ALASKA STATE LEGISLATURE  SENATE RESOURCES STANDING COMMITTEE  March 10, 2010 3:33 p.m. MEMBERS PRESENT Senator Lesil McGuire, Co-Chair Senator Bill Wielechowski, Co-Chair Senator Charlie Huggins, Vice Chair Senator Hollis French Senator Bert Stedman Senator Gary Stevens Senator Thomas Wagoner MEMBERS ABSENT  All members present COMMITTEE CALENDAR  OVERVIEW: AGIA REGULATIONS - HEARD PREVIOUS COMMITTEE ACTION  No previous action to record WITNESS REGISTER MARCIA DAVIS, Deputy Commissioner Department of Revenue (DOR) Juneau, AK POSITION STATEMENT: Commented on AGIA regulations. FRED HAGEMEYER Black and Veatch Consultant to the Department of Revenue (DOR) Juneau, AK POSITION STATEMENT: Commented on AGIA regulations.   COMMISSIONER PATRICK GALVIN Department of Revenue (DOR) Juneau, AK POSITION STATEMENT: Commented on AGIA regulations.   ACTION NARRATIVE 3:33:50 PM CO-CHAIR BILL WIELECHOWSKI called the Senate Resources Standing Committee meeting to order at 3:33 p.m. Present at the call to order were Senators Wagoner, French and Wielechowski. ^Overview: AGIA Regulations Overview: AGIA Regulations    CO-CHAIR WIELECHOWSKI said the committee would take up an overview of the long-awaited AGIA regulations. COMMISSIONER Patrick Galvin, Alaska Department of Revenue (DOR), and Marcia Davis, Deputy Commissioner, Alaska Department of Revenue, introduced themselves. COMMISSIONER GALVIN said today they would deal with two different regulation packages that were put out by the DOR over the last month for public comment. They deal with the interrelationship between the ACES (Alaska's Clear and Equitable Share) production tax law and the AGIA (Alaska Gasline Inducement Act) open season. With the open season coming, he said they recognized that the AGIA tax inducement provides an opportunity to a company that would commit to acquire capacity at that open season to obtain a tax exemption. A tax exemption is for the difference between what the taxes are at the time they are actually producing and the taxes that are in effect at the commencement of the open season. So, the first part of their discussion would be about what they are referring to as the ACES regulations dealing with how gas is priced for tax purposes - how the destination value of the gas will be determined for production tax purposes and how transportations costs are deducted to get to a point of production value. 3:35:25 PM SENATOR BERT STEDMAN joined the committee. 3:36:52 PM COMMISSIONER GALVIN said those are needed to be in effect at the commencement of the open season in order to insure that the gas tax system was as comprehensive as possible before going into it. Another package of regulations deals with the tax inducement itself. One section deals with how to qualify and how the inducements would be used. 3:37:29 PM COMMISSIONER GALVIN started with the regulations for valuation and transportation deductions, which for gas are incredibly complex because of the nature of the natural gas markets. 3:38:22 PM SENATOR GARY STEVENS joined the committee. COMMISSIONER GALVIN said the Alaska Department of Natural Resources (DNR) has a similar task to determine a valuation methodology for its royalty purposes. Under the AGIA inducement associated with royalty they are actually offering a valuation methodology as part of the upstream inducement that is intended to provide more certainty and predictability for the producer in being able to anticipate what their gas valuation will be. He explained that the DOR tried to mirror as much as possible the DNR methodology so that it provides a more unified system from both taxpayer and department perspectives. It would make implementation easier for both departments because they could use each other's information and work off each other's thoughts in working through complexities. Today Commissioner Galvin said he would provide a broad overview on taxes from a structural standpoint and how some of their issues were resolved. SENATOR STEDMAN asked if the committee had a quorum to start. CO-CHAIR WIELECHOWSKI answered no; but they were not going to conduct any business. MARCIA DAVIS, Deputy Commissioner, Alaska Department of Revenue (DOR), started with a discussion of the over-arching principles that guided them in preparing the ACES regulations. She said that Fred Hagemeyer, Black and Veatch, and John Larson, Audit Master, DOR, were on line; they were both key in developing the regulations. The first principle was the department's duty to insure that full value is received by the state through its production tax laws from the natural gas production. In addition, she said, a lot of lessons were learned with having oil marketed valued for tax and royalty purposes, and they don't want to make the same mistakes with gas - things like the proper way to value oil using prevailing value and reasonable value - marketing was something at arm's' length, et cetera. They want to provide as much clarity as possible to industry. MS. DAVIS said they met with their DNR brethren to see what they had to do to value gas for royalty purposes and what the DOR did for tax purposes and tried to come up with a common approach so that industry could understand clearly if one value for gas was used for tax purposes, why another might be used for royalty purposes. While each department has its own statutory authority, she said they tried to be consistent where it was legally permissible. 3:43:27 PM MS. DAVIS said they benefited from having a common consultant who could understand and grasp their concepts and who could help the departments, hopefully, pick the best solutions for a particular problem. She explained that the DOR has a 25-30 year body of case law and a body of regulations on how to value things and principles on valuing things. So, what they did had to be consistent with past practices. She said they learned that the natural gas industry has a lot of unique differences in the way gas gets sold and marketed, how it moves across the nation and the system that is in place for handling gas and the types of processing that happens with it. Once oil leaves Alaska and hits the West Coast the state is not involved; it doesn't pay much attention to the downstream - like manufacturing into plastics and asphalt and things like that (slide 4). But gas tends to be marketed more in its constituent parts as well; so that they have to deal with the pieces of gas. Things get marketed and people pull stuff out and send it down. They have had a little bit of experience with that in oil, but not as much as is going to happen with gas. They needed to go to school on that and they got a lot of education. 3:45:13 PM MS. DAVIS said one thing they do know is that whatever regulations they set up for marketing for handling what the price of gas is and how it's going to be transported, they want them to be flexible. That is one thing they have learned from the oil regime. What you think is always going to be a price marker that will be there forever may not be. So, they built in flexibility to keep people from having to come in to see new regulations or changes in how things are done as often. They want some certainty about how "we will step out way through our decision tree when and if this particular bench mark is no longer available." In this way they hope to minimize litigation on transportation and administrative costs. 3:46:17 PM One thing they have realized with oil transportation is the availability of financial information. Within Alaska it is TAPS (Trans Alaska Pipeline System). Most people think information on that would be easily available, but she has learned otherwise as they struggled developing the oil transportation regulations. They wanted to ask the oil companies what their costs for transportation are, but Elkin's Law states that the pipeline can't share information with the shipper if they have their own subsidiary shipping as well. So, there is "an appalling lack of information flow" between a pipeline company and the people who ship on that line. She said the department had been struggling with how to obtain publicly available information that relates to the cost of shipping that a taxpayer can access and use readily in calculating their tax bill. So, they have "devolved" to using what gets reported on FERC reports or other reports that have to be filed from the prior year. Then that information is applied to this year. She remarked that this is just in Alaska where theoretically the DOR has subpoena power and could acquire the records, but those records couldn't be shared with the taxpayer. She mused that perhaps they could be posted as an aggregate. 3:48:33 PM MS. DAVIS said when they look at gas transportation costs they are looking at transportation that occurs mostly in Canada and the Lower 48 that is beyond the subpoena power of the DOR and certainly beyond the ability of the taxpayer to get information, because some of the transportation systems are unregulated. Gas's regulatory oversight is a little different than taxes with FERC. TAPS almost always has an adjudicated just and reasonable rate. With FERC and gas lines there is less scrutiny and you tend to just get approved. One of their concerns in drafting what costs can be deductible in the transportation regulations was to come up with a system that would insure the taxpayers could find the information necessary to make the deductions. Finally, she said gas is unique because of the system set up under AGIA the gas that gets transmitted via the commitment at the open season (versus subsequent open seasons) has benefits or non-benefits. Also, a lot of gas is co-mingled from different places, but they wanted to ensure that neither the state nor the shippers could game the system. She would not want the state to be able to pick the highest price gas with the lowest transportation cost and say it was from Alaska; and likewise they would not a taxpayer to do the reverse - pick the lowest price gas with the highest cost of transportation and tell Alaska that was their gas that got marketed. 3:50:46 PM CO-CHAIR LESIL MCGUIRE joined the committee. 3:50:53 PM So, Ms. Davis said they developed a pro-ration system that equitably allocates the pluses and the minuses of market pricing and transportation costs evenly across the board. The last over- arching principle is where the Legislature gave direction to look at rates set by FERC and to honor those as prima fascia evidence of a reasonable cost to deduct; they tried to carry that principle into the gas transportation regulations structures as well. 3:51:48 PM SENATOR HUGGINS joined the committee. 3:51:58 PM (Slide 6) MS. DAVIS explained that a taxpayer producer calculates its tax by first deriving the value of its gas at the point of production (POP) - the entry point to the pipeline after gas processing. This means the value at that place (think of a place on the North Slope) before it gets put into the gas treatment plant (GTP) and into the pipeline. SENATOR FRENCH asked exactly where the point of production for gas is. MS. DAVIS answered the POP for gas is downstream of gas processing and upstream of the gas treatment plant. She explained that the North Slope has gas processing essentially because the CGF and NGL is getting pulled out to reinject. Everything else would be left in that gas stream that they would want to market somewhere else. The purpose of the GTP is to make sure the gas is in a condition that it is safe to transport, which means that it doesn't have water in it to rust the pipe or CO that will hurt the valves. 2 CO-CHAIR WIELECHOWSKI inserted that they now have a full committee and that he had have been trying to set this hearing up for several weeks and then regs just came out. He asked Ms. Davis for a quick overview of timelines. MS. DAVIS responded that the regulations on transportation cost deductions and how the gas is valued for purposes of calculating tax were released about mid-February ago; they have a 30-day comment period. DNR regs are due approximately a week later with public comments due around March 22. 3:55:09 PM MS. DAVIS said for a taxpayer to calculate their taxes they take what they got for their gas or what the state tells them is a prevailing value and subtract the actual cost or, if the rules indicate, their reasonable cost of transportation, and end up with the gross value at the point of production. This is on the pivot point of deciding two things; the first is does a taxpayer get to use his actual sales price or does he have to use a prevailing sales price. The statutory direction to the department is to require the use of a prevailing sales price (that other people generally get) when that transaction is not arm's length or when it is suspiciously below market price. CO-CHAIR WIELECHOWSKI said that seems to give a huge amount of leeway, but was it to the producers or to the department. MS. DAVIS replied that the regulations define what an arm's length transaction is by essentially looking at who the seller and the buyer are and if there is a relationship between those two such that they would define them as being affiliates of the same entity. The definition of affiliate is if you have a 10 percent or more voting interest in who you sold to. 3:57:01 PM COMMISSIONER GALVIN mentioned if the price is between the prevailing value and the arm's length value the state would use the higher of those two to calculate the production tax. CO-CHAIR WIELECHOWSKI asked if prevailing price is Henry Hub price. MS. DAVIS answered that they have several choices for selecting a prevailing value. Transportation depends on if you ship on a transportation facility (which includes a GTP, the pipeline and anything downstream) and vessels; if it's not arm's length or with an affiliate the DOR would figure a reasonable cost of transportation calculation. 3:58:35 PM MS. DAVIS went back to explaining Gas Valuation (slide 8): When gas is delivered off the North Slope the value is based on the "higher of" the weighted average sales price of arm's length transactions (unassailable sale prices in the market) or the prevailing value at destination markets which is set by statute. She recalled that gas product that has to have a value assigned can be sold as it comes out of the ground without being touched. CO-CHAIR WIELECHOWSKI asked what happens if 1 bcf is sold at $6/mcf and then 3 bcf is sold at $7/mcf. MS. DAVIS answered that in those cases an average price per mcf is calculated and that is defined in regulations. You may sell your gas as stripped out so that all that's left is residue (residue gas is the methane you have left if you strip everything else out of Prudhoe gas). Utilities burn methane, so they value that. Gas plant products - ethane, propane, butane and NGLs - get stripped out and sold separately. Some people go through the extra process of freezing gas and selling it as LNG. So there are four different kinds of products and gas plant products have another whole range of products to keep track of. 4:00:18 PM (Slide 9) She assumed the actual sale price can't be used, so the department created a "first destination market" concept and used the first place where this gas went that had a very liquid market, one that has a lot of third-party transactions. She reminded them of the over-arching principles for dealing with Lower 48 pipelines and destination markets where five pipelines might be involved. Generally a liquid market will have posted prices and it's a place of certainty where everybody can figure out what the price of gas is at that liquid market. CO-CHAIR WIELECHOWSKI said Alberta has the ACCO market, but asked if the gas goes to Valdez what would the market be there. MS. DAVIS replied if it goes to Valdez she presumed they were talking about LNG and they would look at the daily volume of regasified LNG that is sold in arm's length transactions. A body of law already exists for establishing LNG value for taxing the plant in Nikiski; so they are pretty comfortable with developing a value for the gas for purposes of tax. Finally, if there are gas plant products, they would generally look at a place where both the residue gas and the gas plant products are being pulled out. They don't want to end up in some obscure place where all they do is pull out butanes for some unique process, because it's just not going to have a lot of third-party action. Their goal is to look for some place with lots of activity where they can have some confidence that the marketplace is functioning really well and that the market price that is being placed on these products is a "good solid one" that hasn't been manipulated either because of lack of supply, lack of demand, or parties knowing each other. 4:03:56 PM (Slide 10) The prevailing value (PV) for gas delivered to a market in Canada, the Lower 48 or foreign market is based on the total value of the component residue gas, Ms. Davis said. They will add up all the pieces that got stripped out and sold if that is what happens. SENATOR FRENCH asked it is the higher of all the choices. MS. DAVIS answered it would depend upon what the circumstances are. If the constituents aren't broken out, you use the weighted value. Slide 10 showed the hierarchy to establish the comparison. COMMISSIONER GALVIN said the "higher of" is the higher of between an individual tax payer's arm's length transactions and the prevailing value. In order to compare those two for an individual taxpayer, they have to determine what the prevailing value is at a particular location. If you can't find published prices, then they get a weighted average of all the sales they can collect to establish a prevailing value. If that's not available, they will look for government prices. SENATOR FRENCH said ultimately this would come down to a value judgment by somebody as to which of these applies and he wanted to know where that authority rests. MS. DAVIS explained that the department has charged itself with looking for published prices with established criteria. If they are unable to find published prices, by default they will have to drop down to the weighted average sale price. Again, it will be their obligation to report that number to the taxpayers so that they know what the weighted average sale of third-party transactions is. It has to come from a place with a lot of published third-part sales - like ACCO has, for instance. COMMISSIONER GALVIN said it is in the hands of the commissioner implementing the statutory requirements, but the selection is guided by the regulations with established fairly specific criteria upon which to base a determination. 4:07:56 PM (Slide 11) Ms. Davis said they obligate themselves to tell their taxpayers what they have determined qualifies as first destination markets - that means they will have determined it had sufficient volume, sufficient arm's length transactions, and had a publication that could be put out for public consumption. They would also list the name of the publication or what the source of the published price was so that they would be able to track it as well and be able to keep their records. Also, once you've picked the destination market, if there is clearly a location of quality differential - because something is being sold elsewhere and you need to shift the location - they would acknowledge what those are as well as quality differentials. Finally, reasonable gas treatment processing or regasification costs are allowed if applicable. When someone is marketing their gas plant products which means they have gone through all that cost to treat the gas - and if it's LNG, the cost to regasify - there are cost allowances for that. Those would be published because they are essentially set on a third party arm's length kind of weighted average figures. MS. DAVIS said people get confused because they are used to thinking about oil - to the point that when gas gets produced on the North Slope and gets processed through the central gas facility (CGF) and liquids are stripped out that are called natural gas liquids (NGL) statutorily they have said those are oil and they will be taxed as oil. However, those NGLs owe their source to both oil and gas down in the reservoir. She said the CGF has two parts. The primary part is the gas processing plant, the one that strips out the propane and the natural gas liquids. That is upstream of the point of production and gets deducted as a lease expenditure cost and qualifies for capital credits et cetera. What is left in that gas either gets diverted and sent back down hole or is available to be sent over to a pipeline. So when you think about it, the gas processing plant makes NGLs and its deductible, but in the gas world there are terms of art that conflict with that (slide 12). One of the things they had to bump up against when they started talking to experts is that they used the term "NGLs." The department thought they knew what that was, but they didn't because in the gas world, NGL is everything you can strip out of the gas (the propane, the butane, the NGLs, et cetera) leaving just the residue gas (methane). Also, because that can be done downstream, there are technically gas processing plants that can be located downstream. So, if somebody is selling their Prudhoe gas which might be rich in propanes and butanes, it can conceivably go to a plant down in Alberta for that processing. In Alberta or Kenai, for instance, these components of the gas can be stripped out in a plant that would also be considered a gas processing plant. But it's not a gas treatment plant by their definition, because it's not being done simply to make it transportable. The gas industry generally calls these NGLs. MS. DAVIS said they, therefore, had to define a thing called a "downstream gas processing plant," because it wasn't dealt with in prior statutes. It is essentially a gas processing plant that is downstream of the point of production. It, too, can extract NGLs. CO-CHAIR WIELECHOWSKI asked if you can have a gas processing plant anywhere else than on the North Slope under the defined term. MS. DAVIS responded that the term "gas processing plant" is the term that is defined in AS 43.55.900 and it is juxtaposed with gas treatment plant. The reason it was important to define those terms was for purposes of administering the production tax, they had to decide which part of the gas handling costs on the North Slope were going to be considered upstream of the point of production (gas processing plant) and what part of the costs were going to be determined to be downstream (gas treatment plant). 4:14:49 PM She explained there can be the processing of gas that occurs off of the North Slope and they had to come up with a word for that, because in the gas world a gas treatment plant is a meaningful term. The FERC regulates tariffs associated with gas treatment plants, but gas processing is not necessarily regulated. It's more of a manufacturing process that happens when gas flows through and has valuable components in it. So they couldn't call it a gas processing plant because that's defined as a specific type of plant that is located upstream of the point of the prodcution for tax purposes. So, they are now calling the thing that happens that involves gas processing when it's not on the North Slope (downstream) a "downstream gas plant." Developing terminology that helps keep their concepts clear and straight is one of the challenges they have encountered working through the regulation, she commented. MS. DAVIS said they hated hearing people call all the stuff they strip out of gas in the Lower 48 NGLs, because "we are so bred to think of NGLs as that product stream that we call oil that comes off the North Slope." So they came up with the term "gas plant products" and it includes all the stuff that can get stripped out of gas including NGLs while distinguish those things from what remains which is essentially a methane stream (residue gas). 4:16:45 PM MS. DAVIS said their statutes technically define "gas treatment," but don't define a "gas treatment plant." She said, "the nerds of us felt that lack and so we have put in that definitional term, also." SENATOR FRENCH asked where she expects to get push back from industry regarding the regulations. MS. DAVIS said she had to be careful, because they are in the 30-day comment period and would be providing written responses back. But they had a workshop on this portion of the regulations and questions were along the lines of trying to understand what the regulations were saying and what prevailing value was, and what it would mean to them in their world when they calculate their tax. They were trying to understand the concept of "first destination market," but they were also unclear why she was referring to the prior year's cost data. She was able to explain that it was done for their benefit to give them a reasonable chance of having access to the data. The Alaska Oil and Gas Association (AOGA) would submit comments soon that would give her a clearer picture of what their concerns are with the regulations. 4:19:10 PM MS. DAVIS said there is an allowance for a processing cost associated with a downstream gas plant, now that they all know what it is (slide 14). Clearly, if the department is going to ask somebody to pay their tax based on the value of a product that comes out of a plant, they need to have the right to deduct what the cost was to process it and get it to that point where it was marketable as that product. She said complexities of pro-rating are associated with somebody having multiple gas processing contracts. The same holds true for the allocation of cost for processing co-mingled streams, because in Alaska someday gas will come through the transportation system that is not taxed. It will be coming from federal offshore leases. There shouldn't be any cherry picking by the state or industry. Costs will be allocated fairly and evenly across all the streams. 4:20:57 PM She said industry has had a longer time to react to many of the provisions for the transportation deductions, because they have had four workshops on transportation deductions as they apply to oil costs. As a result of those workshops, they went through a lot of changes in their structure (slide 15). So that by the time they realized they had to get gas pipeline transportation costs fleshed out as well, they were able to fold that in with all the body of work they had up to that point in time for the oil transportation costs. The statutory direction to the department is for the gross value to use actual cost of transportation or the reasonable cost, whichever is lower. In addition, when the modifications made by ACES took place, the Legislature directed the department to make prima fascia (reasonable) any of the costs that were certified as just and reasonable by the FERC or the RCA. So, fortunately or unfortunately depending on perspective, actual costs are not necessarily reasonable costs. Accordingly, the department looks at reasonable costs as being different than actual costs when they have affiliated transactions (10 percent threshold for voting interest), are non-arm's length transactions, or are a transportation methodology that is not reasonable in view of existing market alternatives. These three criteria are set out in statute. CO-CHAIR WIELECHOWSKI asked if these regulations apply to just the gas pipeline. MS. DAVIS answered no, they apply to both oil and gas transportation, gas treatment plants, LNG plants, LNG regasification, vessels; all modes of transportation costs have a provision on arriving what the reasonable value will be if you can't rely upon the actual cost. There are some exceptions for the unique aspects of gas. CO-CHAIR WIELECHOWSKI asked if they would apply to both an AGIA gas line versus a non-AGIA gasline. MS. DAVIS answered that is correct. COMMISSIONER GALVIN added that most of what the regulations cover almost exclusively deal with gas. The one component that deals with oil and gas has to do with regard to the transportation deduction portion. CO-CHAIR WIELECHOWSKI asked if these regulations would apply to a bullet line from the North Slope or a spur line. MS. DAVIS answered yes; they have some instate provisions. CO-CHAIR WIELECHOWSKI asked Commissioner Galvin if he agreed with that. COMMISSIONER GALVIN replied that it gets complicated, because some of the valuations are different in Alaskan markets, but they didn't get into prevailing value and published prices and that sort of thing for the Alaskan market. He didn't want to mislead on the scope of application to an instate line, but the transportation deduction is relevant to an instate line, as well. 4:25:35 PM MS. DAVIS said they actually already have some transportation regs on the books, but those will be limited to when gas is marketed outside the state. She continued that when they ask themselves what reasonable costs are, the first choice are rates that are adjudicated as "just and reasonable" by the RCA or other regulatory body (as directed by the Legislature in ACES). A second that is added, because they learned that gas tariffs don't get the degree of "scrubbing down" that the TAPS tariffs seem to get (FERC does a lot of them and has an abbreviated methodology). FERC does not adjudicate gas tariffs as "just and reasonable;" instead they do an approval process. The FERC has determined they will honor in the spirit of the directions the Legislature gave them for the prima fascia "just and reasonable" the initial gas tariff rates that are approved by the FERC. These are the first ones that come out of the hat and the ones that get filed when someone is seeking issuance of their certificate of public convenience and necessity from FERC. It has a high degree of review, but not technically "just and reasonable adjudication." A third choice, she said is pipeline and gas treatment plant tariffs under settlement agreements to which the state is a party. She said this came up during their oil transportation deduction thought process; it didn't make much sense to the DOR that if the state entered into a settlement and said okay this is a good tariff and they want to accept it that they shouldn't at least give it that prima fascia nod that this should be considered reasonable. MS. DAVIS said they have acknowledged that each of these "sanctionings" of a tariff rate as being reasonable is limited in time. It can get stale. For instance, a tax rate that is adjudicated as "just and reasonable," is generally a very cumbersome process; and for someone to make the case they will gather their test data about what their costs and the rates of return were it usually takes about two years before that test data gets "sanctified" by FERC as being just and reasonable. So, they give whatever data they put in front of the FERC five years to be valid. At that point, they start to look at something else. The same with the initial gas tariff rates; they have said they will be good for at least three years. CO-CHAIR WIELECHOWSKI asked if settlement agreements were prima fascia evidence. MS. DAVIS replied that they are putting those in the same category as "adjudicated just and reasonable," but with conditions. It has to be a settlement agreement that the state is a party to, the settlement is cost-based (one that on its face is very similar to what FERC would administer allowing them to be depreciated, allowing a rate of return on capital - a normal settlement), and in addition in order for it to be "evergreen" or to let it ride, the state needs to have a reopener at least every two years to get out of it if it has become stale or anachronistic at that point. CO-CHAIR WIELECHOWSKI said he thought that was an excellent provision, because he remembered the state getting stuck with a really bad settlement agreement years ago that cost us billions. MS. DAVIS said yes; they have had an opportunity to learn from their experiences in the oil world. She said they are trying to be fair and balanced and want to have a policy that encouraged settlement. Litigation generally eats up everybody's dollars. Finally, if none of those three categories is available because the facts don't involve them, there is the "default method" or the methodology they have developed in the regulations that will establish the reasonable cost of service if it is not an arm's- length or third-party transaction. 4:31:29 PM She said it is a cost of service methodology (slide 19) in proposed regulation 15 AAC 55.197. It is modeled after the FERC and RCA methodologies where operating and maintenance expenses are allowed, economic life of the pipe is established, you depreciate all the capital only once (so if somebody sells it, it can't be depreciated all over again), you allow income tax deductions and allow a return on undepreciated capital. They have essentially tried to look at how the experts (FERC) have done it and used a similar rate of return which involves getting a proxy group. To the extent that FERC isn't involved (unregulated gas treatment plant or something else), they have selected Moody's All Industrial Users Baa rating (slide 20). 4:33:08 PM MS. DAVIS said that they have two examples; the first is a simple one of North Slope gas being delivered to Alberta and the other one, a more typical example where gas may be delivered to two places, Alberta and Chicago. They thought that walking through this example with Fred Hagemeyer, Black & Veatch, consultant for the Department of Revenue, would eliminate the pieces they had just gone through in terms of the global structure. FRED HAGEMEYER, Black & Veatch, said he would be happy to walk through example 1 on slide 21. This is intended to encapsulate many of the things Ms. Davis had been walking through but in a very simple way. Generally speaking, it starts with production of 91 mcf, which converts to 100 mmbtu, and will be used most for the valuations after it leaves the point of production. It will go down through the gas treatment plant, move down through transportation facilities (which can be more than one); in this case the destination is a processing facility in Alberta. There you would determine a value whether it be through the processes that were described by Ms. Davis in terms of an actual value or prevailing value based upon indicators. It turns out that Alberta has a fairly liquid market, particularly for ACCO, for residual gas and gas product at Edmonton. The way the example is set up, they would start at the bottom at destination value and use 90 mmbtu of residue gas. He mentioned that the example did not show the gas that would normally be used as fuel at various stages of the transportation or treatment. The gas plant products - components of ethane, propane, butane, and any tanes - would be extracted and collectively have a 200-gallon volume. The residue gas would be sold at $6/mmbtu which is the prevailing price in the ACCO market in this case. This translates over to an absolute dollar value of $.50/gallon. At that point the destination value is $640 total. Moving up to a number of allowances in terms of deductions, one of them would be the processing costs in the Alberta market. In this case, they have an inlet volume of 100 mmbtu and as that got extracted out it ended up as 90 mmbtu of residue gas, and gas plant products which are measured in gallons at that point. Then usually in the case of a gas processing facility there can be a number of ways to contract but it can be converted to dollars per mmbtu for a cost factor - in this case it's $.20. That's a deduction and as you move back up you also have an allowance for transportation, which is usually a fairly significant portion. In this example they had 100 mmbtu for volume coming down the Alaska Pipeline for both the Alaska and the Canadian segments and they used $3/mmbtu cost. In the Alberta system the cost rate is $.10 to get to the processing plant or the ACCO market. Then as you move back up, you have the gas treatment plant expenses (using the total volume of 100 mmbtu in this case) and a $1 for the throughput rate. As you subtract those elements, you end up with a total value at the point of production of $210. 4:39:30 PM MR. HAGEMEYER moved to example 2 on slide 22 that is very much the same except that in this example they come down the Alaska main line and at a point just north of the Alberta market half of the gas volume goes down the Alliance Pipeline System to Chicago. This example presumes that there is an interconnection of Alliance into the Alaska main line at some point before it enters the Alberta system. The 91 mcf converted to 100 mmbtu goes through the gas treatment plant; it goes down the Alaska main line through both the Alaskan and Canadian segments, splits off into the Alberta and Chicago markets. Those become two destination markets and would be identified as being liquid destination markets and both would have residue gas prices as well as gas products prices. At the bottom of the example at the Chicago market the residue gas volume of 45/mmbtu and 100 gallons of gas plant products has a value of $.60 on average and equaling $60 - 45/mmbtu X $6.75 mmbtu has a value of $303. So, you have a total value of $363 at that destination. The same process just above it in yellow happens in Alberta where it has a $6 ACCO price against a 45/mmbtu and 100 gallons of gas plant products that have been extracted into constituent parts with an average of $.50 per gallon. Those add up to $320. The deduction for processing in Chicago is $.20, and $.25 in Alberta. Moving up the example they also see the TAPS still at $3 for the total volume of 100/mmbtu (fuel line loss is not shown). The Alberta system has a $.10 for half the volume at that point. The Alliance Pipeline shows a $1/mmbtu cost; you also have the 100 mmbtu X the $1 GTP cost. Eventually you end up with $2.06, and in this case having to split the volumes you come back with $2.06 for that month as the value at point of production. 4:42:53 PM CO-CHAIR WIELECHOWSKI asked if the Alliance Pipeline runs from Alberta to Chicago. MR. HAGEMEYER answered yes. It originates in Alberta and actually truncates in Chicago to an area west of Chicago into a very large gas plant facility. 4:43:15 PM COMMISSIONER GALVIN said he wanted to make sure they were clear that it looks like going to Chicago results in a $43.75 "uplift" in terms of actual destination value, but when you deduct the differential cost to get to Chicago from Alberta, it appears to be about $47.50. He asked given what they described earlier about prevailing first destination value that in this particular instance the destination value in Chicago turned out to be less than the destination value in Alberta, would there be a use of the Alberta price or would they be able to get the lower point of production value by going to Chicago. MR. HAGEMEYER answered in this example if Chicago is determined to be a destination value then it's felt to be a liquid market for all the considerations they talked about. The fact that Chicago has a slightly lower cost for transportation to get there coming from the end of the Alaska main line just happens to be the situation that month. It would not change the process whereby you would look at Chicago because it's been determined to be the destination value at that point assuming that the residue gas price is utilized in the destination value determination. 4:45:42 PM COMMISSIONER GALVIN said if there is a situation where other gas than Alaska gas goes to Chicago and Alberta, would that gas have to be prorated. MR. HAGEMEYER answered yes. This example does not go into the fact that very possibly the particular shipper will have other gas associated with this gas. So the contract that they may be selling to in Chicago, for example, could have a number of other streams. 4:46:43 PM COMMISSIONER GALVIN moved on to the section dealing specifically with the AGIA inducement regulations (slide 23). The package is referred to as the ACES regulations dealing with valuation of transportation and they went out for notice on February 9. There was a public hearing on March 3, and the comment period closes on March 15. The section they are moving into now with the AGIA regulations were noticed on February 19 and the public hearing was yesterday, March 9; comments are due on those by March 22. 4:48:03 PM In order to understand the qualification for the AGIA inducements for both royalty and tax inducements, the requirements are basically shared between the commissioners of DOR and DNR; so the application is done jointly. In order to handle this in the regulatory process because the state has two different inducements, one in the royalty section of regulations and one in the tax section, they have two identical descriptions of how one qualifies in the two different sections of the regs. Commissioner Galvin said he would be describing the sections within the tax inducement portion. He said the sequence of events is that the inducement is available to shippers who commit to acquire firm capacity in the initial open season of the AGIA pipeline. A distinction will be made between shippers who are producers and shippers who acquire capacity who aren't a producer. In which case those shippers would acquire a voucher for this inducement and pass it on to the shipper for their tax and royalty benefit and presumably get some compensation for that when they make their purchase of the gas. In order to identify what shippers qualify for this inducement they had to look at the transaction that took place between the pipeline company and the shipper in order to determine who would ultimately qualify for it. So, they had to define a couple terms. The first one is a precedent agreement (PA), which is the agreement that will emerge from the initial open season transaction between the shipper and the pipeline company. It will establish the general terms of transportation service that the shipper will be obligated to acquire if they ultimately reach the actual agreement to transport the gas which is referred to as a transportation services agreement (TSA). That agreement isn't going to be reached until they get down to sanctioning decisions on the pipeline - you have to get your FERC certificate, your financing and other things. SENATOR FRENCH asked if these are standard industry terms. COMMISSIONER GALVIN answered yes. The PA will also identify the conditions that will have to be met in order for the shipper to be obligated to enter into a TSA. As part of the open season process the pipeline will set out what they are offering as part of the PA and identify the things they expect the shipper to agree to and the conditions upon which they could place and open it up to additional conditions that could be placed during the open season. Those would have to be negotiated after the open season to result in a PA that actually identifies that if these things are met, then you will go to a TSA and that is then the unconditional obligation to pay the firm transportation (FT) costs. 4:54:54 PM The sequence to qualify for the AGIA inducements you have to apply and demonstrate that you have met the qualification requirements, and then separately you are eligible for the royalty inducement which has certain additional requirements in terms of having to agree to change your leases and other things that are unique to the royalty inducement; and you also separately have the tax inducement available through the regulations that he will describe shortly. So, to be considered qualified you have to commit to acquire FT capacity in the first binding open season. The regs say that in order to be considered to have committed to acquire FT capacity in the binding open season you have to do each of the following: submit a bid for FT capacity during the initial open season, you have to execute a PA within 180 days after the close of the initial open season, you have to ultimately execute a TSA within five years of the open season or two years following FERC certification whichever is later (those dates align with the sanctioning requirements of the AGIA statute), and you have to file your paperwork and copies of the documents, and demonstrate that you have actually done these things to the commissioners. SENATOR FRENCH posed a simple hypothetical: open season happens on May 1, a company (Exxon) wants 1.5 bcf/day in the pipeline, they submit a bid, they execute a PA with the Alaska Pipeline Project (subsidiary of TransCanada), and in that they say they would give them 1.5bcf/day but the only condition is they want $.05/mcf tax. Is that the kind of condition he meant? COMMISSIONER GALVIN answered there could be a whole suite of conditions that could deal most directly with what has to be done with the pipeline project in order for the shipper to be obligated to enter into a TSA, but there also could be conditions that are external to the relationship between the two, but they would have to be conditions that basically the pipeline company is willing to have in their PA if they want the project to go forward. SENATOR FRENCH asked if TransCanada could conceivably reject a condition. COMMISSIONER GALVIN answered yes. SENATOR FRENCH said assuming there are 10 commercial conditions and one sort of external one could they agree to go forward with that external condition embedded in their PA and hope that it will somehow get resolved in time for them to execute a TSA. COMMISSIONER GALVIN answered yes. He noted that a big part of what is happening in the negotiation of the PA is also who is ultimately responsible for the development costs of getting from that point in the process to the next big flag in moving to a TSA; and if the project ends up not going forward at that ultimate point, who is going to pay for those things. The conditions are on there as much to provide clarity for that part of the relationship as well. SENATOR FRENCH said it's a fairly complex commercial contract negotiation between two sophisticate parties. COMMISSIONER GALVIN said, "That's putting it lightly." CO-CHAIR WIELECHOWSKI asked him to turn to slide 25 where it says a PA "establishes general terms of transportation service under which a shipper will be obligated to acquire FT capacity." Do you have some sort of definition of "general terms?" Would a producer who agrees to put their 1.5 bcf in the pipeline assuming they can get fiscal certainty from the state satisfy the "general term" requirement of PAs? COMMISSIONER GALVIN answered that this language is not taken directly from the proposed regs. That sentence is intended to capture not the conditions he just described but the actual tariff terms or the general methodology for determining what the tariff is going to be and how costs are going to be recovered. An example is just the open season plan that was submitted by the Alaska Pipeline Project generated 72 pages of comments from BP on the tariff terms being offered. One of the issues they raised was in the winter pipeline capacity increases because of the temperature. 5:03:09 PM CO-CHAIR WIELECHOWSKI asked if someone agreed to put gas in the pipeline if they get fiscal certainty or some term like that, would they be able to get a PA under the regulations. COMMISSIONER GALVIN answered potentially if their condition is specified in a way that is acceptable to the Alaska Pipeline Project for the purposes of their relationship. If they are on a go-forward basis with a project on the basis of that particular condition and it is sufficient for them to feel like the development costs and the risks of going forward are properly allocated between the parties, based on that condition. 5:04:05 PM CO-CHAIR WIELECHOWSKI said they are running a little late but have a few more things to cover. They would be back tomorrow and next week for the DNR regs. He found no final questions from committee members; therefore, he adjourned the meeting at 5:04 p.m.