                               
Representative Vic Kohring, Chair                                                                                               
Representative Hugh Fate                                                                                                        
Representative Lesil McGuire                                                                                                    
Representative Norman Rokeberg                                                                                                  
Representative Harry Crawford                                                                                                   
MEMBERS ABSENT                                                                                                                
Representative Mike Chenault, Vice Chair                                                                                        
Representative Beth Kerttula                                                                                                    
COMMITTEE CALENDAR                                                                                                            
HOUSE BILL NO. 113                                                                                                              
"An Act extending the renewal period for oil discharge                                                                          
prevention and contingency plans; and providing for an effective                                                                
     - MOVED CSHB 113(O&G) OUT OF COMMITTEE                                                                                     
HOUSE BILL NO. 61                                                                                                               
"An  Act establishing  an exploration  and development  incentive                                                               
tax  credit  for  persons  engaged in  the  exploration  for  and                                                               
development of  less than 150 barrels  of oil or of  gas for sale                                                               
and  delivery  without  reference  to  volume  from  a  lease  or                                                               
property in the state; and providing for an effective date."                                                                    
     - HEARD AND HELD                                                                                                           
PREVIOUS ACTION                                                                                                               
BILL: HB 113                                                                                                                  
SHORT TITLE:DISCHARGE PREVENTION & CONTINGENCY PLANS                                                                            
SPONSOR(S): RLS BY REQUEST OF THE GOVERNOR                                                                                      
Jrn-Date   Jrn-Page                     Action                                                                                  
02/19/03     0252       (H)        READ THE FIRST TIME -                                                                        
02/19/03     0252       (H)        O&G, RES, FIN                                                                                
02/19/03     0252       (H)        FN1: ZERO(DEC)                                                                               
02/19/03     0252       (H)        GOVERNOR'S TRANSMITTAL LETTER                                                                
02/27/03                (H)        O&G AT 3:15 PM CAPITOL 124                                                                   
BILL: HB 61                                                                                                                   
SHORT TITLE:OIL & GAS TAX CREDIT FOR EXPLORATION/DEV                                                                            
SPONSOR(S): REPRESENTATIVE(S)CHENAULT                                                                                           
Jrn-Date   Jrn-Page                     Action                                                                                  
01/24/03     0060       (H)        READ THE FIRST TIME -                                                                        

01/24/03 0060 (H) O&G, RES, FIN 02/04/03 (H) O&G AT 3:15 PM CAPITOL 124 02/04/03 (H) <Bill Hearing Canceled> 02/27/03 (H) O&G AT 3:15 PM CAPITOL 124 WITNESS REGISTER MARY SIROKY, Legislative Liaison Department of Environmental Conservation Juneau, Alaska POSITION STATEMENT: Briefly spoke about the intention behind HB 113. LARRY DIETRICK, Director Division of Spill Prevention & Response Department of Environmental Conservation Juneau, Alaska POSITION STATEMENT: Provided written testimony to explain HB 113; offered a brief synopsis and answered questions. DANA L. OLSON Wasilla, Alaska POSITION STATEMENT: Testified on HB 113, expressing concern about the public process and that there is no rational basis for the extension to five years. TADD OWENS, Executive Director Resource Development Council (RDC) Anchorage, Alaska POSITION STATEMENT: Testified in support of HB 113 and HB 61. MARILYN CROCKETT, Deputy Director Alaska Oil and Gas Association (AOGA) Anchorage, Alaska POSITION STATEMENT: Encouraged passage of HB 113 and expressed support for Amendment 1. DOUGLAS MERTZ Prince William Sound Regional Citizens' Advisory Council Anchorage/Valdez, Alaska POSITION STATEMENT: Testified in opposition to HB 113 as drafted. BRECK TOSTEVIN, Assistant Attorney General Environmental Section Civil Division (Anchorage) Department of Law Anchorage, Alaska POSITION STATEMENT: During hearing on HB 113, explained Amendment 1. LEONA OBERTS, Staff to Representative Mike Chenault Alaska State Legislature Juneau, Alaska POSITION STATEMENT: Presented HB 61 on behalf of Representative Chenault, sponsor. JOHN A. BARNES, P.E., Alaska Business Unit Manager Marathon Oil Company Anchorage, Alaska POSITION STATEMENT: Offered presentation on the reasons HB 61 is needed; answered questions. PAUL RICHARDS, Lobbyist for VECO Corporation Juneau, Alaska POSITION STATEMENT: Testified in support of HB 61. LARRY HOULE, General Manager Alaska Support Industry Alliance Anchorage, Alaska POSITION STATEMENT: Testified in support of HB 61. KEVIN TABLER, Manager of Land and Government Affairs Union Oil Company of California (Unocal) Anchorage, Alaska POSITION STATEMENT: Encouraged passage of HB 61. ACTION NARRATIVE TAPE 03-11, SIDE A Number 0001 CHAIR VIC KOHRING called the House Special Committee on Oil and Gas meeting to order at 3:21 p.m. Representatives Kohring, Rokeberg, Fate, and Crawford were present at the call to order. Representative McGuire arrived as the meeting was in progress. HB 113-DISCHARGE PREVENTION & CONTINGENCY PLANS Number 0093 CHAIR KOHRING announced that the first order of business would be HOUSE BILL NO. 113, "An Act extending the renewal period for oil discharge prevention and contingency plans; and providing for an effective date." [The bill was sponsored by the House Rules Committee by request of the governor.] CHAIR KOHRING, noting that [Larry Dietrick] hadn't yet arrived to present the legislation on behalf of the administration, offered a synopsis based on Mr. Dietrick's written testimony in committee packets. Chair Kohring explained that HB 113 has the goal of improving regulatory efficiency and reducing the administrative burden [on industry] while improving spill prevention, preparedness, and protection of the environment. It lengthens to five years [the time for renewal of oil discharge prevention and contingency plans], from the current three years. He offered his understanding that the administration believes this will create more flexibility in the system; will give industry more time to put plans together; and will help industry to spend more time on oil discharge prevention, and on implementing plans already in place, before having to refile their plans. Thus a five-year renewal period will streamline the review process for the industry while maintaining Alaska's strong spill prevention and response standards. CHAIR KOHRING continued, noting that oil discharge [prevention and] contingency plans are required of all operators of oil terminals, refineries, crude oil transmission pipelines, oil exploration and production facilities, oil tank vessels, [oil] barges, nontank vessels [over 400 gross tons, and railroad tank cars]. He said there is concern that this might compromise environmental protection, but the administration's position is that that won't happen and, if anything, this will complement the current process and provide those who must submit contingency plans more time to adhere to the regulatory requirements and put the plans into place. He added the belief that this extension to five years enables the emphasis to shift from paperwork to performance. Number 0389 MARY SIROKY, Legislative Liaison, Department of Environmental Conservation (DEC), emphasized that this legislation is to allow [DEC] to ensure that oil spill protection is even better than today. Through actual drills and putting plans into place, she said, [DEC] intends to ensure that people can put their plans into place when a spill happens. She noted that Breck Tostevin from the Department of Law should be on teleconference to speak to a proposed amendment. CHAIR KOHRING indicated amendments would be addressed after testimony was taken. He informed Mr. Dietrick, who'd just arrived, that he'd explained the legislation, but requested a synopsis. Number 0530 LARRY DIETRICK, Director, Division of Spill Prevention & Response, Department of Environmental Conservation, read the first sentence of his written testimony that had been summarized by Chair Kohring, which stated, "This bill supports the Governor's goal of improving regulatory efficiency by reducing the administrative burden while improving spill prevention, preparedness and protection of the environment." He offered to answer questions. Number 0607 REPRESENTATIVE CRAWFORD noted that he'd had a discussion with Ms. Siroky indicating this would allow more drills and testing of the actual spill response. He said he didn't see that direction in the bill, however. He asked whether [DEC] would be averse to some intent language that says the savings from this "break" would be used towards more drills and actual [hands-on training]. Recalling his time in Valdez from 1974-1977, he said a tugboat was supposed to escort all oil tankers out past Bligh Reef, an oil response crew was supposed to be on call 24 hours a day, and there was supposed to be sufficient boom [for an emergency]. All those went by the wayside, however, and there was no preparedness for the oil spill in 1989. He said he didn't want that ever to happen again, and didn't see how extending this to five years would [prevent it]. He emphasized his desire to see more testing, drills, and hands-on practice for an oil spill response. He again asked whether [DEC] would be averse to such intent language. Number 0770 MR. DIETRICK replied: I believe we'd be more than willing to review it. ... That is the concept, and that is what we're trying to do, is cut down on the bureaucratic and the administrative burden of the plan reviews, and that is a substantial burden. And by doing that, we're trying to be smarter and more efficient, to achieve the governor's goals. And I think this is a smart piece of legislation in that regard, and it frees up the operators to focus also on spill prevention and the operation of their plants, which is where spill prevention happens. And so that's very good. And then the shift to verification exercises and training, yeah, we think we can get a ... better "bang for the [buck]" - better operation of the facilities. Number 0833 REPRESENTATIVE ROKEBERG asked how long it takes once a plan is drafted and submitted for review. MR. DIETRICK answered that the timeframe depends on the complexity of the facility. Prince William Sound crude-oil tanker plans - which involve multiple owners of tankers, the Trans-Alaska Pipeline System (TAPS), and the Valdez Marine Terminal - are bigger and much more complex plans, and take longer than smaller plans for smaller oil terminal facilities around the state. There is a lot of upfront negotiation beforehand, he indicated, but once a completed application is received, there is roughly a 65-day period for public notice and review. REPRESENTATIVE ROKEBERG asked, because of the planning and review time, whether a plan now is only good for two years and some months, or whether the three years dates from [the time of] approval. MR. DIETRICK answered that depending on the complexity and which facility the plans apply to, the process may begin up to six months prior to the expiration date of a plan that is to be renewed. REPRESENTATIVE ROKEBERG said he understood DEC's testimony to be that the preference is to have everyone perfecting the ability to respond, rather than "sitting around writing plans." MR. DIETRICK concurred, suggesting that setting it back to five years would result in a significant gain [in time] and a reduction in the paperwork burden. Number 1051 MR. DIETRICK, in response to questions from Representative Rokeberg, explained that the extent of changes [to the plan] at the time of renewal really depends on the facility, the extent to which the nature of the operation has changed, and any corresponding change in response capability. If the situation is status quo, then the changes are relatively minor compared with those when somebody has added storage tanks or similar modifications. There is a requirement to update, however, which applies to new technology as well as "typical things" done at renewal time. Therefore, the update to evaluate new technologies would be an item that all operators would perform. Number 1191 REPRESENTATIVE ROKEBERG posed a hypothetical example of a port facility that has expanded its capacity, and asked whether it is required under the current plans that there be modifications for that during the course of an approved plan. MR. DIETRICK answered that there is another provision in the requirements for an amendment of a plan. If a change or modification to a plan is significant and may affect the response capability during the time when the plan is in effect, then that would be triggered and the operator would request to amend the plan within the three-year cycle. REPRESENTATIVE ROKEBERG asked whether provisions in the current process for plans approved by DEC already have flexibility to account for a substantial change in the capacity or other circumstances of a facility, or for new technological advances. MR. DIETRICK said that is correct. In response to a further question, he said one benefit of extending the renewal is that the amendment requirement now in place requires continuous changes to that plan for anything that happens which may be significant during that plan cycle. Number 1317 REPRESENTATIVE ROKEBERG asked whether it is correct, then, that if DEC is doing its job and the amendment process works properly, there should be no additional risk whatsoever "to what's contemplated under a contingency plan." MR. DIETRICK answered in the affirmative, noting that there also is a mechanism whereby the operator is required to immediately notify [DEC] of nonreadiness if, for any reason, that operator's equipment or response capability isn't up to par and in a state of readiness. He indicated the department would immediately pursue corrective action after being notified by such an operator. REPRESENTATIVE ROKEBERG asked whether DEC audits these capabilities or somehow checks on these plans periodically. MR. DIETRICK replied: Yes, but ... we think there's a better "bang for the buck" if we can increase working directly with the operators to actually verify - through exercises, training, equipment audits, and [so forth] - their capability. ... It's just a much easier communication. You can work more hands-on with the operators. You can find out where problems are that you can't through the theoretical plan-review exercise. So, yes, we would increase -- that is the intent. And, actually, I believe our goal would be to get improved performance and response capability as a result of doing [this]. Number 1429 MR. DIETRICK, in response to further questions from Representative Rokeberg, explained that for noncrude or refined products, storage in excess of 10,000 barrels is the threshold for requiring a contingency plan; for crude oil, the storage threshold is 5,000 barrels. A plan is required for an oil well as long as it involves liquid hydrocarbons, regardless of whether it is an exploratory well or a production well. REPRESENTATIVE ROKEBERG suggested a fuel oil company with more than 10,000 barrels would have to have a plan. MR. DIETRICK affirmed that. CHAIR KOHRING thanked Mr. Dietrick and opened the public testimony. Number 1521 DANA L. OLSON referred to written testimony she'd sent the committee and told members that contingency plans address the permittee, not the public. Noting that AS 46.03.040 is a requirement by the legislature for an environmental plan, she explained: It's not been done, and that's the public process. So, in other words, you are assuming that the criteria has been set for these [contingency] plans, and I really am just going to have to raise an objection. ... You have to have a factual basis first, to ... base a contingency plan on, and that's not been done. Where the technological data is not provided to the public at the lease sale ... stage or the coastal consistency, at some point it triggers a need for the public to know what the secondary effects are from this ... permitted activity. The community right-to-know laws are meaningless if you go in and you write a contingency plan and you make ... presumptions without any public process. I would have to raise an objection. I feel that there isn't an adequate public process because you're not addressing the public; you're addressing what the agency will do and what the permittee or the activity will do, and ... not what the effect on the public is. I wanted to say that the state's disaster plan is supposed to be a community-based effort, and not an agency-directed or an legislative-enacted activity. And certainly contingency plans are basically a mini- disaster plan. And I'm really going to have to object to this five years. It has no rational basis. If there is a need because there is a hazard or the public welfare is in need, it's an arbitrary decision-making thing. Disaster is public welfare, and economics don't ... fathom under national security either. So I don't know how you're going to address ... a state disaster plan when you are not addressing the public. Number 1701 TADD OWENS, Executive Director, Resource Development Council (RDC), testified that RDC is a private, nonprofit business association representing individuals and companies from Alaska's oil and gas, mining, timber, tourism, and fisheries industries; it mission is to help grow Alaska's economy through the responsible development of natural resources. Mr. Owens specified that RDC supports HB 113, which changes the renewal period for DEC-required discharge and contingency plans ("C- plans") from three to five years. Although C-plans are essential to spill response preparedness, he said the effort associated with the plan renewals is significant for both industry and the state. He told the committee: Based on our members' experiences, a three-year renewal cycle often does not result in meaningful improvements in environmental protection or regulatory compliance. Increasing the time between renewals from three to five years will bring the program's benefits in line with its costs. A five-year renewal cycle will allow the state to focus its resources on site inspections, rather than the office work associated with plan reviews. Currently, [DEC] is responsible for more than 125 C- Plans in Alaska. And we believe that allowing agency staff additional time in the field will provide them with a more thorough understanding of industry operations. A five-year renewal period will give agency staff a better opportunity to determine the effectiveness of existing plans and to observe plan implementation prior to any incident. By utilizing this information and experience, subsequent plan renewals will have better oversight, incorporate more high-value improvements, and be less vulnerable to legal challenges. Meanwhile, industry will be able to shift its resources away from the largely administrative exercise of three-year renewals to additional prevention-specific activities. Improved networking and communication between industry and [DEC] will further emphasize and enhance the quality of plan renewals. Also, a five-year renewal cycle would mirror the federal requirement, allowing industry to consolidate its review process. RDC's members believe that increasing the C-Plan renewal cycle from three to five years will result in a more thorough public process, the creation of more realistic and sophisticated plans, and establish a more efficient and predictable regulatory regime. HB 113 deserves the committee's support. Number 1886 MARILYN CROCKETT, Deputy Director, Alaska Oil and Gas Association (AOGA), testified that AOGA is a trade association whose 17 member companies account for the majority of the oil and gas activity in the state. All of AOGA's members that have activity in the state are required to have a C-Plan approved and in place. She told the committee, "Clearly, we have a significant interest in this legislation, and we encourage the committee to pass it." MS. CROCKETT reported that AOGA spent considerable time over the past 12 months looking at permitting programs and identifying those in need of updating and streamlining, and early on had adopted a guiding principle: "accomplish updates and streamlining without compromising environmental protection of safety standards." She said HB 113 fits perfectly within this principle. MS. CROCKETT indicated the five-year cycle proposed in the bill is the cycle used by the federal government, the West Coast states, and "other oil-producing states that we've studied." She reported that the cost of renewal alone can average $60,000 to $100,000, depending on the type of facility; that doesn't include legal challenges, which can increase figures up to half a million dollars. In addition, the renewal process is time- intensive. She reported that experience has shown that for some plans, even with submittals 180 days in advance of the expiration date, approvals can still average 360 days, "essentially meaning that once a renewal is complete, work must begin on the next renewal." Number 1982 MS. CROCKETT emphasized what purpose a C-Plan serves: it is a blueprint describing how an operator will respond to an event. The proof of its effectiveness isn't how often it is renewed, but whether the response identified in the plan can be delivered as promised. Demonstration of this effectiveness is accomplished through drills, she said, suggesting this area is where the biggest benefit of extending the renewal cycle will be seen, by shifting the focus from administrative processing to field performance. The extension also will provide additional time for agency staff to increase their familiarity and understanding of a particular operation for which they are responsible. MS. CROCKETT, calling these C-Plans "evergreen" documents, said they are continually reviewed by the operators to ensure that the information is kept up to date, and that the plan continues to reflect the current operation and state of readiness. She noted that DEC regulations require that updates and amendments be submitted to the department. Number 2033 MS. CROCKETT referred to the amendment mentioned by Ms. Siroky [to be discussed by Breck Tostevin of the Department of Law]. That amendment [later adopted as Amendment 1], read as follows [original punctuation provided]: Page 1, following line 10: Insert a new bill section to read: **Sec. 2 The uncodified law of the State of Alaska is amended by adding a new section to read: TRANSITION. Notwithstanding any contrary provision of AS 46.04, including the review procedures in AS 46.04.030, and the regulations adopted under AS 46.04, the expiration date of an oil discharge prevention and contingency plan approved by the Department of Environmental Conservation before the effective date of this Act shall be extended for two years, or for a shorter period if a shorter period is requested by the holder of the approved plan, if (1) the plan is still in effect on the day before the effective date of this Act; and (2) the Department of Environmental Conservation has not given a notice of violation of AS 46.04.030 to the holder of the plan that has not been corrected to the satisfaction of the Department of Environmental Conservation. Renumber remaining sections accordingly. MS. CROCKETT specified that AOGA supports the amendment. She noted that with her were people she considered experts in this field who could answer technical questions. Number 2129 DOUGLAS MERTZ, Prince William Sound Regional Citizens' Advisory Council (RCAC), testified in opposition to HB 113 as drafted. Noting that his organization is a coalition of mostly municipal and borough governments and other entities formed after the Exxon Valdez [oil spill], he said it is actively involved in tracking the entire process of oil transportation from Valdez, through Prince William Sound and throughout that area. Intimately involved in the C-Plan creation and approval process on an ongoing basis, the RCAC has concluded that it must oppose this bill as currently drafted because it will, in fact, weaken Alaska's oil spill prevention and response capabilities, Mr. Mertz reported. MR. MERTZ discussed the three ways his organization believes this will happen. First, extending the timeframe inhibits the timeliness of the agency's ability to incorporate into C-Plans those lessons learned from on-the-ground, in-the-field drills and other exercises, which are an incredibly important part of learning and preparation for oil spills. Second, it reduces the frequency of updating the "best available technology" (BAT) analyses, a highly important part of the entire oil spill process. Under the C-Plan requirements, plan holders are required to employ BAT in their oil spill preparedness, prevention, and response capacities. Extending the time period for these renewals will basically defer - and almost double - the time period during which the BAT analyses must be undertaken and implemented. And third, it reduces the agency's and plan holder's familiarization with the plan, which could result in complacency. From the Exxon Valdez and other major spills, he cautioned, [it has been learned that] what very often precedes such a spill is a period of complacency. Number 2270 MR. MERTZ countered testimony that an extension to five years would align Alaska's requirements with federal requirements. He pointed out that because Alaska's requirements now are stricter than the federal ones, the federal requirements "tend to be a much less extensive plan update to the Alaska requirements." Furthermore, the federal regulations have an additional requirement for an annual review and update. There is no such requirement in Alaskan law, and this bill wouldn't add one. He suggested: If you really want to align what happens on the state level with what happens on the federal level, then that same annual review and update should be incorporated; in fact, you could lift the language from the federal regulations and incorporate them into state law directly, to truly make it in alignment. MR. MERTZ noted that the RCAC's testimony was provided by fax to each member the previously day, and said he wouldn't read it this day. He again pointed out that his organization, which follows these issues carefully, is increasingly uncomfortable with the idea of extending this plan without this kind of additional safeguard and additional requirements that ensure an ongoing, mandatory duty to update plans annually or on some more frequent basis than five years. Number 2359 REPRESENTATIVE ROKEBERG offered his understanding from Mr. Dietrick's testimony that already in existence are the amendment process and provisions for notification of nonreadiness with regard to C-Plans in Alaska. He asked whether those processes aren't working correctly, and whether they aren't equivalent to annual review. MR. MERTZ responded: They're not the equivalent. Those are ... tools which can be used in the extraordinary circumstances of true inability to respond to fulfill the plan, or some extraordinary event [that] makes actuality diverge from what's in the plan. But that's different from what the federal regulations require, ... an actual, ongoing update incorporating best available technology ... as a regular matter - in other words, ... a constantly evolving process that ... continually causes ... an improvement in the ability of the plan holder to perform. What [Mr. Dietrick] ... was talking about really can be invoked only in extraordinary circumstances. And right now the agency doesn't have the ability to say to a plan holder that "you must do these incremental, almost continuous improvements in your ability to perform." Number 2434 CHAIR KOHRING asked whether anyone else wished to testify. He then closed public testimony. Number 2453 REPRESENTATIVE ROKEBERG asked Mr. Dietrick to respond to the testimony of Ms. Olson about the public process and the idea that C-Plans are supposed to be a community-based effort. MR. DIETRICK answered: The public review process is provided for, for contingency plans. It's a 30-day public review process with a request for additional information. And we ... do those. So ... that's a fairly standard public notice review period that the department uses for most of its major permits and authorizations. So that's the one that's in place for contingency plans, and that's what we use to provide for the public notice. Number 2504 REPRESENTATIVE ROKEBERG asked Mr. Dietrick to respond to Mr. Mertz's three main points [also set out in the RCAC's letter dated February 26]. He offered his own assessment that having a plan longer leads to more familiarity, rather than complacency. MR. DIETRICK replied: First of all, ... I think the good news about the bill is, I think everybody has the same goal. The Prince William Sound Regional Citizens' Advisory Council has been given an oversight role under the Oil Pollution Act of 1990 to make sure we all do a good job. And we work with them all the time. They've got good expertise and experience, and we ... seriously consider their input on all oil spill prevention and response matters, ... as we do their comments today ... on this bill. So we treat those very seriously, and ... they are a very key player here in ensuring the integrity of the system. We sometimes disagree on the approach and ... how to get to those goals. ... We believe that actual field testing is a better way to move forward and test the capability of these systems than these ... three-year renewals. And that's why we believe the extension to five-year [renewals] is a substantial improvement. With regard to the lessons learned and the delaying the lessons learned, we do not wait even till three years now to incorporate lessons learned from drills into a plan. We do roll those into a plan now, if they are significant, by amendment. So extending it to five years is neither here nor there, because if it is significant, the idea is, we use the amendment process to include them now. And for major plans, even in the Prince William Sound area, we have monthly meetings - they call them the "response planning group" - to review lessons learned, sort through them, determine which ones are significant; they're even tracked in a system called "Passport" (ph). We ... would like to improve on that, but ... there very clearly is a mechanism in place to ... roll those lessons learned in without any delay. Number 2659 MR. DIETRICK addressed the RCAC's concern about review of the best available technology as follows: With regard ... to the second point in their letter, the best available technology reviews, those are performed at the time of renewal, and ... the intent behind those is to keep these plans current with changes in technology. Now, the technology-review cycle for oil spill response equipment is ... long. ... There have not been many breakthroughs. A five- year cycle for a technology review, I believe, is an appropriate cycle. As a matter of fact, our regulations require that we conduct a "best available technology" conference on a five-year basis right now. This would simply line that up. The best available technology analyses that are performed in these plans [are] a theoretical exercise. And we believe it's more important - than to review those - to actually go out and test those premises more frequently to see if they work, to see if the technology that was analyzed and arrived at in the plan is actually the ... best available technology when you implement it. So increasing our ability to do that in the field will, I believe, drive faster advances in technology improvements, because ... we will have the ability ... to test those, reject the ones that don't work, and then seek improvements ... and get better ones ... that will work. Number 2733 MR. DIETRICK responded to the RCAC's concern about complacency as follows: I think the third point, then, was the complacency. And, indeed, that is a significant phenomenon that we all need to be aware of. It's the one that, a decade ago, was pointed to quite frequently. And I think no one wants to slip back into that mode. This change, however, again, I think is a smart change because it gets us away from the theoretical reviews and gets us [to] the point where we can actually test the capabilities of the response system and actually, then, through testing, identify which ones are real and which ones aren't, and then seek the improvements that way. So I think it's a much more productive way of 1) interacting with the companies, 2) finding out what does work, and 3) that is really, in our opinion, an increased interaction with the operators, which to me does just the opposite - it reduces the complacency. Number 2835 REPRESENTATIVE ROKEBERG asked whether both the plan applicant and [DEC] have the ability to move to amend [a plan]. MR. DIETRICK replied that he believes the statutes are quite strong. He paraphrased from AS 46.04.030, which read in part: (f) Upon request of a plan holder or on the department's own initiative, the department, after notice and opportunity for hearing, may modify its approval of a contingency plan if the department determines that a change has occurred in the operation of a facility or vessel necessitating an amended or supplemented plan, or the operator's discharge experience demonstrates a necessity for modification. The department, after notice and opportunity for hearing, may revoke its approval of a contingency plan if the department determines that (1) approval was obtained by fraud or misrepresentation; (2) the operator does not have access to the quality or quantity of resources identified in the plan; (3) a term or condition of approval or modification has been violated; or (4) the person is not in compliance with the contingency plan and the deficiency materially affects the plan holder's response capability. REPRESENTATIVE ROKEBERG requested that Mr. Dietrick provide a copy for the committee's files and for the bill packet [to be given to the next committee of referral]. MR. DIETRICK said he would gladly provide those parts of the statute and the nonreadiness [provisions]. Number 2878 CHAIR KOHRING moved to adopt Amendment 1 [text provided previously]. The committee took an at-ease at 4:07 p.m. and was called back to order within a minute. Number 2911 BRECK TOSTEVIN, Assistant Attorney General, Environmental Section, Civil Division (Anchorage), Department of Law, explained that Amendment 1 adds a transition provision that requires DEC to administratively extend the expiration date of an oil discharge prevention and contingency plan that was approved before the effective date of this Act. That extension would be for two years, or for a shorter period if a shorter period were requested by the holder of an approved plan. He said a shorter period would be to allow a plan holder to synchronize with a federal plan review or if a shorter period were needed for some other reason. MR. TOSTEVIN said there would be two limitations on the authority for extending the plan renewal date. First, the plan would have to be in effect on the day before the effective date of the Act. And second, if the department had issued a notice of violation to the C-Plan holder concerning the C-Plan, that would have to be corrected to the department's satisfaction before the extension of the plan expiration date. MR. TOSTEVIN explained that the intent behind the transition provision is to extend the expiration date of existing plans without requiring a new administrative review or renewal procedures, or requiring DEC to adopt unnecessary regulations. This transition provision would allow immediate benefits to the industry and the department, he suggested, as discussed earlier by Mr. Dietrick. He offered to answer any legal questions. TAPE 03-11, SIDE B Number 2976 CHAIR KOHRING renewed his motion to adopt Amendment 1. There being no objection, it was so ordered. The committee took an at-ease from 4:11 p.m. to 4:13 p.m. Number 2950 REPRESENTATIVE CRAWFORD moved to adopt [Conceptual] Amendment 2. CHAIR KOHRING objected for discussion purposes. REPRESENTATIVE CRAWFORD explained that he wanted to adopt intent language taken from Mr. Dietrick's written testimony, as follows: Streamlining the process would allow the applicant to focus on the actual testing of oil spill prevention and response preparedness through [in-the-field] inspections, drills, and exercises, which is our most effective means of ensuring spill prevention, response readiness, and protection of the environment. Number 2896 REPRESENTATIVE ROKEBERG also objected for discussion purposes, pointing out the need to have this be a conceptual amendment. REPRESENTATIVE ROKEBERG withdrew his objection. CHAIR KOHRING renewed his objection for discussion purposes and asked Mr. Dietrick to provide his thoughts on the amendment. Number 2850 MR. DIETRICK offered his belief that DEC would concur with the language. CHAIR KOHRING withdrew his objection. He then announced that Conceptual Amendment 2 was adopted. Number 2830 REPRESENTATIVE ROKEBERG moved to report HB 113, as amended, out of committee with individual recommendations and the accompanying zero fiscal note. There being no objection, CSHB 113(O&G) was reported from the House Special Committee on Oil and Gas. HB 61-OIL & GAS TAX CREDIT FOR EXPLORATION/DEV Number 2816 CHAIR KOHRING announced that the final order of business would be HOUSE BILL NO. 61, "An Act establishing an exploration and development incentive tax credit for persons engaged in the exploration for and development of less than 150 barrels of oil or of gas for sale and delivery without reference to volume from a lease or property in the state; and providing for an effective date." Number 2795 LEONA OBERTS, Staff to Representative Mike Chenault, Alaska State Legislature, presented the sponsor statement for HB 61 on behalf of Representative Chenault, as follows: HB 61 creates a new income tax credit to encourage increased exploration and development of natural ... gas reserves south of the Brooks Range. While focused primarily on natural gas reserve development, the bill also provides an incentive for the development of marginal oil reserves, should they be discovered. For the purpose of this bill, marginal oil production is defined as that which initially produces 150 barrels of oil per day or less. To qualify for the credit, operators must successfully drill and develop hydrocarbon reserves that produce natural gas for sale and delivery. The credit may offset no more than 50 percent of an operator's annual income tax liability, and remains in effect for a period of 10 years. The tax credit would amount to 10 percent of qualified investments - and 100 percent of services associated with said investment - for each year. For example, an operator who spends $20 million in a given year successfully developing natural gas reserves would receive an income tax credit of $2 million - applicable to up to one-half of its income tax liability for that year. Credits in excess of 50 percent of the operator's income tax liability can be carried over to future years. This is a "successful efforts" bill, which means that no credits will be given for dry holes. The Cook Inlet continues to have great potential for additional natural gas development. Other Alaska basins outside of the North Slope have similar potential. However, the combination of exploration risk, high development costs, and historic low natural gas prices has ... created a disincentive to drill for new reserves as compared to other areas of the world. By providing a credit for successful efforts, more exploration will occur in southern Alaska, leading to much-needed new natural gas reserves. This will benefit all residents and businesses, at no direct cost to the state. In addition to the benefit of developing new gas reserves, increased Cook Inlet drilling will also aid the general economic status on the Kenai Peninsula and in Anchorage, as well as other areas of Alaska. Moreover, increased tax revenue from additional hydrocarbon production will more than offset any fiscal impact from the proposed credit. MS. OBERTS informed members that there were experts available to answer questions. CHAIR KOHRING opened the public hearing. Number 2626 JOHN A. BARNES, P.E., Alaska Business Unit Manager, Marathon Oil Company ("Marathon"), came forward to provide a presentation on why Marathon believes HB is needed [handout in packets]. The committee took an at-ease from 4:20 p.m. to 4:22 p.m. to address technical difficulties. [The recording didn't begin immediately; however, the handout contained all material discussed, with page 1 being a cover sheet.] Page 2 of the handout read as follows, with some punctuation and formatting changes, and with abbreviations spelled out in brackets: HB 61 - What Does it Do? Creates income tax credit to encourage exploration and development of gas reserves south of Brooks Range. Primary focus in on Cook Inlet, but applies to other basins. Primary focus is on natural gas, but applies to smaller oil as well (less than 150 bopd [barrels of oil per day]). Levels the playing field somewhat with other exploration opportunities around the world. Draws more E&P [exploration and production] capital to Cook Inlet. Page 3 read in part as follows, with some punctuation and formatting changes: HB 61 - How Does it Work? Applies to 10% of Qualified Capital Investment. Applies to 100% of Qualified Expense. [Recording began again at this point.] Number 2580 MR. BARNES, noting that this bill allows an offset of no more than 50 percent of corporate income tax in any one year, explained that any amount left over could be carried forward for up to five additional years. He emphasized that this [incentive] only applies to successful efforts. Another key point is that it could be factored into economic analyses as a company analyzes various opportunities. Currently, he noted, the State of Alaska has some other incentive programs that are attractive, but often those only kick in at the discretion of the commissioner of the Department of Natural Resources (DNR). Thus there is uncertainty, until after the investment is made, as to whether those would be applicable in any one case. MR. BARNES discussed page 4 of the handout, which addressed why HB 61 is needed. He said this is probably the most salient point: natural gas reserves have been declining and continue to do so in Cook Inlet. The current estimate of proven natural gas reserves is about 2 trillion cubic feet (Tcf) or 2,000 billion cubic feet (Bcf), based on the most recent DNR report. Despite recent increases in [exploration] activity there, reserves aren't being replaced on an annual basis. He explained, "You will only have a sustainable business if you replace what you produced in any one year; otherwise, you are in a declining business." Number 2486 MR. BARNES referred to page 5, a graph labeled "Cook Inlet Proven Gas Reserves" that looks at the years 1990-2002 [with DNR cited as the source]. He pointed out that in 1990 reserves were in decline and totaled about 3,500 Bcf. From 1995 to 1997, there was an increase of just over 1 Tcf, a result of recalculations rather than drilling new wells; he said if that incremental number were put on the front of the curve, it would show a decline. He pointed out that [as of 2002] about 2,000 Bcf or 2 Tcf of gas was left in Cook Inlet. MR. BARNES referred to page 6 of the handout, further addressing why HB 61 is needed. He said Cook Inlet deliverability - "the rate at which you could produce natural gas" - has been declining over the last several years. MR. BARNES turned to page 7, a graph titled "Cook Inlet Peak Supply/Demand." He explained that the part labeled "Total Requirement" would be what is required if "every contract peak requirement" occurred at the same moment on the same day: if ENSTAR [Natural Gas Company ("ENSTAR")] needed the maximum gas for heating homes, if Chugach [Electric Association, Inc.] needed the maximum for generating electricity, and if "the industrials" that use gas [needed the maximum as well]. He pointed out that the amount shown is more than 800 million cubic feet a day of natural gas. In 1997, he reported, Cook Inlet could produce about 900 million cubic feet a day; current estimates are about 667 million cubic feet a day. He emphasized that there is a shortfall - that Cook Inlet isn't producing what would be required to fulfill the needs of every consumer. Number 2383 MR. BARNES addressed page 8 of the handout, noting that "supply and demand rationalization" will occur because the free market works. He said the first occurrence is that not enough gas is produced to "feed the low-price consumer"; he suggested members had heard testimony previously about that. Another result of scarcity is that the price of gas rises. He suggested ENSTAR is probably a good measure of the cost of gas in Cook Inlet because it is the local heating utility; its weighted average cost of gas (WACOG), the price it pays to acquire gas from "a family of contracts," now is about $2.55 per Mcf [thousand cubic feet]. He said the most recent ENSTAR gas contract was signed at a price that has a floor of $2.75 but can range upward to a "rolling average of Henry Hub." He pointed out that the recent Henry Hub price of $15 or more per Mcf is an aberration in the marketplace; in reality, the Henry Hub price has been averaging $4 to $5 per Mcf. Mr. Barnes told members that the marketplace works, that natural gas prices are rising, and that "there's an impact of higher prices." Number 2307 MR. BARNES addressed page 9 of the handout, "Cook Inlet Reserves & Resources." He reiterated that current proven reserves are estimated at 2,000 Bcf. At an annual consumption rate of 200 Bcf per year, which he said is what is burned in Cook Inlet, the reserve life there is about 10 years. Beyond reserves - gas known to be in the ground - he explained that there is a category called "resources" - gas that technologists, geophysicists, and geoscientists estimate could be found. Speaking of unspecified committees, he said: The most recent that I'm aware of is the estimate by a potential gas committee of two resources: a probable reserves, which is about a 50 percent chance that you'll find it, of about 1,050 Bcf of gas; and possible reserves, which is less than a 50 percent probability, of about 2.1 Tcf [or] 2,100 billion cubic feet. Number 2245 MR. BARNES addressed page 10 of the handout, impacts to the State of Alaska from HB 61. He said that first and foremost, Marathon believes [the bill] would stimulate activity in Cook Inlet and potentially other basins, and would aid in maintaining Cook Inlet's current production of 200-plus Bcf a year. He said 200 Bcf a year is a significant number. If converted on an "energy basis" to equivalent barrels of oil a day, it would be roughly 33 million barrels, about one month's worth of North Slope production; he therefore suggested viewing Cook Inlet [production] as a thirteenth month's worth of North Slope production for the state. He pointed out that it provides gas for the Cook Inlet utilities; provides feedstock for "industrials"; and would result in jobs, royalties, and taxes. Number 2195 MR. BARNES turned to page 11 of the handout. He reported that Marathon believes the incentive clearly would be positive for the State of Alaska. He listed factors when thinking about impacts: how many developments might be incentivized; how much gas will be discovered; what the price of the gas will be when it is sold, which affects royalty and severance tax value; and how much money will be spent in efforts to explore for and ultimately develop reserves. He called it "successful efforts- driven," since no incentives for dry holes are included in HB 61. MR. BARNES addressed page 12 of the handout, which includes a conceptual estimate of fiscal impacts to the State of Alaska under HB 61. He clarified that the assumptions he'd used included the following: the field size of the discovery was varied from 0 Bcf to 500 Bcf; and he'd used a development-cost estimate of $.50 per Mcf, a royalty of 12.5 percent, severance tax at 7.5 percent, ad valorem at 2.7 percent, and a gas sales price of $2.50 per Mcf. He noted that other parties might vary these assumptions for their own analyses. Number 2132 MR. BARNES turned attention to page 13, a table labeled "Fiscal Impact to State of Alaska." Choosing a discovery with a field size of 50 Bcf as an example, he explained that the development cost for that field - what the operator would spend to drill wells and probably put in facilities - would be around $25 million. The tax credit proposed in the bill, at 10 percent of [the taxpayer's qualified capital investment], would be about $2.5 million. The gross revenue generated by the field would be about $125 million. The royalty received [at 12.5 percent] would be about $15.6 million. The severance tax [at 7.5 percent] would be $9.3 million. And the ad valorem would be estimated at about $1 million. Therefore, the total tax generated through this discovery would be about $26 million, about 10 times the value of the tax credit. MR. BARNES turned to page 14, a graph illustrating [the information on page 13]. He pointed out that the tax credit is rather low on the curve, but that the lines showing the total development cost and total tax take are about the same. He said it means, on average, that the money an operator spends finding and developing a field is [about the same] as what the state might ultimately receive in royalty and other tax payments. Number 2025 MR. BARNES discussed conclusions on page 15 of the handout. He noted that there might be a question of how many of these fields truly need incentives. Based on this conceptual tax model, he said, if only one field were incentivized, that tax credit would generate enough other taxes to pay for the "incentivization" that the state might lose, so to speak, from ten other fields of roughly the same size. MR. BARNES told members Marathon believes the credit is needed now, and that he believes there isn't enough exploration and development activity in Cook Inlet now to meet demand. Providing an example, he reported that recently [Marathon] advertised to hire four production operators, and received more than 90 applications from people looking for work in the gas fields there. He also pointed out that new discoveries take about three years to bring to "first gas" because of permitting and other issues. He said Marathon is very appreciative and supportive of efforts underway to look at the permitting process; he suggested that would be good for the state as well. Number 1958 MR. BARNES addressed the final page of the handout, page 16, suggesting someone would look for the following to determine the success of this legislation: increased lease activity by those looking to acquire leases; increased drilling rig activity; increased construction activity; increased production; increased deliverability; and that credits are being applied for, which is "the measure that new gas is being found." He pointed out that under the economic scenario he'd proposed, approximately $10 would be spent successfully to develop new reserves, and about $10 would come to the state as new tax revenue. CHAIR KOHRING commended Mr. Barnes for presenting such a compelling argument. Number 1901 REPRESENTATIVE CRAWFORD referred to page 3 of the handout, which said this would apply to 100 percent of qualified expenses. He asked, when Mr. Barnes had explained the figures on page 13, whether those included the qualified expenses. MR. BARNES answered that it is intended to be included. He suggested perhaps it is a problem of wording or misunderstanding between how an oil and gas company might present the economics and how the state might draft the bill. He said the 100- percent-of-service charge would be intended to represent "the intangibles for labor costs that might be associated with putting the tangible - the iron - in the ground, so to speak, or to build a facility." He suggested this committee or a subsequent one might want to discuss a language change in this regard, but said it is intended that it be represented in that 10 percent of the cost. Number 1834 REPRESENTATIVE ROKEBERG said he was glad to hear Mr. Barnes talk about the fact that Cook Inlet [is estimated to have] 10 years for proven reserves and perhaps 15 for probable reserves. He expressed concern about ensuring that the resource is available for economic development and growth there. Referring to testimony by Mr. Barnes about gas prices, he asked whether supply and demand wouldn't go a long way towards solving the problem if, in fact, the reserves were there. MR. BARNES responded: My view would be that if you could depend solely on market conditions, ... probably ... you'd see prices increase until there was sufficient stimulation for activity. And then you'd have activity, and then ... you might find enough gas for supply-demand to drive it down again. ... That would be ... one model; you're correct. Alternatively, if sufficient drive was created soon enough, you might actually see sufficient activity to find gas that might moderate that supply- demand marketplace action you were talking about. Number 1711 REPRESENTATIVE ROKEBERG asked whether it is whatever [Marathon] expends in exploration and production for new production that would qualify [under the bill]. MR. BARNES answered: It's intended to represent -- into the pot of funds that would qualify would be those funds expended towards the exploration and development of new - and that's ... the critical term, "new" - gas reserves or oil, if you found oil and it was a small enough field. So it's not your ongoing, day-by-day expenses associated with your current activities. It's expenses associated with finding and then bringing to production ... that new field. Number 1585 REPRESENTATIVE ROKEBERG surmised that it wouldn't be for an existing oil well, then. He asked, "Does it occur geologically in Cook Inlet that you can ... drill a well maybe for gas and then have some incidental production of oil?" MR. BARNES replied, "Not very often. But, again, if you did find a marginal oil well by happenstance, I don't know what the probability would be, but the intent would be to try to recognize that those economics are difficult as well." REPRESENTATIVE ROKEBERG suggested that if a $20-million well only produced 150 barrels a day, the company would get a tax credit anyway. He asked whether that was what Mr. Barnes was saying. MR. BARNES said a company could produce a 150-barrel-a-day well, but if it cost $20 million to get there, it would be a very risky proposition and a company might not choose to operate it. He indicated that the intent is, should somebody find it, that [this incentive] would provide an opportunity [for production]. REPRESENTATIVE ROKEBERG asked, if there were an areawide lease for which the company had a bonus bid, whether that dollar amount also would be part of the qualified capital investment because of its being real property. MR. BARNES replied, "Probably so. I would think so." Number 1512 REPRESENTATIVE ROKEBERG suggested "everything but the kitchen sink" is included, and mentioned cost accounting. He expressed concern about the 150 barrels a day [as a limit] and how that would work out. Furthermore, he said, the legislature has passed bills previously under which certain fields have been designated for special royalty treatment; he also mentioned the "180(j) sections" for royalty, which have never been used, as well as a bill he and Chair Kohring are working on as an incentive for marginal fields. He asked how these different programs fit together. MR. BARNES agreed that there is a "family" of royalty-reduction programs and policies from legislation that has passed. He said one is specific to certain fields, which to his belief must begin production by the end of this year. There also is a royalty reduction available for a marginal field, but that doesn't stimulate new activity; it only maintains production in an older field. Furthermore, a "discovery royalty" [incentive] is at the discretion - ultimately, to his belief - of the commissioner of DNR; to his understanding, he said, no field has actually qualified under that. Mr. Barnes offered Marathon's view that those are more difficult to predict with regard to economics, whereas this could be "run through your calculator" and is not discretionary; it is easier to analyze economically and easier to propose to management. He added, "Discretionary ones are more difficult, obviously." Number 1303 REPRESENTATIVE ROKEBERG offered his understanding that the Division of Oil & Gas has indicated a producer or operator on the North Slope could "come to the Cook Inlet and buy existing production or invest in an existing well," which would provide some offset against North Slope tax obligations to the state. He asked whether Marathon has looked at that. MR. BARNES noted that the bill clearly says it is for the exploration and development of new reserves. He said he didn't understand how it would apply to buying existing production. REPRESENTATIVE ROKEBERG again asked whether a tax credit developed in Cook Inlet could be used to offset [tax obligations relating to the North Slope]. MR. BARNES indicated that if a company positioned itself to offset $10 million of North Slope-derived corporate income tax, the company would have spent $100 million in Cook Inlet successfully finding and developing natural gas. He said he would think that was great, because that 10-to-1 multiplier would indicate that the $100 million spent by the company ought to generate new taxes. He added, "I would believe that an offset of tax from another ... basin would not be as important as the fact that you did find ... new gas reserves." REPRESENTATIVE ROKEBERG clarified his point: it isn't specific to a particular project. He suggested the company would have to prove that expenditures which met the qualification under the statute occurred only [south of the Brooks Range]. MR. BARNES said it would be "project-derived" and that perhaps there would be a way to qualify what the 100 percent of expenses means. He suggested it is meant to represent costs directly applicable to that activity, rather than overhead for corporate offices and so forth. That wouldn't be the intent, he said. Number 1035 CHAIR KOHRING informed members that Mark Myers [director of the Division of Oil & Gas, DNR] and Chuck Logsdon [of the Department of Revenue] were available via teleconference to answer questions or offer technical expertise. Number 1012 PAUL RICHARDS, Lobbyist for VECO Corporation, testified in support of HB 61. He said: VECO believes efforts which incentivize exploration and development in Alaska are crucial to the long-term fiscal viability of this great state and the overall welfare of its citizens. VECO is a multi-national corporation that provides services - project management, engineering, procurement, construction, operations, and maintenance - to the energy, resource, and process ... industries [and] to the public sector. VECO's mission is to make our clients successful while creating stakeholder value and providing [a] safe and rewarding place to work. VECO is an Alaskan company founded in 1968 with their first project in Cook Inlet, and has built on existing Alaskan expertise to provide added value to its clients. The results are many long-term working partnerships, well-trained teams, and a network of regional offices around the world, which use integrated, state-of-the-art project management and communication systems to provide local solutions for the smallest to the large mega-projects. Values are important to VECO. They have built the corporation on several premises, which are the keys to our continuing success. VECO employees work every day to ensure that every job reflects those building stones. VECO strives to ensure that more Alaskans are given an opportunity for employment in Alaska. And with your help today in passing HB 61, this can continue to be a reality. Number 0880 MR. RICHARDS continued: This being said, VECO has reviewed the proposed legislation and [finds] HB 61 creates an incentive for operating companies to explore for and develop new sources of natural gas in Alaska, and particularly the Cook Inlet. What does this mean for VECO? Most importantly, it means new construction, maintenance, and operating jobs for our employees. It also means continued economic stimulus for local communities where employees live, work, and shop. As most of you recognize, Alaska's economy has a cycle of boom and bust. Unfortunately, all too often this cycle is driven by outside forces. VECO is strongly supportive of efforts by this legislature and the administration to create an environment where Alaska controls its own fate. Encouraging and incentivizing development through your support of HB 61 accomplishes this. It is particularly important to remember, this incentive applies ... only to successful efforts. For this incentive to be applicable, an operating company must have or acquire leases. It must then run seismic to identify exploration targets. Then it must drill one or more wells. If a discovery is made, production facilities must be installed, and potentially pipelines must be laid. This represents a lot of work - a lot of jobs for Alaskans. After the field is on production, it provides more jobs, royalty, and severance taxes. Finally, the incentive is only applied to state income tax, meaning the company is already making money in Alaska and supporting the state and its economy. This is all good news. The Cook Inlet natural gas business is an important part of Alaska's economy. It is important for local citizens who heat and light their homes through natural gas. It is important to those industries which use natural gas. VECO believes HB 61 can be important as well, and supports it. Number 0681 CHAIR KOHRING commended VECO Corporation for its Alaskan investment and optimism about the future. He said he supports this legislation as well, characterizing it as "win-win" legislation that will be good for the industry, the state, and the general public. The committee took an at-ease from 4:55 p.m. to 4:58 p.m. CHAIR KOHRING informed listeners that during the at-ease members had indicated the desire to hear more testimony from Mr. Myers or Mr. Logsdon, particularly with regard to royalties lost or gained. He announced that the committee would continue to take testimony and then hold the bill over. Number 0514 LARRY HOULE, General Manager, Alaska Support Industry Alliance ("Alliance"), informed members that the Alliance is a nonprofit, statewide trade association with chapters in Anchorage, Fairbanks, and Kenai. It comprises more than 420 member companies that derive their livelihood from Alaska's oil and gas industry; at any given time, its employment base exceeds 25,000 Alaskans. Specifying that the Alliance membership is fully supportive of HB 61, he suggested that in this time of fiscal uncertainty the state needs to promote as much exploration and development of oil and gas as possible. He said the incentive proposed in HB 61 seems especially suited for the mature Cook Inlet basin, which serves important gas market on the Kenai [Peninsula], in Anchorage, and in the Matanuska-Susitna area. He also suggested that passing legislation like HB 61 is a proper role for government. MR. HOULE offered that one outstanding feature of HB 61 is that the tax credits apply only to successful efforts. He suggested the bill will promote the drilling of new wells, and said in the oil industry it is a simple mathematical equation: "the more holes we drill, the more gas and oil that will be produced." Noting that state tax-incentive programs of this nature come in many shapes and sizes and are common throughout the country, he acknowledged that they vary in "quantifiable effectiveness." He said, however, that HB 61 seems to have the right combination to be workable in a mature basin like Cook Inlet. Referring to comments by Representative Rokeberg, Mr. House suggested it might be worthwhile for the legislature to explore incentive programs that include tax relief for low-volume, economically marginal wells or idle wells. He reiterated support for HB 61 on behalf of the 25,000 Alaskans represented by the Alliance. Number 0299 TADD OWENS, Executive Director, Resource Development Council (RDC), testified in support of HB 61 as follows: RDC supports House Bill 61, and we ask the House Oil and Gas Committee to move the legislation forward. HB 61 provides a tax credit for exploration and development of natural gas reserves and small oil deposits south of the Brooks Range. The legislation will have a major positive impact - specifically, on natural gas exploration and development in Cook Inlet. As the committee has already heard, this legislation is needed to help offset the continuing decline in Cook Inlet's proven natural gas reserves. At this time, reserves in Cook Inlet are not being replaced on an annual basis. In fact, rising natural gas prices in Cook Inlet threaten to greatly increase both the cost of living and the cost of doing business in Southcentral Alaska. As with all of Alaska's resource industries, Cook Inlet oil and gas projects compete for capital investment with other projects around the globe. HB 61 would stimulate additional exploration and development activity in Cook Inlet by leveling the playing field with other worldwide business opportunities. Attracting additional private-sector investment capital to Alaska is exactly what the state needs to encourage a market sustainable economy - one that relies primarily on growing our exports and replacing our imports, as opposed to one that depends on state and federal transfer payments and low-paying, low-skill jobs. The tax credit defined by HB 61 would apply, as you've heard, to 10 percent of a company's qualified capital investment and 100 percent of the expenses associated with that capital investment. However, in any given year the credit is capped at 50 percent of a company's corporate income tax liability. And, perhaps most importantly - and also as you've heard before - the credit will only apply to successful exploration and development projects, and no reward is granted to dry holes. By providing incentives for successful exploration and development, Cook Inlet natural gas reserves should increase, meaning additional royalty, severance, and ad valorem income to the State of Alaska. Increased natural gas reserves in Cook Inlet will also ensure an adequate supply for Southcentral communities, utilities, and industrial operations, meaning stable jobs and tax revenues for the region. Number 0069 MR. OWENS concluded his testimony as follows: The bottom line is this: current exploration activity in Cook Inlet is not sufficient to meet future demand for low-priced natural gas. House Bill 61 will help provide an attractive business environment for companies looking to increase leasing, drilling, and construction activities in Cook Inlet. Our members believe it is a timely piece of legislation, and we hope the committee will see fit to support the legislation. Number 0003 KEVIN TABLER, Manager of Land and Government Affairs, Union Oil Company of California (Unocal), began his testimony, indicating he holds the manager position for Unocal in Alaska. TAPE 03-12, SIDE A Number 0001 MR. TABLER, speaking in support of HB 61, expressed appreciation for consideration of the bill as a vehicle to stimulate gas exploration and development south of the Brooks Range. He told members: Although we recognize this bill may serve to improve the economics of marginal oil reservoirs discovered or defined while exploring for gas, it is the identification and development of new gas reserves in Cook Inlet which are needed if we are ... to sustain our local economy in Southcentral Alaska. Without ... new gas reserves, value-added businesses and industrial exporters will suffer cutbacks in production, yielding to the ever-present Southcentral utility needs. These disruptions in supply, if left unchecked, will lead to a lower tax base, unemployment and underemployment, and loss of the monetary cycling effect as dollars change hands throughout a community. I place an emphasis on Cook Inlet, as Cook Inlet is where Unocal's infrastructure base and manpower are best defined. Although we do have working interests in the fields on the North Slope, our ownership interest is such that we play a minor role in the exploration and development operations of these fields. While we recognize that incentives available to North Slope explorers and producers will have a beneficial impact on Unocal, the beneficial impact of incentive legislation in Cook Inlet is magnified when applied to the marginal nature of the mature fields and the declining gas-reserve base in Cook Inlet. For this reason, incentive legislation such as HB 61 will help achieve the desired effect of identifying new gas reserves by providing a predictable and quantifiable credit to help lessen the inherent risk of costly exploration. The increased tax revenue from additional hydrocarbon production will more than offset the initial financial impact from the tax credit. The objective is not to shift a larger share of an existing pie to industry; rather, the objective is to increase the size of the pie for everyone. Number 0215 MR. TABLER continued: For the last several years, Unocal has consolidated and restructured its Alaskan operations and focused on becoming the safest, lowest-cost producer in Cook Inlet. We have, either through purchase and/or exchange of properties, positioned ourselves to have the most cost-effective operation possible. The Cook Inlet, with its mature and declining fields, low margin properties, high operating costs, and regulatory uncertainty, is a very challenging environment in which to stay profitable, let alone risk ... capital. Cost cutting, in and of itself, is only a temporary fix. The only sustainable solution is to increase the reserve base. Unocal's considerable stake in its Cook Inlet infrastructure, manpower, and capital investments are continually threatened by internal global competition for investment dollars. Evidence of this vulnerability is confirmed by the recent drilling of three dry holes on the Kenai Peninsula in an effort to meet the growing demand of the natural gas market. Although we were rewarded by a discovery of the Ninilchik Unit with our partner Marathon, the expense, risk, and uncertainty of success has reduced our Alaskan capital budget from $70 million last year down to $35 million for 2003. Providing a credit for successful efforts will definitely improve the attractiveness of our Alaskan exploration projects. Number 0330 MR. TABLER continued: Not only will HB 61 create an incentive for companies currently active in gas exploration in Cook Inlet, the attractiveness of such a credit will act as an ... industry incentive to those thinking of investing in exploration south of the Brooks Range. If you think of the credit as costing the state $1 for every $10 invested by someone else, and paid out only in a success scenario, the risk to the State of Alaska is negligible when compared with the ancillary benefits of new reserve identification. In conclusion, we believe this bill will add certain attractive parameters to companies during the investment decision-making process, with very little exposure to the State of Alaska. Therefore, we encourage passage out of your committee. Number 0480 CHAIR KOHRING told Mr. Tabler he'd made some excellent points with which he concurred. He also thanked Mr. Myers and Mr. Logsdon for standing by on teleconference. He announced that HB 61 would be held over. ADJOURNMENT There being no further business before the committee, the House Special Committee on Oil and Gas meeting was adjourned at 5:10 p.m.

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