SB3001-APPROVING AGIA LICENSE  HB3001-APPROVING AGIA LICENSE  10:03:09 AM CHAIR HUGGINS brought SB 3001 and HB 3001 before the committees for consideration. SENATOR GREEN, President of the Senate, noted the new Senate Special Committee on Energy consists of members of the Senate Resources Standing Committee and the Senate Finance Committee. During these joint meetings Senator Huggins would chair. REPRESENTATIVE HARRIS, Speaker of the House, explained that he, Representative Samuels, Representative Kerttula, and Representative Coghill, chair of the House Rules Standing Committee, were representing the House Special Subcommittee on AGIA, the Alaska Gasline Inducement Act. CHAIR HUGGINS announced that Representative Samuels, who chairs the Legislative Budget & Audit Committee (LB&A or BUD), would be the facilitator today. REPRESENTATIVE SAMUELS informed members that three consultants - Barry Pulliam, Lesa Adair, and Dan Dickinson - would give presentations today and tomorrow, followed by a roundtable discussion. He introduced the others: William Mogel, a Federal Energy Regulatory Commission (FERC) attorney, and Dr. John Neri, who was tasked with the ins and outs of rate making. He said letters went out under his signature to TransCanada and the administration that he didn't personally write; a lot of technical information and questions came from Dr. Neri. REPRESENTATIVE SAMUELS noted he has tried to stay at arm's length from the consultants. Questions have been relayed from the legislature and other consultants, and the LB&A consultants were asked to review certain subjects. He encouraged questions during their presentations. 10:09:36 AM ^LB&A Consultants Barry Pulliam, Lesa Adair, William Mogel, Dr. John Neri, Dan Dickinson BARRY PULLIAM, Senior Economist, Econ One Research, gave his background, saying he has worked on oil and natural gas for 20 years. In some capacity, he has worked for or with the State of Alaska for most of that time on behalf of the administration and the legislature, dealing with issues such as taxes, a gas line, and royalties. He also works with other states; has worked with the federal government on energy matters; and has worked for private companies including producers, refiners, and pipelines. MR. PULLIAM began his PowerPoint presentation titled "Comments to Legislature on TransCanada Proposal"; a handout duplicated the slides. He noted he would discuss the proposed tariffs and the related cost structure, implications, and sensitivities surrounding the assumptions. This would provide a foundation when considering the presentations to follow. MR. PULLIAM paraphrased slide 1, which was labeled "What Does TransCanada Propose to Do?" and had the following points: - Construct and operate 1,700-mile, 48-inch pipeline from North Slope to Alberta, with initial capacity of 4.5 bcf/day, expandable to 5.9 bcf/day with addition of compression - Conditioned on receiving sufficient firm transportation commitments - Pipeline would terminate at Boundary Lake on the British Columbia/Alberta border, where it would enter the "AECO Hub" - At AECO, shippers would arrange for extraction of valuable NGLs (either from third parties or through construction of own facilities). "Residue" gas could be sold either in Canada or shipped to Lower 48. - Construct and operate necessary Gas Treatment Plant ("GTP"), if not undertaken by another party - Provide pipeline access for LNG facility if demand warrants MR. PULLIAM said while the pipeline ultimately would be expandable to over 7 billion cubic feet a day (Bcf/day), initially it would be expandable to about 5.9 Bcf/day just through compression. The AECO Hub is an interconnection of pipelines, a center for market activity and price formation that is one of the most active trading areas in North America. REPRESENTATIVE SAMUELS added that the AECO Hub isn't a single spot, but involves the entire province of Alberta. 10:14:34 AM REPRESENTATIVE GARDNER asked: Is there adequate infrastructure now to ship gas from AECO to Chicago if that is the market? MR. PULLIAM replied while it might not exist today, most folks anticipate sufficient infrastructure to move the gas away from Alberta by the time gas comes on line, in 10 years or so. There might need to be some expansion of existing lines, but it's unlikely that there'd need to be a new line built to take all this gas to the Lower 48. Ms. Adair would speak to that later. MR. PULLIAM continued with slide 1, saying as the gas moves down the pipeline it contains natural gas liquids (NGLs) that will be extracted, most likely at AECO, where the NGL-extraction capacity is anticipated to be sufficient to handle gas from Alaska. He believes those NGLs will have significant value for producers, shippers, and the State of Alaska. After extraction, the "residue" gas that's left could be sold in Canada or shipped to the Lower 48. 10:16:48 AM REPRESENTATIVE GUTTENBERG asked whether TransCanada assumes the NGLs would be shipped or whether provisions allow those to be extracted within Alaska. MR. PULLIAM replied he believes the assumption is that the liquids would be shipped with the gas. While he didn't know of any prohibition on in-state extraction, in large part the infrastructure and capacity already exist in Alberta for that. It may be the most efficient to extract NGLs in Alberta to get the highest value for the state. REPRESENTATIVE GUTTENBERG asked: Once the NGLs get to AECO, does a different authority control it or is it under the shippers' contract? MR. PULLIAM answered there are issues at AECO as to how NGL- extraction rights are allocated. As the gas enters the pipeline in Alaska and all the way down to AECO, the NGLs belong to the shippers; it is up to them either to negotiate with folks who have extraction facilities in AECO or to potentially build a facility there themselves to extract the NGLs. REPRESENTATIVE GUTTENBERG surmised there'd be no conflict in taking the NGLs from Alberta into the Lower 48. MR. PULLIAM gave his understanding that shippers bringing gas into AECO typically don't move NGLs further; they sell extraction rights in AECO and then the owners of the plants are responsible for further shipping. It doesn't mean it couldn't be done differently, through negotiation, keeping the NGLs and shipping them. But it may make more sense to have someone else do the extraction in AECO and then have that entity pay for the value of those NGLs. REPRESENTATIVE SAMUELS asked: What percentage of the Prudhoe Bay gas is NGLs, and if those are taken in Alaska or in AECO, how much gas would be lost? And would it affect the financing because the throughput would have dropped? 10:19:50 AM MR. PULLIAM answered it is a relatively small percentage. The question is where to get the most value. If NGLs are taken out of Alaska, they must be moved to markets that consume and pay for them. If NGLs are extracted in Alaska, the quantity is more than could be used today in Alaska; they'd have to be moved out of state in some form, requiring a pipeline and/or marine transportation. The expense would likely be greater than if the NGLs traveled in the pipe and then were extracted in Alberta. MR. PULLIAM, in further response with respect to pulling out propane at the Yukon River, opined that some NGLs could be extracted for local uses without causing problems down the line. The gas would have to be measured as it gets to Canada to determine its composition. If propane is pulled out in Alaska, some value will be pulled out; propane has a higher value on average than the stream, which is mostly methane. Any amount taken in Alaska for local use wouldn't likely damage the economics associated with moving the gas to Alberta and doing extraction there. REPRESENTATIVE SAMUELS surmised Alaskans would use a relatively small amount of propane. He asked if a small enough plant could be built to make it economical to drop some propane at the Yukon River in order to help get energy to those living in Western Alaska, knowing there'll be a transportation cost. MR. PULLIAM deferred to Ms. Adair. 10:23:05 AM LESA ADAIR, Muse Stancil, indicated her company worked for LB&A previously on this issue of in-state use. She said it boils down the value of propane in Alaska relative to other places. The capital cost of building a plant to extract liquids is more driven by how much gas must be processed to extract the propane, rather than the amount of propane that comes out. MS. ADAIR noted the plant has to be big enough to handle enough gas to extract the propane. Those economics can work if someone is importing propane or hauling it a long distance. For instance, they'd looked at a couple of plants in northwestern Alberta where bottled gas is highly profitable because the product is imported today. She gave her feeling that it could work, but said the economics hadn't been run on that case. CHAIR HUGGINS highlighted in-state jobs that this industry will create instead of just exporting raw resources. REPRESENTATIVE DOOGAN gave his understanding that the business about NGL offtake is an economic assumption, rather than a term of the agreement that the legislature is being asked to approve. MR. PULLIAM affirmed that. REPRESENTATIVE DOOGAN requested that such instances be clarified during the presentation. 10:25:31 AM REPRESENTATIVE NEUMAN referred to the phrase "extraction of valuable NGLs" on slide 1. He surmised if TransCanada builds a pipeline, that will be a decision among the producers, TransCanada, and any industry that might be attracted by Alaska to come build a plant to process NGLS; nothing in AGIA covers it or says the NGLs will be shipped outside, and so it leaves open the possibility for value-added products to be produced in Alaska within this process. MR. PULLIAM relayed his understanding that nothing in AGIA requires NGLs to be extracted at one place or another. Before the gas can be used in residential or industrial markets, NGLs will be extracted; they have value. He opined that the owners of the NGLs would make a commercial decision as to where the highest value is. REPRESENTATIVE NEUMAN asked: If the state could attract someone to build a processing plant to extract butanes, propanes, and so on - either for use in Alaska or to export - is there any hammer so the state can have first-access rights to those NGLs? MR. PULLIAM replied he wasn't aware of any, though it was a little outside his field. 10:27:39 AM SENATOR WAGONER asked if building a plant to extract propanes and ethanes in Southcentral Alaska makes it more economically feasible. Surmising the tariff would likely be lower than to Alberta, he suggested if a spur line brings natural gas/methane into Southcentral anyway, it could ride in the same line with propanes that aren't used in the Yukon. MR. PULLIAM replied he hadn't modeled that scenario. He gave his sense that for the volume discussed, the pipe would be much smaller that carries ethane or ethane and propane; there'd be relatively high fixed costs over which to spread that smaller volume. Also, once extracted in Alaska, it has to be turned into a finished product, either for Alaskan consumption - some of which can be done with propane - or else for export, the case with ethane now. One must add up all associated shipping costs to see how it stacks up. Given likely economies of scale, it probably isn't as good from a netback-value standpoint. MS. ADAIR agreed that was probably right. For downstream users, particularly for ethane, one issue is that most plants competing economically today are world-scale, huge facilities. Facilities in Alberta today will need those ethanes. Mentioning sunk costs, established markets, and takeaway capacity, she predicted it would be costly to compete. She opined that an economic analysis would show it is more cost-effective if those go to Alberta to existing markets. MS. ADAIR indicated there'll likely be a need to process gas used in Alaska. Commercial economics must be analyzed for recovering ethane or letting it be sold as natural gas, which happens on the U.S. Gulf Coast, depending on relative prices for those. MS. ADAIR also mentioned bottled gas markets locally for propane; suggested butanes and pentanes can be used for gasoline blending in Alaska; and said liquids can be spiked back into the pipeline, for example, if there isn't a market in the Yukon for some of those heavier liquids. She said it's more efficient to move everything under one system than to build multiple systems to transport products. SENATOR THOMAS asked: Right now, what is the best use of that gas economically? Would it be used in the tar sands, for example, or go to the Midwest for heating and power generation? MR. PULLIAM replied if it comes down the pipeline into Alberta, it may be used in a combination of ways, locally in Alberta in the tar sands and also moving into the Lower 48. Physically, it will increase the Western Canada gas supply, which has been declining; that supply is used in Canada and the surplus is exported to the Lower 48. Effectively, Alaska's gas will be exported to the Lower 48; the economics will be a Lower 48 netback. Physically, a lot of it may be used in Canada. 10:33:32 AM REPRESENTATIVE SAMUELS asked if on pure economics, maximizing value to its shareholders, TransCanada doesn't care if NGLs are taken off in AECO or shipped to Chicago, but if some is taken at the Yukon River there'll be a little less gas and thus a slightly higher tariff per unit. MR. PULLIAM replied he believes it largely is accurate that TransCanada doesn't have an interest in gas processing or NGL extraction, which will be performed by somebody else; it isn't a service that company provides now. Agreeing that if the NGLs were extracted in Alaska the volumes would decline a little, he pointed out that they'd have to come from another source, either through quicker production or gas coming from other fields. REPRESENTATIVE SAMUELS requested confirmation that the TransCanada proposal has an in-state tariff which would apply to propane dropped out at the river and that a little would be saved on the tariff, since it wouldn't be the Alberta tariff. MR. PULLIAM affirmed that. 10:35:35 AM CHAIR HUGGINS asked if anything in AGIA or in TransCanada's proposal modifies the state's flexibility with respect to its royalty share. MR. PULLIAM replied not that he was aware of. Returning to the slide, he noted TransCanada proposes to construct and operate a gas treatment plant (GTP) if that isn't undertaken by another party. He said it seems fairly clear in the proposal that TransCanada's preference is for someone else to do that. 10:36:30 AM REPRESENTATIVE GARDNER asked how access pricing and processing costs are calculated, whether that is regulated, and if there is any way it could impede new explorers wanting to get into the GTP. She also asked who owns the gas. MR. PULLIAM answered first about GTP access. He said TransCanada's proposal envisions the GTP as a regulated facility. There'd be a regulated cost-of-service tariff, although there may be issues, depending on who builds it, as to how that regulation is applied. Noting this is outside his field and deals with FERC policies, he surmised it would be a regulated facility if integrated with the pipe, but he wasn't sure what access issues would exist if it were built by the producers and operated separately. MR. PULLIAM highlighted the importance of considering this, since the GTP is integral to getting the gas to market. If exploration is a key activity to encourage, he said, then being able to get gas into the GTP or to expand the GTP in some way will be important. MR. PULLIAM turned to who owns the gas, saying that is a legal question best answered by one of the state's attorneys; he is an economist. He offered his lay understanding that the gas has been leased to the producers, which have ownership rights to it. The state gets a royalty portion and also has sovereign capacity and the ability to tax the gas as it is extracted. REPRESENTATIVE SAMUELS advised members that tomorrow the question involving the GTP would be addressed during the roundtable discussion. He said the point of AGIA is to ensure access. If the GTP is a bottleneck, he surmised FERC will get involved. He posed a scenario in which an expansion would drive the tariff up and he owned the GTP at Prudhoe Bay; he asked why he would expand it, costing him more with respect to the tariff. 10:41:12 AM SENATOR THERRIAULT told members last week he was surprised to hear that Asian gas systems burn a higher-Btu-content gas. Selling into that market and getting the higher price requires that blend, and Alaska's gas stream is right about at what they need. If that happens, there'd be no ability to strip out large quantities of gas liquids either to sell to a separate market or to use in Alaska. He asked if Mr. Pulliam agreed. MR. PULLIAM concurred, saying if gas is to be sent to the Far East in the form of liquefied natural gas (LNG), it will be for industrial uses. They can handle gas that is relatively rich, with the NGLs still in it, and contracts are typically written for a relatively rich stream. Assuming that Alaska's gas is exported to the Far East in conformity with how it's typically done there, it would mean relatively few NGLs taken out of the gas before it's shipped. MR. PULLIAM pointed out in North America it works differently. For safety reasons, NGLs need to be stripped out before the gas is used commercially for industrial or residential purposes. Also, NGLs have tremendous value in today's market and future projections. They have to be stripped out if they stay in North America, which involves a separate sale. If the gas is sent to the Far East under the kind of terms in place now, a relatively small amount of NGLs could be taken out prior to that. 10:44:34 AM REPRESENTATIVE JOULE recalled hearing for a long time how hungry the country is for Alaska's gas. He asked: If some of this gas will be used in the tar sands and some in the Canadian market, how much will really be used in the Lower 48? Also, he said part of the argument against an all-Alaska gas pipeline to get to the Asian market is that the congressional delegation will be upset. He noted this gets into a larger political arena. MR. PULLIAM responded that the gas would be sent via pipeline to Alberta, where it would connect with an existing system taking gas to the U.S. In Alberta, all that gas gets comingled. A particular molecule cannot be attributed to Alaska or Canada physically, although it can be through accounting. MR. PULLIAM said today Western Canada exports gas to the U.S. If Alaska's gas connects into that, it increases the supply there and effectively pushes the gas into the U.S. As long as Canada exports more than 4.5 Bcf/day, the addition of Alaska's gas effectively moves it into the Lower 48, in his opinion, since if Alaska's physical gas is used in Canada, it pushes Canadian gas into the Lower 48. REPRESENTATIVE LeDOUX asked: How do we know Canada would continue to export gas to the U.S. if there were a gas shortage in Canada? MR. PULLIAM surmised if Canadian production got so low that there wasn't anything left to export, the gas would be used there. However, all projections he's seen show Canada exporting gas for a long time, although those exports are declining as production in Canada has declined and usage there has risen. MR. PULLIAM added that the Canadian and U.S. markets for gas are tied together as one larger market; that's different from elsewhere in the world today. They are tied by an extensive system of pipelines that have operated for some time to move gas from Canada into the U.S. That is expected to continue for the foreseeable future. MS. ADAIR noted her presentation would address some of this. REPRESENTATIVE SAMUELS remarked that setting aside political concerns - including federal loan guarantees and what Congress thinks - if Alaska sold its gas to the tar sands and got the best price there because of not having to pay the tariff to Chicago, the state wouldn't care economically. MR. PULLIAM replied he thought that was correct. To the extent the federal government allows Alaska to do what it wants with the gas, seeking the highest netback makes sense. As a practical and economic matter, if the gas connects into a grid in Canada, it effectively moves gas into the Lower 48, regardless of whether it's the same physical gas. He gave his understanding from discussions with the U.S. Department of Energy (DOE) and others in the federal government that they'd view it the same way - not as an export to Canada, but as facilitating the movement of more gas into the U.S. 10:51:38 AM SENATOR THERRIAULT emphasized that the shorter the distance, the higher the netback to the state. If Alaska can sell to a closer market, it's advantageous in the long term. He requested to hear at some point about the original congressional language or the treaty between the U.S. and Canada as far as anticipating where the gas would ultimately be delivered and whether there is a commitment or requirement that a certain number of molecules make it across the border. REPRESENTATIVE SAMUELS replied if they cannot get the answer in the next two days, they'll task somebody with getting it during the special session. It is a good point as to whether Congress requires the gas to get to the U.S.; some rules for the $18 billion in loan guarantees haven't been written yet. REPRESENTATIVE SAMUELS emphasized that TransCanada's proposal has suggestions, not requirements, on how the company would structure those; it will depend on Congress. Although some won't be answerable, there can be research on what has been done so far and whether rules say certain molecules or a certain amount of extra gas must go somewhere in particular and not end up in Canada's tar sands. 10:53:12 AM MR. PULLIAM turned to the last point on slide 1, saying TransCanada proposes to provide pipeline access for an LNG facility if demand warrants - if, when an open season is held, there is sufficient demand for a pipeline into Southcentral Alaska or Valdez to build an LNG facility. REPRESENTATIVE SAMUELS suggested saving the following for the roundtable discussion, since FERC and rate making would be involved. He posed a scenario with an open season in which somebody bids 2 Bcf/day for LNG, which wouldn't leave enough gas to build the across-Canada pipeline. He asked who would determine in the open season which bid to take. MR. PULLIAM answered in part, saying if there were an open season with such demand for in-state use, he believes it would cause TransCanada to look at whether it would build the rest of the line or what makes the most sense. Typically, a company would rank commitments in terms of the present value of those in an open season and then allocate them based on what gives the highest value overall. REPRESENTATIVE SAMUELS asked who would have that say - the state, the federal government, or the pipeline company. MR. PULLIAM gave his sense that it's a process the pipeline company would go through. 10:56:32 AM MR. PULLIAM paraphrased slide 2, the second on what TransCanada proposes to do, which said: Offer tariffs reflecting: - 20, 25 and 30 year firm transportation commitments - Recourse and Negotiated Rates (Alaska); Negotiated Rates (Canada) - Capital Structure of 70% debt/30% equity (recourse), 75% debt/25% equity (negotiated) - Equity return floating at 965 basis points above 10- year T-bonds - 100% cost recovery (3.5 MMBtu/day and above) MR. PULLIAM added that TransCanada proposes two types of tariffs: 1) a recourse rate, a traditional cost-of-service rate that is required by AGIA, and 2) a negotiated rate, which is something the parties sit down and come to agreement about. Both would be addressed later. Consistent with the requirements of AGIA, TransCanada is offering the capital structure set forth above; the negotiated rates are for when the pipeline comes into operation, when there'd be a little higher debt ratio. MR. PULLIAM noted the equity return is a little different from other U.S. pipelines. It would float year to year at 965 basis points above 10-year Treasury bonds ("T-bonds"); this equals 9.65 percent interest. If T-bonds are at 5 percent, the total would be 14.65 percent. REPRESENTATIVE SAMUELS recalled during the session Mr. Porter had looked back at the rate of return (ROR) for 10-year T-bonds, finding the floating rate of return went from 14 percent to the mid-20s. He asked Mr. Pulliam if he'd run a calculation comparing that and whether he could confirm that the ROR could go that high. MR. PULLIAM indicated he'd show calculations later. Turning to the final point on the slide, he said TransCanada's tariffs would reflect 100 percent cost recovery, meaning those shipping on the pipeline would be expected to pay ultimately for the full cost of constructing and financing the pipe, as well as the associated operating costs. TransCanada is offering to build as long as commitments are greater than the amount shown. 10:59:45 AM MR. PULLIAM addressed slide 3, the third slide on what TransCanada proposes, which had the following points: - Assess market demand for expansion every two years through non-binding open seasons - Offer rolled-in rates for expansions, subject to ceiling of 115% of initial tariff - Provide minimum of 5 in-state delivery points, using distance-sensitive rates MR. PULLIAM noted these are consistent with AGIA. The second point means if the cost of expansion would drive up the initial rates by less than 15 percent once expansion costs are factored in, then those rates would be included in everyone's tariff, including the tariff for those that committed in the initial open season. It may drive rates down as well by putting more gas in there, but rolled-in treatment would be used at least up to the 115 percent ceiling. He would show an example later. REPRESENTATIVE SAMUELS posed a question for Mr. Pulliam and Dr. Neri when that time comes: Can that number be negotiated away? REPRESENTATIVE CRAWFORD inquired about the difference between binding and nonbinding open seasons. MR. PULLIAM answered that a nonbinding open season is one in which the company solicits interest in transportation, rather than requiring someone to sign up at that point. In a binding open season, if someone responds to a solicitation and it is accepted, that is binding and the party would then be expected to sign a firm transportation (FT) commitment. MR. PULLIAM, in further response, relayed his understanding that it would be up to TransCanada to conduct the proceeding. But explorers or potential shippers would be the ones to respond and say what type of capacity they'd like and so forth. REPRESENTATIVE CRAWFORD asked whether TransCanada could respond by saying no. MR. PULLIAM said he wasn't sure, but they have to conduct it. He gave his understanding that if the demand is there and people are willing to pay the cost of the proposed tariffs, they'd be required to go forward. SENATOR WIELECHOWSKI asked how it works. For instance, does the open season have to be for gas to Alberta or Valdez, or can it be for gas to anywhere? 11:04:08 AM JOHN NERI, Ph.D., Benjamin Schlesinger and Associates, Inc., gave his understanding that this is once the pipeline has been constructed. If the pipeline is from Prudhoe Bay to Alberta, the points would have been defined already and the nonbinding open season would be the pipeline's way of finding interest from shippers as to whether it should expand the system. If, over the years, there are intermediate receipt or delivery points, it gets a little more complicated and there might be open seasons for those points. 11:05:10 AM REPRESENTATIVE FAIRCLOUGH asked: If it can't exceed 115 percent of the cost in determining access to the line, is there an inflation-proof factor for construction, or will inflation eat it up so there is no longer an assessment of the market? MR. PULLIAM offered his understanding that if they couldn't expand within the 115 percent cap, they wouldn't be required to offer rolled-in treatment for an expansion. An expansion could still take place, but it would bear whatever incremental costs were associated with it. REPRESENTATIVE FAIRCLOUGH expressed concern, saying it limits access to the line if someone has to pay the entire expansion cost but inflation for construction isn't factored into a baseline tariff. REPRESENTATIVE LeDOUX asked if anyone could answer definitively. MR. PULLIAM suggested someone from the administration probably could. 11:07:57 AM SENATOR ELTON highlighted the second point on slide 3, "Offer rolled-in rates for expansions, subject to ceiling of 115% of initial tariff." He asked if TransCanada is required to do so. MR. PULLIAM affirmed that, noting the 115 percent ceiling is required by AGIA. SENATOR THERRIAULT gave his understanding that the rolled-in rates, the 115 percent cap, and the ROR must be sanctioned by FERC. TransCanada hopes for a 14 percent ROR; the producers or whoever ships on the line will negotiate that rate down, which is in the state's best interests because the netback would go up. He recalled that the FERC language says there can be rolled-in rates, but not to the point of subsidization, a point FERC determines. SENATOR THERRIAULT also recalled that the state required that TransCanada propose in its application that it is willing to do rolled-in rates up to 115 percent. But until it goes to FERC, it isn't known if FERC will set that cap at 105 percent, for instance. He requested discussion about what the state asked for, what TransCanada proposed, and FERC's role in this. MR. PULLIAM opined that it's under the control of the regulators and that FERC said there'll be a presumption that rolled-in treatment is appropriate for expansions; this doesn't mean it has ceded control or oversight, however, since FERC is the ultimate arbiter of what is required. He suggested FERC's role in the process might be different in the context of a recourse rate versus a negotiated rate. 11:11:35 AM DAN DICKINSON added that the administration, in several places in the findings, pointed out that the State of Alaska could be among the parties that appeal, saying it should be 500 basis points, for instance. The state isn't bound by this plan and could be appealing those numbers along with the shippers. MR. PULLIAM turned to the final point on slide 3. He said it's consistent with AGIA that TransCanada is offering to provide a minimum of five in-state delivery points and to offer tariffs on a distance-sensitive basis. An example of how such rates work would be shown, but it means tariffs for movement in Alaska would be related to mileage and would be lower than for movement outside of the state. SENATOR WIELECHOWSKI asked whether there'd be a "postage stamp" rate for all of Alaska, so if there are five offtake points they'd have the same rate, even if one required 100 miles of in- state line and the other required 700 miles. MR. PULLIAM affirmed that. He said the rate is calculated based on the average delivery cost for all those locations. 11:13:10 AM REPRESENTATIVE KELLY returned to rolled-in rates. Interpreting Mr. Pulliam's remarks about the 115 percent cap to mean the incremental shipper has to pick it all up, he asked: Is it not the case that it's rolled in up to the 115 percent constraint and then the delta above that the incremental shipper picks up at 100 percent, instead of the whole deal being off? MR. PULLIAM said he wasn't sure if the entire increment would be picked up or it would just be the amount above 115 percent. REPRESENTATIVE KELLY asked Mr. Pulliam to get back on that. He also asked about inflation, surmising the 115 percent is strictly in nominal dollars. MR. PULLIAM gave his understanding that it would be the rate that would be expressed in nominal dollars. MR. DICKINSON added that the first series of expansions, as noted on the previous slide, will probably lower the rates for everyone. The rolled-in rates occur later, when looping is required. It won't be going from a base. Inflation may or may not eat it up, and there will be more overhead than 15 percent. 11:15:09 AM REPRESENTATIVE FAIRCLOUGH focused on distance-sensitive rates, asking what happens with respect to Alaska's offtake in relation to the rate for going through Canada, because there's less to monetize going through that line for capital construction costs. MR. PULLIAM replied that the cost is spread out for all movement of gas throughout Alaska, whether it's going to the border or to locations in Alaska. Then the cost is allocated based on the mileage and the volume to those different locations. REPRESENTATIVE FAIRCLOUGH offered that the more gas that is taken off in Alaska for in-state use, the higher the tariff rate will be because there will be less to monetize going to market through Canada. MR. PULLIAM said that's what he anticipates. 11:15:58 AM REPRESENTATIVE WILSON gave her understanding from meetings in Anchorage that it would depend on how far the gas has already come down the pipeline. She interpreted Mr. Pulliam's remarks to mean that if there is only one offtake point and they pay $3, and then two years later a new offtake point is added much farther down the line, it still would be added together so that the tariff for the first offtake point would go up. MR. PULLIAM responded if that occurred after the initial offtake points were set, he wasn't sure if it would lead to two different rates or would all get rolled into one. He said he didn't know if it would change the overall in-state rate and didn't believe the proposal specified how that would work. 11:18:00 AM REPRESENTATIVE GARDNER said the tariff rate is set for the original shippers; over time, expansion shippers, using compression expansion, bring down the rate for everyone. So the last new shipper using the rolled-in rate starts out at the lowest potential rate. Then new expansion shippers come in and looping is required. For the 115 percent ceiling for the last of the expansion shippers before the looping rates, she asked if that's 115 percent of the lowest possible rate or if the expansion shippers would experience a new tariff that has a ceiling of 115 percent of what the original shippers paid, the highest rate to date. MR. PULLIAM replied it's 115 percent of the initial rates, to his understanding. REPRESENTATIVE GARDNER surmised the expansion shippers would experience an increase that could be significantly more than they'd signed up for. MR. PULLIAM said it could be; that's his understanding. 11:19:33 AM REPRESENTATIVE LeDOUX referred to Representative Wilson's question about in-state delivery points. She asked: If there isn't anything in the proposal to cover that, should there be? MR. PULLIAM replied nothing he sees in the proposal addresses the specific question. He indicated it might be helpful to include that if a license is issued. Also, there is a regulatory backstop, since FERC will look at it and ask whether it's a reasonable treatment if there's any ambiguity. If the desire is to lock it in up front, though, that could be done. 11:20:56 AM REPRESENTATIVE SAMUELS posed a question for all the consultants later: Will the entire 115 percent evolve around how FERC interprets the word "subsidization"? For instance, if BP is paying $3.00 as a tariff, with the potential risk that it will go to $3.45 - billions over the life of the project - is it subsidization? REPRESENTATIVE SAMUELS followed up on Senator Therriault's comments, saying FERC will determine this. As he recalled, the shippers when they take FT commitments could argue their economic interests before FERC, but AGIA requires that TransCanada ask for this and then the state can go with what it believes is in its best interest for the tariff. He added that the mandate from Congress which leaned towards rolled-in tariffs and expanding the basin will play into it somehow, but a roomful of lawyers at FERC will determine that. MR. PULLIAM indicated later this would be addressed somewhat. He turned to slide 4, a proposed timeline assuming a license is awarded in April 2008. Since it wasn't awarded then, he said the timing would move back accordingly unless there are places where TransCanada believes it can make up for that. MR. PULLIAM said the initial open season is envisioned 18 months after the license is awarded, September 2009 on this timeline. If it's successful, FERC filings would be in place for the certificate of public convenience and necessity, he indicated, which would ultimately allow TransCanada to begin construction. MR. PULLIAM noted the anticipated FERC response is in April 2013, with project sanction at the beginning of 2014, which starts the construction process. This takes the project to early 2018, although initial gas is shown on this timeline for November 2017. He pointed out that the administration's findings include different assumptions for timing and generally see this schedule as optimistic, predicting instead that first gas will be about 2020. 11:25:19 AM REPRESENTATIVE CRAWFORD told members how extremely irritated he feels that it takes four years to get FERC approval, but two years to build it. Saying America needs this gas, he suggested focusing on getting expedited FERC approval. SENATOR WIELECHOWSKI asked whether FERC would expedite this and where the holdup is that would cause a three-year delay, to 2020, in getting the gas on line. MR. PULLIAM gave his assessment that FERC is committed to expediting it and is charged by Congress with doing so, which FERC takes seriously; later in the month someone from FERC would address those issues. One delay relates to the ability to do work in the summertime. This requires phasing, and the timeline on the slide is based on getting a license in April 2008 so work can start in the summer. If the license is issued at the end of summer, it pushes work back a year. He said the administration could better explain other delays, since they'd looked at all the regulatory and construction phases. 11:28:21 AM MR. PULLIAM showed slide 5, "What Does TransCanada Ask From the State?" It had the following points, along with a chart under the third bullet point that showed amounts budgeted, the state reimbursement, and the reimbursement percentages: - License - Follow through on State commitments under AGIA - State Contribution of $500 million toward development cost of pipeline - Not to be included in tariff rate base REPRESENTATIVE GARA returned to slide 4, surmising a four-year FERC approval process also would apply to any other proposal, including one from the producers. MR. PULLIAM replied he wasn't aware of anything in the FERC approval process specific to just TransCanada or the producers. MR. NERI added that FERC approvals for pipelines in the Lower 48 typically take 24 months or less. He wasn't certain why it might be 48 months for this proposal, although it is a large project with unique circumstances. 11:29:58 AM REPRESENTATIVE LeDOUX asked about the state license versus what is issued from FERC. MR. DICKINSON explained that FERC issues a certificate, a critical step in building a pipeline. But the state has now defined its license, a copy of which can be found on the website; it is distinct from what FERC does. REPRESENTATIVE LeDOUX asked whether that means the producers can't do anything without a state license. MR. DICKINSON replied the license refers to three documents: AGIA; the request for applications (RFA) put out as a consequence of AGIA; and the application. He indicated the commissioner of the Department of Revenue (DOR) had said nothing in the license prevents anyone from doing the same things without it. The license grants certain benefits to whoever holds it, and it is a one-time deal for one company. REPRESENTATIVE LeDOUX suggested it equates to the $500 million. MR. DICKINSON agreed that's the most visible aspect, but said other things are being granted. He mentioned a coordinator. AN UNIDENTIFIED SPEAKER mentioned treble damages. 11:32:41 AM REPRESENTATIVE HAWKER asked whether Canada's regulatory agency would be involved and might complicate this timeline or whether that is encompassed in the FERC timeline. MR. PULLIAM answered that this chart came from TransCanada's proposal, and he believes it encompasses a generic label of FERC. While this is ongoing, though, the same process would have to be going on with Canada's National Energy Board (NEB). AN UNIDENTIFIED SPEAKER asked whether the regulatory interrelationship would be discussed later. MR. PULLIAM agreed it could be talked about. 11:33:43 AM REPRESENTATIVE WILSON asked: If the state gives a license to TransCanada, doesn't the treble damages provision mean the state couldn't give a license to anyone else? MR. DICKINSON opined that the treble damages provision is triggered by a payment of money, presumably the $500 million or favorable treatment with respect to the royalty or tax, although he couldn't recall the exact language. There is a process to award one license, which is now before the legislature. If it fails, there may be another process to bring up another license, but he didn't believe it was anticipated that a second live license would be issued. REPRESENTATIVE WILSON gave her understanding that if the state assisted anyone else, the treble damages provision would apply. MR. DICKINSON replied there are caveats. If at some point the project is found to be uneconomic and both parties mutually withdraw, there'd be no treble damages. The treble damages would only occur if, say, one party thought it was uneconomic but the other didn't; then it might be asked whether the state was doing something with another party. MR. DICKINSON suggested looking at the language defining treble damages, noting there are two clauses: one that triggers it and one that defines the amount. Those don't use the same words and therefore might cause legal debate. He opined that assistance, particularly nonexclusive assistance, wouldn't trigger it. SENATOR STEVENS asked if the treble damages are for the amount of money expended or include loss of revenue. MR. DICKINSON proposed looking carefully at the statute and getting a legal opinion. He said the words are ambiguous to him as a layperson. He recalled last week in Anchorage the Department of Natural Resources (DNR) commissioner, who isn't an attorney either, defined the treble damages as measured by what is left over after reimbursement. MR. DICKINSON highlighted slide 5. He said the commissioner's interpretation was that the maximum treble damages would be three times $111 million, or $333 million. However, others would say it's three times the total spent, closer to $2.4 billion. There is some question as to whether it's three times on top of what has already been paid or the total payment. 11:37:25 AM MR. PULLIAM explained the chart under the third bullet point of slide 5, saying the state's contribution of $500 is something TransCanada's proposal asked for; AGIA has provisions on that contribution, including how much can occur prior to the open season, during the certification period, at least as a percentage. What is shown on the slide is from an amendment to TransCanada's proposal as to how those dollars would be spent. MR. PULLIAM noted about $82 million is budgeted through the open season, with the state reimbursing 50 percent; to get to the certification TransCanada anticipates another $528.7 million, with the state reimbursing $458.8 million. That's about 87 percent, whereas AGIA calls for 90 percent - less because the $500 million cap is reached during that time. Overall, through the certification period, the proposed budget is about $611 million, with the state contributing $500 million, about 82 percent. MR. PULLIAM said about $29 billion is estimated all the way through construction; the state's $500 million contribution would be about 2 percent of that. The $500 million cannot be included in the rate base, which is worth about 5 cents per MMBtu on the tariff. Examples would be shown later. CHAIR HUGGINS requested confirmation that AGIA requires TransCanada to go to certification, but not build the pipeline. MR. PULLIAM affirmed that. SENATOR ELTON referred to presentations by the state's reviewers of the license application, recalling they'd suggested that the $500 million affects the tariff assessed afterwards and that if there is a successful project, the amount will actually be an investment which returns dollars later. MR. PULLIAM agreed it certainly is an investment. He said the question is what the return will be. Part of what the state is doing is buying down the tariff for all shippers, about 5 cents per MMBtu. The state has a fairly large percentage of the gas "pie" with its royalty and taxes, particularly at projected price levels; it will get a big piece back in tariffs. Also, as with any investment, this is making a bet, taking some risk in return for a lower tariff and with the hope that it will help move the process along. 11:42:08 AM SENATOR THERRIAULT recalled hearing last week that the expected tariff reduction is 6 cents. He asked about the difference, saying the 5 cents is at $1.2 billion and so that penny is meaningful. He also expressed concern that some folks believe the state will write a check for $500 million the day after the license is issued, though that's not how the law works. MR. PULLIAM opined that the difference between the 5 cents he'd quoted - which is based on TransCanada's estimate - and the administration's 6 cents is from using different cost levels for the pipeline and a longer construction period, which results in a little higher savings but on a higher tariff. As to the second point, he agreed a check wouldn't be written right away; these would be matching funds provided after review of the expenditures, to his understanding. SENATOR GREEN asked: If the $500 million makes a 5-cent or 6- cent difference and the state sees it all invested early on, up to 82 percent of the investment total preconstruction, wouldn't it make the same difference if that $500 million were extended out over, say, only up to 50 percent throughout the process until the state reached its $500 million? MR. PULLIAM answered that it should have a little larger effect earlier in the process. In calculating tariffs, a pipeline is entitled to an allowance for funds used during construction (AFUDC), which is like interest on money invested. To the extent that the state defers earlier dollars, it actually would have a little more impact on the tariff savings. SENATOR GREEN said she wants assurance that the pipeline will get built as the state invests its $500 million. SENATOR BUNDE asked: Could AGIA have required the building of a pipeline? MR. PULLIAM replied he wasn't sure. As things normally progress, a company goes to FERC for certification after getting commitments to ship gas. If FERC provides the necessary certificate, it would be in the pipeline's interest to go ahead if it has those commitments. 11:46:14 AM REPRESENTATIVE LeDOUX suggested if this gets all the way through the certification process, FERC could say this is a go, the commitments could exist, and the $500 million could already be paid. She asked whether TransCanada could decide not to do it because it doesn't seem economically viable. MR. DICKINSON answered that TransCanada may have that legal and technical ability. Practically, though, if binding shipping commitments exist and TransCanada has obtained FERC certification under the terms of AGIA, it seems unlikely to decide against proceeding unless there are some extraordinary conditions on the certificate. There is an out if TransCanada meets the criteria for proving it's uneconomic, though at that point it would be pretty hard to do so. Also, the state could challenge it, if it were obviously economically viable, and say the company needed to proceed. MR. DICKINSON noted if there is a failed open season and commitments don't exist, however, TransCanada would be applying for a certificate and paying 10 cents on every dollar - with the state putting out 90 cents - without much hope of a return. TransCanada will want to find customers. If so, it will likely get a certificate. But having a certificate doesn't find customers, the gas shippers who use the transportation service. REPRESENTATIVE LeDOUX gave her understanding, then, that TransCanada would have to prove it's not economic in order to decline to build the pipeline. It couldn't simply decide on its own that the project isn't economic. MR. DICKINSON replied he would double-check, but believed that to be the case. 11:50:57 AM MR. PULLIAM summarized slide 6, the second slide on what TransCanada asks from the state, which had the following points from TransCanada's proposal: - Engagement with ANS producers to reach agreement on fiscal terms - Encouragement of robust exploration and development of North Slope gas resources - Cooperation of State to reach out to stakeholders - Cooperation of State in efforts with the Federal Government to obtain support for project - Use of loan guarantees for cost overruns - Exploration of alternative credit concepts, i.e., backstop Shipper contract MR. PULLIAM relayed his understanding that these aren't requirements, but things TransCanada is asking the state to do in order to help make the project work. 11:51:18 AM REPRESENTATIVE CISSNA highlighted the third point, saying unanticipated problems increase costs and slow a project, which for mega-projects can be disastrous. Noting she represents stakeholders, citizens in communities with a local economy, she surmised TransCanada has experience with socioeconomic impacts. Saying many such impacts are starting already, she asked what consideration has been given to how TransCanada and the state can mitigate any negative aspects or costs. MR. PULLIAM gave his reading that TransCanada hadn't specifically addressed that in the proposal, other than working in cooperation with the state to reach out to stakeholders. He interpreted this to mean that if people are impacted in some negative way, TransCanada would reach out to try to resolve it. MR. PULLIAM agreed that the larger the project, the more there is to consider, things that can and do go wrong. One should spend time getting the planning right at the outset - the better the planning, the better the execution. He said he thought it would be important during the planning process to listen to the concerns of individuals in communities as to what those negatives might be. MR. DICKINSON recalled in the prior go-round there was a body created, a municipal advisory commission, which hired Information Insights and did a report. Noting many items looked at would be features of this project as well, he suggested that is a good place to start. 11:55:59 AM REPRESENTATIVE LeDOUX asked about the first point, "Engagement with ANS producers to reach agreement on fiscal terms." MR. PULLIAM gave his interpretation that TransCanada wants an agreement on the fiscal terms to remove any potential impediment to a successful open season and getting the pipeline operational. REPRESENTATIVE HAWKER asked whether these are conditions or gratuitous requests that the state doesn't need to follow up on. MR. PULLIAM answered that as a legal matter he didn't know, but he didn't believe they were gratuitous. He'd seen correspondence back and forth and didn't believe they were characterized as precedent or legally binding. He gave his understanding that TransCanada believes these are important issues on which they'd like to see progress. REPRESENTATIVE LeDOUX asked if this is returning to the issue of fiscal certainty, an impediment a couple of years ago. MR. PULLIAM indicated he believes fiscal certainty through locking in the tax rate is part of it, together with the percentage the state gets. He surmised TransCanada would want a reasonable balance between the state and the producers as to how the state effectively taxes the pipeline, which would impact the tariff. Potentially more important is how the state taxes the gas production itself. 11:59:57 AM MR. DICKINSON explained the state's taxes and royalties. First, property tax that the project pays goes into the tariff and gets paid by the shippers, although TransCanada will get the bill. Second, there is an allowance for income tax, including corporate income tax; if TransCanada makes profits on the pipeline it will get the bill, but it goes into the tariff and is paid by the producers. Third, production tax is based on production; TransCanada presumably would have no production, so it would be paid by the producers. Those are the taxes. MR. DICKINSON said, fourth, royalties are based on what is produced off of state-owned land, so TransCanada wouldn't pay those either. So taxes and royalties to the state if this project is built won't come out of TransCanada's pocket. They'll all come from the shippers, presumably the producers that are the customers on the pipeline. REPRESENTATIVE LeDOUX asked: In order to get this to a successful open season, will the legislature have to talk about providing the producers with some fiscal certainty on taxes over a specific length of time? MR. PULLIAM replied he didn't know, but TransCanada has said it would like for the state to come to an agreement with the producers on fiscal terms; in their view, that would facilitate a successful open season and project. REPRESENTATIVE DOOGAN asked: If the legislature approves a license for TransCanada, does it obligate the state either to reach an agreement with the producers on fiscal terms or to discuss fiscal terms with them? Or is this a third category - things TransCanada would like the state to do - along with the contract and economic assumptions? MR. PULLIAM replied that is his understanding. As it's packaged in the context of a license - referring to AGIA, the RFA, and TransCanada's proposal - whether that creates something as a legal matter he couldn't answer. But based on public discussion from the administration and TransCanada, it seems to be in the category of things TransCanada would like the state to do that it believes are helpful in moving the project forward. He opined that neither side has said, at least publicly, that any of these are binding. REPRESENTATIVE DOOGAN requested to hear from any of the LB&A consultants or the administration's consultants if they disagree with that interpretation. 12:03:47 PM MR. PULLIAM addressed slide 7, the third slide on what TransCanada asks from the state, which had the following points from TransCanada's proposal: In the event of an unsuccessful open season: - Expect State to use its position of sovereign government to encourage, induct and persuade ANS producers to commit gas - Expect State to thoroughly evaluate and seriously consider financial and commercial feasibility of dedicating significant State resources to underwriting an alternative financing mechanism for the project REPRESENTATIVE LeDOUX asked: If there's not a successful open season - meaning there's no agreement to ship the gas - what project would there be and what difference would it make if the state finds an alternative financing mechanism for it? MR. PULLIAM replied if nobody commits gas in the open season in sufficient quantities, the question is how to make the project go. Gas is the way to get financing. These types of projects typically aren't done on speculation, and that isn't anticipated here. As he reads the proposal, if there isn't a successful open season TransCanada asks for the state to perhaps look creatively at ways to finance it, including state guarantees or funds, for instance, or legal action to get commitments. REPRESENTATIVE LeDOUX surmised the state assumes if the pipe is there, the gas will be there and the customers to use the line. MR. PULLIAM responded that the biggest cost of the pipe is the upfront capital; about 75 percent of the tariff cost comes from those construction and financing costs. If that is overcome and the pipe is there, under almost any conceivable scenario of gas prices and operating costs, there'd be a tremendous incentive to sell the gas. If someone came in and laid the pipe at one's feet, the tariff would likely be cheap. MR. DICKINSON clarified that there can be more than one binding open season. The open season is a sort of shorthand; then there must be agreements and so forth to get the commitments. Simply having one open season that doesn't result in express commitments doesn't stop the process; the company can keep going and might change terms. MR. PULLIAM concurred. 12:08:37 PM SENATOR ELTON asked: If the legislature approves the license, will this be a playground for lawyers with respect to treble damages, for instance, because this information and these requests have been transmitted? He suggested the need for legal advice on whether the state has accepted legal obligations from the applicant. REPRESENTATIVE SAMUELS surmised the consultants hadn't looked into that, saying it could be looked at by an attorney. Returning to the first point on slide 7, he suggested there could be a reserves tax, a tax deal, delayed taxes, a rebate, and so on. But if there is no gas, TransCanada wants the state's help in some way to get gas into the pipeline. It doesn't specify whether it is a carrot or stick and has no timeline. He requested confirmation from Mr. Pulliam. MR. PULLIAM said he thinks that's what TransCanada is asking. 12:10:48 PM CHAIR HUGGINS told members he'll be pursuing a contract to go along with a license. He suggested having a contract that takes the state's "must haves" in AGIA and what TransCanada has asked for, forming an amalgamation. This would clear up any ambiguity so the legislature knows what it is agreeing to. 12:12:12 PM MR. PULLIAM read from slide 8, "How Does the State Subsidy Help?" It had the following points: Reduces risk to TransCanada - State shares in risk that project may not proceed to completion and is responsible for 82 percent ($500 Million) of the targeted $611 million in development costs Reduces tariff, which benefits resource owners: State and producers. Using TransCanada assumptions as to costs and tariffs, the $500 million impacts the tariff as follows: - Estimated tariff to Alberta without subsidy is $2.46/MMBtu - Estimated tariff to Alberta with subsidy is $2.41/MMBtu - This is $0.05/MMBtu - Over a 25-year period, this amounts to a reduction in tolls of $2.2 billion. Approximately $1.2 billion is expected to accrue to the State MR. PULLIAM added that this reduces upfront risk to TransCanada, since its initial outlay would be relatively low. And by reducing the tariff, it also benefits the resource owners. The subsidy is worth about a nickel per MMBtu. MR. PULLIAM indicated the $1.2 billion to accrue to the state was an estimate from the LB&A consultants. As for how $500 million gets $2.2 billion back, the $500 million today has the effect of offsetting capital costs by giving a return that is akin to interest. In response to Representative Hawker, he said these are all expressed in nominal dollars. REPRESENTATIVE HAWKER noted these would be cash dollars that come in over 25 years, then. If the traditional present-value calculation is followed, comparing $500 million today versus a cash-flow stream of $1.2 billion over 25 years, it isn't a one- to-one comparison as to what is being invested versus what is being obtained. MR. PULLIAM agreed, saying it would be much less than the present value of $1.2 billion. REPRESENTATIVE GARA asked if the state wouldn't have to spend the full $500 million if the producers committed their gas to the point where this could proceed. MR. PULLIAM gave his understanding that if the legislature approves the license, it commits the state to spending the $500 million up to the point of getting a certificate, even if the producers were to commit their gas immediately. 12:15:43 PM SENATOR FRENCH asked what estimates the LB&A consultants had arrived at. Recalling that last week's presentation in Anchorage showed much higher estimates from Black & Veatch compared with TransCanada's on slide 8, he said a quick conversation with one of the administration's consultants indicated the big difference - about $1.50 - is the difference between a cost estimate developed today in today's dollars versus a cost estimate for the 2016 time period for actual construction. MR. PULLIAM agreed the administration predicts higher tariffs than TransCanada does. First, the administration estimates capital costs overall will be higher in today's dollars because the GTP will be more expensive to build and the exchange rate between Canadian and U.S. dollars will be lower than in the projections required by the RFA. MR. PULLIAM said, second, it forecasts higher inflation, about 4 percent a year versus 2.5 percent. Third, it estimates completion in 2020, two years later than TransCanada's 2018, increasing interest on the moneys invested. Finally, it predicts higher borrowing costs. MR. PULLIAM noted those all factor in. He anticipates the tariff will likely be higher than what is in TransCanada's proposal. He said he isn't an engineer and so cannot go into cost estimates like some of the consultants hired by the administration, but he has looked at their reports and doesn't see anything that strikes him as unreasonable with respect to cost estimates or assumptions they used in determining a tariff. He hadn't heard yet from TransCanada about the differences. 12:19:40 PM MR. PULLIAM addressed slide 9, "Tariff Fundamentals," which had the following points: What is a tariff? - Document that sets forth rate and terms of service provided by a pipeline to shippers - The per-unit cost charged by a pipeline to ship gas from point of injection to point of extraction (Point A to Point B) MR. PULLIAM added that the $2.41 to Alberta is the per-unit charge, for instance. He characterized the tariff as the entire package governing the service. MR. PULLIAM turned to slide 10, a map labeled "TransCanada's Tariff Estimates" that gave these estimates: GTP $0.59, Alaska section $$0.92, Yukon-BC section $0.75, and Alberta section $0.15, for a total without fuel of $2.41; fuel $0.86 and a total with fuel of $3.27. A footnote, related to the fuel and total with fuel, said "25-year average based on AEQ2008 price profile at Henry Hub, with $0.40/MMBtu differential to AECO." MR. PULLIAM noted much of what he'd been planning to say here had just been discussed. In response to Senator French, he said this all assumes 4.5 Bcf/day coming into the GTP. MR. PULLIAM explained that when someone signs a tariff, there is an agreement to pay a certain per-unit rate and provide the fuel consumed in the operations. The pipeline doesn't send the shipper a bill for the fuel but takes it out of the gas. The cost is the value, what the gas would yield on a netback basis on the North Slope. The higher the price, the higher that fuel component will be; the lower the price, the lower the component. The slide shows an estimated average cost of $0.86 for fuel. MR. PULLIAM specified that these are all nominal dollars over the 25-year period, assuming gas prices in AECO consistent with the DOE's latest forecast put out earlier this year, less a 40- cent differential between Henry Hub and AECO. Observing that TransCanada's estimated total with fuel is $3.27, he suggested the administration's number would be closer to $5.00. 12:23:10 PM MR. PULLIAM paraphrased slide 11, "Significance of the Tariff to Resource Owners," which said: All else equal, resource owners (State and producers) prefer lower tariffs; lower tariffs = higher netbacks In the case of gas, tariffs typically involve long- term "take or pay" commitments. Here we are talking about commitments likely ranging between 15 and 30 years - In this respect, gas pipeline tariffs are different than oil pipeline tariffs. With oil pipelines (such as TAPS), there is typically no take or pay aspect - Risk to shipper rises with length of commitment - Risk to shipper rises with level of tariff relative to the expected gas price - Tariff level is fixed while price of gas at market is unknown and variable MR. PULLIAM emphasized that risk to the shippers rises - although risk to the pipeline falls - with the length of the commitment. This is because a tariff, at least when it has been negotiated, locks in a consistent price level per unit for shipping. What's typically unknown, though, is the market price for gas. The further out in time one goes, the more unknown that is. So the risk to the shipper that signs on to the consistent payment of the tariff increases as the time commitment increases. MR. PULLIAM showed slide 12, a graph depicting an example of gas prices and a tariff, also labeled "Significance of the Tariff to Resource Owners." He noted the bars at the bottom show the fixed tariff over time, not including the fuel component. REPRESENTATIVE GARDNER highlighted risk to the shipper. She asked: Is it practical for the state to offer what the producers call fiscal certainty so the rate when the contract is signed holds true until that contract expires or is renegotiated? MR. PULLIAM replied he could see some logic in tying those together, but it boils down to 1) whether it ultimately makes a significant difference economically to go out over a certain amount of time and 2) whether legally the state could do so. The committees took a break from 12:26:29 PM to 1:30:22 PM. REPRESENTATIVE SAMUELS returned attention to slide 12. MR. PULLIAM noted they'd been discussing the commitment to ship and how that leads to a fixed payment over time. What the shipper hopes to get is the sale of the gas, which generally isn't at a guaranteed price but varies with market conditions. The longer it goes over time, the less certainty there is about that difference, and it introduces an element of risk. MR. PULLIAM showed slides 13 and 14, similar graphs depicting the difference if the gas price is lower or if the tariff is higher than anticipated. In either case, the difference between the fixed payments and the price received for the gas is less. It varies over time, and the longer the time, the more economic risk it introduces. MR. PULLIAM discussed slide 15, also titled "Significance of the Tariff to Resource Owners." It had a different graph and said: Based on current projections by the EIA over 25 years beginning in 2018 and potential tariffs set out in the TransCanada application, the tariffs would be approximately 25% of the value of gas at AECO MR. PULLIAM explained that this graph depicts a levelized tariff that TransCanada has put in place, along with fuel costs that rise over time as a function of gas prices. It also shows projected gas prices from the Energy Information Administration (EIA), which is the arm of the DOE that forecasts prices for Henry Hub, the main trading center in the U.S. What the consultants did was to bring it back to an AECO basis and add in the value of NGL extraction to that line. MR. PULLIAM alluded to the key on the graph, which had the estimated AECO sales price at $12.91, 100 percent; the tariff at $2.41, 18.7 percent; fuel at $0.86, 6.6 percent; total costs at $3.27, 25.3 percent; and a netback at $9.64, 74.7 percent. He noted EIA's forecast prices are higher and continue to rise over time. The tariff, with fuel, equates to about 25 percent of the value of the gas at AECO, with the netback at about 75 percent. MR. PULLIAM highlighted uncertainty in forecasting oil or gas prices. He said one reason for considering a gas pipeline is that expectations for gas prices have gone up significantly in this decade. These particular forecasts represent the views of EIA as of early 2008 and generally equate with other forecasts, though somewhat conservative; Wood Mackenzie and some other private firms predict higher gas prices. He emphasized that these forecasts have been evolving over time, with changing expectations even in the last half a year for both oil and gas. 1:35:36 PM MR. PULLIAM turned to slide 16, which had a graph similar to slide 15 and said: Increasing capital costs by 50% would lead to tariffs being approximately 32% of the value of gas at AECO The key showed these figures: estimated AECO sales price at $12.91, 100 percent; tariff at $3.35, 25.9 percent; fuel at $0.78, 6.0 percent; total costs at $4.13, 32.0 percent; and netback at $8.78, 68.0 percent. MR. PULLIAM clarified that this depicts what would happen if TransCanada's assumed costs were to increase by 50 percent. This is more in line with what the administration predicts, though not quite as high. The total cost including fuel would be close to one-third of the netback value. MR. PULLIAM showed slide 17, a three-column summary with these categories: "25% Below EIA AEO 2008 Forecast," which gave a netback of 68.7%; "EIA AEO 2008 Forecast," which gave a netback of 74.7%; and "25% Above EIA AE 2008 Forecast," which gave a netback of 78.2%. MR. PULLIAM said the average netback value is shown in the middle category. For all, the tariff doesn't change but the fuel element does; lower prices mean lower fuel costs. Under any of these scenarios there is a good, positive netback, consistent with the view that gas prices should be fairly robust going forward. SENATOR FRENCH asked whether other presentations would address where the netback falls in relation to other projects globally. MR. PULLIAM replied it isn't in his presentation, though he anticipates seeing some from the administration. As for netbacks, the value at the inlet of the GTP, he said these certainly appear to be substantial and healthy on a per-unit basis. The debate will be how to divide that value. 1:38:54 PM MR. PULLIAM summarized slide 18, "Tariff Fundamentals," which had the following points: Tariffs are regulated - U.S. is regulated by the Federal Energy Regulatory Commission (FERC) - Canada is regulated by the National Energy Board (NEB) - Charged with insuring that rates are "just and reasonable" - Opportunity for shippers to challenge tariffs through rate proceedings MR. PULLIAM added that the charge to FERC and NEB to set just and reasonable rates means the rates would be consistent with a competitive market operating rates that are cost-based. An important part of the process is the opportunity to shippers and other interested parties such as the state to challenge the rates through rate proceedings. Both recourse rates and negotiated rates are being offered by TransCanada. 1:40:06 PM MR. PULLIAM addressed slide 19, "Recourse Rates," which had the following points: - Traditionally, tariffs have been based on "cost of service." Tariff rates under a traditional cost- based approach are known as "Recourse" rates - These tariffs provide for recovery of operating costs, capital costs and a "reasonable" return on invested capital - Initial tariffs would be established by FERC in filings by the pipeline during certification. These rates could be challenged in FERC and/or NEB by shippers in rate proceedings MR. PULLIAM said this is the traditional approach at both FERC and NEB. Capital costs are for the pipeline itself. The rates can be challenged by shippers or other stakeholders through rate proceedings. MR. PULLIAM showed slide 20, "Recourse Rates and Cost of Service," which said: Key elements of cost of service include: - Return on Investment - Return of Investment (Depreciation) - Operating Expenses - Non-Income Taxes (e.g., Property Taxes) - Income Taxes MR. PULLIAM elaborated. He said return on investment includes return on equity, the cost of the debt. The investment itself is recovered in a tariff through depreciation; if $20 billion is spent on the pipeline, that will be depreciated over time. The others are pass-through costs. For instance, income tax paid by the pipeline flows through in the rates, so the shippers ultimately pay it. MR. PULLIAM said the more profit there is - the higher the return on equity - the more there'll be in income tax, which raises the rates. The lower the return on equity is, the lower the income tax and thus the tariff will be. 1:43:03 PM MR. PULLIAM discussed slide 21, also labeled "Recourse Rates and Cost of Service," which showed cost-of-service elements in TransCanada's estimates as follows: return on investment $33.2 billion, 32 percent; return of investment (depreciation) $33.2 billion, 32 percent; operating and maintenance $9.5 billion, 9 percent; non-income taxes $15.8 billion, 15 percent; income taxes $12.3 billion, 12 percent; and a total of $104.0 billion, 100 percent. MR. PULLIAM said the return on investment and return of investment are about two-thirds of the cost of service that goes into the tariff. In large part, those drive the tariff rate. The pipeline has some control over those through what it asks for as a return and what it invests. The cost of the project itself dictates what the capital has to be, and then regulatory agencies have a big say in what the return will be. MR. PULLIAM added that the pipeline also has some control over operating and maintenance costs through how it manages those, but they are a relatively small percentage. It has little control over taxes, which are set by governments, although it may have some lobbying influence. Pass-through items are about one-third of the cost of service. 1:45:09 PM MR. PULLIAM addressed slide 22, "Cost of Service--Return on Investment," which read: Return on Investment is calculated as: Rate Base x Rate of Return Rate Base is: Gross Plant (Initial Capital Investment + AFUDC) - Accumulated Depreciation = Net Plant - Accumulated Deferred Income Taxes + Working Capital = Rate Base MR. PULLIAM gave details. He said the rate of return is whatever is allowed. Gross capital is what is put into the plant initially, along with the AFUDC, which allows interest to be earned on money invested today; it goes into the tariff calculation, and the longer the time between when funds are expended and the project comes on line, the larger this is. Accumulated deferred income taxes are sometimes known as ADIT. The rate base is what someone ultimately gets a return on. MR. PULLIAM showed slide 23, "Cost of Service--Rate of Return," which had the following points: Rate of Return is: - "Reasonable Return" on Investment (Rate Base) - Function of three components: - Capitalization Ratio (Debt, Equity) - Cost of Debt - Allowed Return on Equity MR. PULLIAM reiterated that both regulatory bodies are charged with setting a reasonable return. The AGIA requirement for the capitalization ratio is that the pipeline seek to have at least 70 percent debt. That's important. Generally, debt is cheaper than equity and is tax-deductible; a higher debt-to-equity ratio, within reason, usually leads to a lower cost of service. MR. PULLIAM said within that, the cost of financing as far as floating debt is important and typically is flowed through in the regulatory process. The allowed return on equity is open to more debate and is where FERC and NEB will have more of a hand in what is allowed. 1:47:54 PM MR. PULLIAM showed slide 24, also labeled "Cost of Service--Rate of Return," which had the following points: - These elements are set by FERC to allow "Reasonable Return" - Typically allow for pass-through of debt costs, plus - Return on Equity consistent with business risk associated with the pipeline venture - FERC has approved Equity Returns in the range of 12-14% - Higher end of the range for "greenfield" projects - NEB returns have traditionally been lower - Rate of return is one of the biggest issues for regulators - Initial rates allowed by regulators can be revisited in an initial rate hearing 3-4 years after pipeline operation begin - Initial return is likely to be reduced if business risk is judged to be lower MR. PULLIAM indicated these generally apply to both FERC and NEB. Elsewhere in the U.S., FERC has approved rates of 12-14 percent; equity returns on larger new projects have been at the higher end. The NEB returns have traditionally been lower, though negotiated rates in Canada have been somewhat above what NEB allows and closer to the upper end of the FERC range. MR. PULLIAM said rate of return is one of the biggest issues for regulators, something they look at closely. Initial rates allowed in the certification process will typically be revisited by the regulatory body once the pipeline has been operating. If it determines the risk is less than originally thought, it is likely to lower the allowed return. MR. PULLIAM explained that factors which tend to reduce the risk and lead regulators to lower the return include: that the pipeline has been operating for some period, that it has been fully subscribed, and that it appears things are working as anticipated and the pipe will be full for some time. The aforementioned are all in the context of the cost-of-service approach, the recourse rates. 1:50:13 PM MR. PULLIAM paraphrased slide 25, "Negotiated Rates," which had the following points: - Negotiated rates are also regulated by FERC - However, as the name implies, these are rates that are "negotiated" between shipper and the pipeline company - All elements are up for negotiation. This includes: - Rate of Return - Length of commitment - Flexibility - Treatment of cost overruns - Future expansion issues - Changes in operating costs MR. PULLIAM said TransCanada is offering to provide negotiated rates, which must be approved by FERC and NEB but aren't prescribed. Such rates may be for 5, 10, 15, or 20 years, for instance, and there is flexibility for scheduling and so on. REPRESENTATIVE SAMUELS referred to future expansion and asked: Could TransCanada negotiate a rate with the producers that would throw out the 115 percent? MR. PULLIAM gave his understanding that they'd be required to keep that, but couldn't go above that level. He then said they might be able to negotiate something better. REPRESENTATIVE SAMUELS posed a scenario of TransCanada having negotiated with BP to ship gas for $3, with a 20-year FT commitment; an expansion raises the tariff, and AGIA requires that TransCanada go to FERC and request that it be rolled in so the $3 tariff takes a hit. He asked: If it's a negotiated rate, not a recourse rate, what do AGIA and the TransCanada proposal require? Do they still have to go to FERC and ask for a higher tariff, above what was negotiated with the customer? MR. PULLIAM relayed his understanding that the aforementioned provision is to be included in the negotiated rates. REPRESENTATIVE SAMUELS asked: Does the state have a say in the negotiated rate? MR. PULLIAM answered that the state has some say before the rate is approved. Assuming the pipeline company and shippers have come to agreements and set negotiated rates, the state would have some say until the time when FERC certifies the project. While the state could try to go back later and challenge those rates, the regulatory bodies generally view the negotiation and bargaining process as providing an outcome they want to see; so the ability to challenge afterwards would likely be much less. REPRESENTATIVE SAMUELS returned to the 115 percent and asked: If Anadarko comes in and wants to put gas in the pipeline but it will drive the tariff up, it is your view that TransCanada would have to go to FERC and argue to roll in the tariff and bump up the rate negotiated with its original customers? MR. PULLIAM acknowledged there might be legal aspects, but opined that TransCanada would be required to include rolled-in treatment in the negotiated tariff. He also suggested perhaps TransCanada could agree to forgo that and offer better negotiated terms to a shipper. 1:54:51 PM MR. PULLIAM summarized slide 26, also labeled "Negotiated Rates," which had the following points: - Negotiated rates can result in lower tariffs than recourse rates through the process of commercial negotiation - Negotiation takes the place of regulation. However, as the negotiation takes place with the backdrop of regulatory oversight (and recourse rate option/ backstop), the process can help reduce tariffs charged - Typically involve long-term shipping commitments - Negotiated rates must be approved by FERC and NEB - Regulatory bodies have viewed negotiation process favorably and are reluctant to modify them after the fact MR. PULLIAM added that for shippers, the worst that will happen through negotiation is the recourse rate, whereas negotiation can result in more favorable terms. He paraphrased slide 27, also labeled "Negotiated Rates," which said: A point for the State to consider: - The negotiation process can provide favorable results for the State by helping to keep tariffs down - State likely would not have opportunity to challenge these rates after the fact. The opportunity to challenge would be in the certification process - State's interest should be protected. However, this is the time to apply scrutiny MR. PULLIAM emphasized that the time to challenge negotiated rates is during the certification process. Waiting to see how they play out won't work. 1:57:01 PM MR. PULLIAM showed slide 28, "Some Examples of Recourse and Negotiated Rates," which had these comparisons: for Alliance Pipeline the recourse rate was $0.53 and the negotiated rate $0.54; for Rex West, the recourse rate was $0.91 and the negotiated rate $0.77-$0.79; for Gulf Stream, the recourse rate was $0.66 and the negotiated rate $0.57-$0.59; and for Maritimes and Northeast Phase IV the recourse rate was $0.78 and the negotiated rate $0.53. MR. PULLIAM noted generally recourse rates have been higher, in part because of the negotiation. Also, in the negotiated setting - which also can happen in the recourse setting - the tariff is typically levelized. He showed slide 29, "The 'Levelized' Tariff," which had the following points: - A traditional cost-based tariff starts high and falls as a pipeline recoups its capital costs (i.e., return on investment and return of investment) - This happens because the rate base falls over time as the pipeline is depreciated - A levelized tariff is one in which the tariff is constant over time. The level of the tariff is set such that it results in the same Net Present Value (NPV) and the cost of service for the non-levelized tariff MR. PULLIAM explained that net present value (NPV) is figured for what a traditional cost-of-service tariff would be, and that is translated into a constant-rate tariff that gives the pipeline the same present value in terms of tariffs over time. By contrast, traditional cost-based tariffs, seen in many recourse rates, start high and fall over time as the pipeline is depreciated and that is recovered through the tariff; the company doesn't get to earn a return on the amount depreciated. MR. PULLIAM pointed out that everything members will see, both from these consultants and the administration, assumes there will be levelized tariffs. He showed slide 30, a bar graph labeled "Illustration of a Levelized Tariff," and then paraphrased slide 31, "Tariffs Proposed by TransCanada," which had the following points: Offer 25, 30 and 35-year firm transportation services (FT) Offer Recourse Rate tariff for GTP and Alaska Pipeline Section; Negotiated Rate tariff for all sections - No Recourse Rate offered for Canada, as this is not normal business practice in Canada (i.e., negotiated rates are the norm) MR. PULLIAM specified that new pipelines in Canada typically have negotiated rates, although those have to be approved by the regulators. 2:00:21 PM REPRESENTATIVE SAMUELS again referred to the 115 percent and said the point of the 15 percent extra is to ensure that explorers get in. For the roundtable discussions, he asked: Could rates be rolled in within Alaska, but negotiated to be lower in Canada? Could gamesmanship occur between TransCanada and the producers as to what is requested from the regulatory agencies? Is it possible to use the NEB and FERC processes independently and negotiate rates that are invisible to the regulatory agencies? MR. PULLIAM addressed slide 32, "Key Elements of Recourse Rate Tariff," which had the following points: - Provides for full recovery of capital costs on "straight line" basis over 25-year period, assuming initial transportation agreements are for this period - 100% load factor rates for authorized overrun services - Rate base will exclude Alaska portion of $500 million State contribution - Capitalization of 70% debt / 30% equity - Expansions capitalized at 60% debt / 40% equity MR. PULLIAM, on the second point, said shippers will bear the cost of overruns that are authorized. He also noted the debt- to-equity ratio for capitalization is in keeping with AGIA; expansions would be financed at a lower debt amount. 2:03:01 PM MR. PULLIAM paraphrased slide 33, "Debt Costs," which stated: Debt costs will be weighted average cost incurred by pipeline - Contemplate U.S. loan guarantees - Loan guarantees were originally $18 billion, up to 80% of project - They were indexed to inflation. In 2008 dollars, this is approximately $20 billion - Assuming 75% debt, this would support project of $26.8 billion in $2008 if all the loan guarantee was used - TransCanada has assumed a number for loan guarantee debt of 4.7%. Based on expectations of inflation in the 2.5% range, this may be somewhat low - Borrowing without the U.S. loan guarantee is estimated at 150 basis points higher (i.e., 6.2%) MR. PULLIAM recalled discussion as to whether the loan guarantees would work for overruns. He said the federal government has provided for loan guarantees, with the stipulation that it could be the lower of $18 billion or 80 percent of the project cost. MR. PULLIAM emphasized that the amount is indexed to inflation. Since the law was passed in 2004, it would be about $20 billion today. Assuming 75 percent debt financing, this would support a project of about $26.8 billion today. TransCanada's estimate in 2008 dollars is about $25.8 billion - close to the maximum available with the loan guarantees. MR. PULLIAM also said TransCanada's analysis assumes the loan guarantees will carry about a 4.7 percent debt rate. However, his review suggests this may be a little low; it would be addressed in the next slide, consistent with what the administration anticipates. Without the loan guarantee, TransCanada estimates debt costs at 150 points or 1.5 percent higher than the loan-guaranteed amount. 2:05:35 PM REPRESENTATIVE SAMUELS asked: Do you consider both the 4.7 and 6.2 percent low, and they would float together? MR. PULLIAM answered he thinks both are a little low. The 150 basis points is probably a little more reasonable, the difference between the two. But he believes the overall structure is a bit low. REPRESENTATIVE SAMUELS asked: How much does the 150 basis points cost us in the tariff? If there were no loan guarantees, how much would the tariff go up? MR. PULLIAM answered that for every percentage point difference in debt, there is about an 11-cent change in the tariff, assuming the capital costs shown. 2:06:36 PM MR. PULLIAM turned to slide 34, also labeled "Debt Costs," a bar graph of inflation-adjusted historical 10-year T-bond and corporate bond rates for the last 20 years. He said because interest rates have changed with inflation, this shows the spread between different interest rates and current inflation. MR. PULLIAM observed that the spread for 10-year T-bonds, for instance, has come down over time and recently went negative. Over the last 5 years the average spread was low, 1.31 percent; over the last 10 years, it was 2.1 percent; and over 20 years, it was 3 percent above inflation. He surmised the recent experience is lower than what folks will require in terms of spreads over inflation. Something between the 10-year and 20- year rate is probably more reasonable, from above 2 percent to 2.5 percent over inflation. MR. PULLIAM said over the last 10 years the difference between AAA bonds and 10-year T-bonds has been about 1.4 percent, whereas for lower-rated bonds it's a "low 2 percent" spread between T-bonds and BAA bonds. He also said he believes the historical numbers support the spread between the guaranteed and nonguaranteed, that 150 basis points which TransCanada has proposed, but the guaranteed rate itself is probably too low. 2:09:05 PM MR. PULLIAM showed slide 35, "Potential Borrowing Costs for Guaranteed Loan." It depicted rates using historical premiums over inflation. Projected inflation was 2.50 percent for all categories. The risk-free premium was 3.00 percent for the 20- year average, 2.10 percent for the 10-year average, and 1.13 percent for the 5-year average. The margin was 0.50 percent for all. And the total was 6.00 percent for the 20-year average, 5.10 percent for the 10-year, and 4.13 percent for the 5-year. MR. PULLIAM explained that the margin was calculated at 0.50 percent, 50 basis points, to get the financing over the T- bond rate. That puts the 10-year average over 5 percent, and for the 20-year average it's closer to 6 percent. He suggested a reasonable place would be somewhere in between. Below 5 percent, on a long-term basis, seems too low. MR. PULLIAM turned to slide 36, "Equity Costs." A bar graph notated "965 Basis Points Above Historical 10-Year T-Bond Rates," it had a key showing the 20-year average at 15.73 percent, the 10-year average at 14.51 percent, and the 5- year average at 14.05 percent. He explained that TransCanada has talked about an equity return that floats at 965 basis points above the 10-year T-bond rate. MR. PULLIAM said from a commercial standpoint, he doesn't see anything unreasonable in the floating rate, though it hasn't been used and approved before by FERC. Typically, FERC has had a fixed rate. Historically, that rate has been above 18 percent but has been falling over time; in the last five years it has averaged about 14 percent. As noted before, the last five years is a period of historically low real interest rates, the spread over inflation. 2:11:31 PM SENATOR WIELECHOWSKI recalled that slide 34 shows that in 1988, for instance, the 10-year T-bond rate was about 4.5 percent. He asked: If 965 basis points are added, shouldn't it be more around 14-15 percent? He also asked whether this is the rate of return, what they'll be able to get back on their tariff, which he recalled Mr. Pulliam said is normally 12-14 percent. MR. PULLIAM replied this is the proposed rate of return on the equity portion. In further response, he explained that TransCanada has proposed 965 basis points over the T-bond rates. If it were applied back historically, it would look like this. MR. PULLIAM surmised the question was whether one would take the approximately 4.5 percent shown on slide 34 and then add it to the 965. He pointed out that this is the spread over inflation that's in slide 34; thus an additional amount for inflation would be included in that total amount. So this line on the current graph includes an inflation component, he indicated. SENATOR WIELECHOWSKI asked: If bond yields increase dramatically when the gas is flowing, will that decrease the money Alaska gets through its taxes, since it would increase the tariff and be more of a write-off for the companies? MR. PULLIAM replied if the rates rise and there is a floating rate over the T-bonds, that increases the tariff and reduces netbacks. SENATOR WIELECHOWSKI expressed interest in long-term forecasts for T-bonds. REPRESENTATIVE SAMUELS asked what the normal rate of return allowed in Canada is. MR. PULLIAM opined it's closer to the 12 percent range, but sometimes negotiated rates in Canada can be higher than NEB would allow in its formulas. Ultimately, that rate will come from negotiation in Canada and may be closer to the U.S. number. DR. NERI added, with respect to interest rate forecasts, that he'd checked before coming here. The Congressional Budget Office makes 10-year forecasts; those currently project a 10- year bond rate of 5.2 percent in 2018. Adding the 9.65 percent risk premium gets it to 14.85 percent. 2:16:16 PM MR. PULLIAM turned attention to slide 37, "Potential Equity Return Under Proposal," noting it dovetailed with that. Like slide 35, it depicted rates using historical premiums over inflation; projected inflation was 2.50 percent for all; and the risk-free premium was 3.00 percent for the 20-year average, 2.10 percent for the 10-year average, and 1.13 percent for the 5-year average. Equity premium was 9.65 percent for all. Totals were 15.15 percent for the 20-year average, 14.25 percent for the 10-year, and 13.28 percent for the 5-year. MR. PULLIAM said ultimately these rates will respond to inflation. If inflation is low, rates will be low; if inflation is high, rates will rise. If 2.5 percent inflation is assumed going forward, looking somewhere between the 10-year and 20-year historical premiums on the 10-year T-bond, which is in the 2-3 percent range, and then adding that 965 basis points, it gives a rate of return between 14.25 and 15.15 percent. So the 14.85 percent number that Dr. Neri talked about, flowing from the federal government's forecast, is in that range. MR. PULLIAM emphasized that the premium has been low for the last five years. The 10-year Treasury bond has been only 1 percent or so above inflation. If it did stay in that low range, potentially the equity return would be below 14 percent. But he'd expect it to be higher in the future. 2:17:38 PM MR. PULLIAM paraphrased slide 38, a continuation of "Key Elements of Recourse Rate Tariff," which said: - Depreciation will be on straight-line basis over 25 years (i.e., 4% per year) - Operating costs, income and other taxes are passed on to shippers - Fuel gas will be recovered from shippers based on actual pipeline losses - 4.40% GTP - 2.15% Alaska & Yukon-BC Sections - 0.90% Alberta Section - Shippers retain title to natural gas liquids entrained in the gas and are free to dispose (i.e., sell or process them as they see fit) MR. PULLIAM emphasized that, particularly in the negotiated setting, these items are all open for negotiation. And even if there's a formula that TransCanada would like to take to FERC, it doesn't mean FERC would approve it. Noting that the costs passed on to shippers, including fuel, had been discussed earlier, he also said shippers are free to dispose of or process the NGLs once those are in AECO. 2:19:27 PM MR. PULLIAM addressed slide 39, "Negotiated Rate Tariffs," which had the following points: - Most new pipeline construction works off negotiated tariffs - TransCanada proposes to offer 25, 30 and 35-year negotiated tariffs - TransCanada proposes that its negotiated rates would incorporate: - Levelized tariff - 70% debt / 30% equity capital structure through date of operation, falling to a 75% debt / 25% equity capitalization for period of operation - Expansions would be 60% debt / 40% equity structure - Equity and Debt rates proposed are the same as for recourse rates (i.e., 965 basis points over cost of 10-year T-Bond and actual debt costs) - Return on Equity reduction offered for negotiated rates - In addition, TransCanada proposes to use U.S. loan guarantees to finance cost overruns if available MR. PULLIAM added that negotiated rates will likely be a big part. TransCanada is offering these terms, at least initially; it doesn't mean shippers must accept them. He clarified that the debt-to-equity ratio shifts after construction is complete. He indicated the reduction in the rates for return on equity is offered in case of cost overruns, at least for the first five years of the tariff; the U.S. loan guarantees would be used to finance cost overruns as well, if available. 2:21:09 PM MR. PULLIAM summarized slide 40, a continuation of "Negotiated Rate Tariffs," which said: - Shipper must agree to accept treatment of rolled-in rates under Alaska Gasline Inducement Act (AGIA) - Shipper must agree not to seek or support changes to the economic parameters that underpin the negotiated rate design at FERC and NEB - Notwithstanding the terms offered by TransCanada, the actual terms to be negotiated between shippers and TransCanada, with the exception of those mandated under AGIA, such as treatment of rolled-in rates, are open for negotiation - There is no requirement to accept the economic parameters proposed by TransCanada. Shipper can bargain for lower rates, increased flexibility, and alternative vehicles for protection against cost overruns than those offered - See earlier differences in Recourse and Negotiated Rates - TransCanada proposes to offer equity ownership in the pipeline "Anchor" shippers who subscribe in the initial Open Season MR. PULLIAM, with respect to the second point, said the shippers must agree not to go back on the rates they've negotiated. On the last point, he said TransCanada has nothing more broad in its proposal with regard to how much it is willing to offer. 2:22:15 PM REPRESENTATIVE SAMUELS said if a shipper has 20 percent of the gas and bids 20 percent of the FT in the line, TransCanada says it is open to offering to sell 20 percent of the pipe; at the end of the day, there conceivably could be a consortium of Conoco, Exxon, BP, and TransCanada owning the pipe. He asked: Does TransCanada's proposal talk about how that particular entity would be run or whether there'd be three votes, with the shippers controlling the pipeline company? MR. PULLIAM answered that he doesn't see anything in the proposal as to how it would be run, including who would have voting control and so forth, although he surmised it would have to be consistent with the tenets in AGIA. REPRESENTATIVE SAMUELS gave his understanding that there is a presumption of rolled-in tariffs from Congress and FERC, and then AGIA says it is 115 percent that the pipeline entity - no matter who it is - has to follow because TransCanada agreed to it originally. As it is purchased, there'd have to be an agreement saying that the new owner would also agree. He asked: Is that a statutory change, or do they just approach the future governor years from now and say they've changed their minds about the 115 percent and the three big producers now own three- fourths of the pipeline? MR. PULLIAM replied he doesn't know how that would play out, but he suspects the original owner would have to stick with those terms. Although he indicated he believes selling off pieces of the ownership that could have different terms wouldn't be allowed, he noted that a legal question. 2:24:34 PM REPRESENTATIVE WILSON returned to the last point on slide 39: "In addition, TransCanada proposes to use U.S. loan guarantees to finance cost overruns if available." She surmised that's probably not an option right now for cost overruns. MR. PULLIAM replied it's a two-part question. The loan guarantees are available generally for the project, but whether that includes cost overruns is still undecided within the federal government; it's something TransCanada would like. Second, with respect to "if available," he also means if there is a desire to have those funds available for cost overruns, then building the pipeline based on anticipated costs will require using nonguaranteed funds in place of those. REPRESENTATIVE WILSON asked whether Congress would have to decide that. MR. PULLIAM opined that perhaps the U.S. Department of Treasury could handle it without congressional intervention, though he wasn't sure. 2:26:20 PM MR. PULLIAM showed the first of six slides labeled "Incentive Adjustments to Return on Equity." Slide 41 was a graph that specified it assumes 75% debt / 25% equity. He noted the line across the top tracks the 14 percent return on equity discussed in the proposal. If one assumes that 965 basis points above the T-bonds gives 14 percent over time, the return looks like this without any of the incentives TransCanada has offered. Below it depicts different capital cost projections in 2008 dollars. MR. PULLIAM explained that TransCanada proposes to reduce its rate of return for the first five years of operation. For every percentage increase above the cost that TransCanada estimates at the time of certification, the company would decrease its return by 5 basis points. If, for example, the baseline for costs is $25.8 billion at the point of certification and then overruns are 10 percent, the return would be reduced by 0.5 percent or 50 basis points. 2:28:04 PM REPRESENTATIVE SAMUELS asked: Would TransCanada make 14 percent up to the $25 billion in this example, and then on the next dollar spent get a smaller rate of return but still make money, so that the more it costs, the more the company makes? MR. PULLIAM responded that there'd be examples with specific dollar amounts, but to his understanding the return on the overall amount would be reduced at least for the first five years. It wouldn't just be the increment over the $25.8 billion; the overall equity return would be reduced by half a point. If it went 40 percent over budget, the return would drop to 12 percent overall. This applies the first five years of construction; then the return goes back to 14 percent. MR. PULLIAM discussed slide 42, a similar graph. He noted it shows what happens over the 25-year period. As overruns go up, the result is a blended rate that comes down and approaches something a little over 13.5 percent with a cost overrun as high as 40 percent. This is the effective rate that results from including the incentive portion for the first five years and then going back to the standard rate beyond that. He suggested thinking of a weighted average that falls in between the two. MR. PULLIAM spoke about slides 43-46, pointing out that profits increase as capital goes up with non-incentive rates at a fixed rate of return, since equity is 25 percent of total capital. If there are just incentive rates and a reduction to 12 percent, profits still go up as capital increases, but less quickly; at 40 percent the rate levels off. MR. PULLIAM said with the blending of the two over time, there is increased profit as capital goes up, although at a lower rate than the non-incentive rate. Slides 44-46 had this note: "TransCanada proposes to reduce its allowed return on equity by up to 200 basis points (2%) over first 5 years in the event of cost overruns." 2:32:31 PM MR. PULLIAM addressed slide 47, "Potential to Use Government guaranteed loans to cover potential overruns," which said: - TransCanada proposes to use Government guaranteed loans to cover potential overruns - $18 billion made available in $2004 - Would be approximately $20 billion in $2008 - Assuming 75% debt financing overall, a project of $26.8 billion ($2008) would absorb the full guarantee amount - TransCanada's proposal amounts to $25.8 billion ($2008) - Accordingly, reservation of Government guaranteed loans for any significant cost overruns would require use of more expensive non-guaranteed debt MR. PULLIAM noted the guarantees amount to $20 billion in 2008 dollars, which at 75 percent debt supports a project of $26.8 billion. Since TransCanada's proposal is for $25.8 billion, reserving a portion for cost overruns requires using non- guaranteed debt for the initial capitalization of the pipeline. 2:33:30 PM REPRESENTATIVE LeDOUX asked: Can this deal happen without using the government-guaranteed loans to cover potential overruns? MR. PULLIAM answered that the government loans are helpful to the project, although from what he's seen - based on current gas price projections and tariff costs with/without those guarantees - they aren't the linchpin. They serve to reduce the tariff and make it more economic. REPRESENTATIVE LeDOUX asked whether Mr. Pulliam was saying it's not actually part of the deal. MR. PULLIAM replied part of the proposal is to use those loan guarantees. However, it is a little unclear in the proposal whether those will be reserved for cost overruns or used in the initial pipeline construction. REPRESENTATIVE LeDOUX asked: Are those loan guarantees in law now? If TransCanada applies for them, will it get them? MR. PULLIAM answered yes, as long as TransCanada meets the conditions set forth in the legislation. 2:35:50 PM MR. PULLIAM, in response to Chair Huggins, explained that the non-guaranteed debt will have a higher interest rate. Most of the pipeline is debt-financed. At higher interest rates, the financing costs will be higher on the biggest portion of the pipeline. Ultimately, the regulators will allow those higher interest rates to be passed through in the form of a tariff. REPRESENTATIVE SAMUELS gave his understanding that if the guarantees are used on the front end, capital costs can be reduced but there's nothing left for overruns. But if it's saved for overruns, capital is higher but it isn't known what the overruns will be and thus it might be wasted. MR. PULLIAM surmised that any amount which hadn't been used for cost overruns could be applied later on. 2:36:40 PM REPRESENTATIVE DOOGAN asked: If the government guarantee goes to loans for initial financing and then there are cost overruns, how would those typically be financed? MR. PULLIAM replied they could be financed either by increased borrowing or by putting equity capital in. If someone proposes a certain capital structure for debt and equity and has targeted 75 percent, presumably it will continue to be funded at that same rate as costs go up. Someone could instead seek to fund it over time, however, using different percentages. REPRESENTATIVE DOOGAN said in this example it's more expensive money across the board, because it isn't government-guaranteed; those funds would have already been used. MR. PULLIAM concurred, saying he'd assume the company would try to use as much of the government-guaranteed money as possible; there's only a certain amount. 2:38:51 PM REPRESENTATIVE HAWKER gave his understanding that although these guaranteed loans are available, the process to obtain them is fairly lengthy, complex, and uncertain. MR. PULLIAM responded that he isn't familiar with the entire process, believes it is lengthy and requires a lot of certification, and doesn't know whether there is uncertainty with respect to how they're used. SENATOR WILKIN asked about two incentives he'd heard about in Anchorage last week to minimize cost overruns: 1) the return on equity shown here that seems to cost some $3 billion for a 40 percent overrun and 2) one related to federal corporate income tax and a deduction or surcharge. MR. PULLIAM indicated he hadn't been in Anchorage and didn't know. In response to Senator Therriault, he said the loan guarantee amount will continue to grow until used. If project costs grow with the rate of inflation, the relationships all stay the same. The administration's projected costs are at a higher growth rate than general inflation, however, more like 4 percent, whereas the loan guarantees are indexed to the general rate of inflation. 2:41:28 PM SENATOR THERRIAULT asked whether Mr. Pulliam's calculations accounted for that. MR. PULLIAM replied he'd shown these in 2008 dollars to try to maintain an apples-to-apples basis as much as possible. SENATOR WIELECHOWSKI asked if pipeline companies typically have tremendous cost overruns or if some factor keeps those down. MR. PULLIAM answered that, first, the shippers are highly sensitive to costs, and in the regulatory process they'll try to ensure that the costs which are ultimately approved are reasonable and prudent; the regulators are charged with that. Second, in negotiating rates, shippers can anticipate and negotiate terms about how overruns will be treated. They may embrace something like TransCanada has talked about, require something more stringent, or have different terms. DR. NERI concurred. CHAIR HUGGINS highlighted the importance of understanding the process for the federal loan guarantees, including what triggers them, what the procedure is, and how long it takes. 2:44:00 PM REPRESENTATIVE SAMUELS agreed. Following up on Senator Wielechowski's question, he posed a topic for the roundtable discussion: Is the negotiated rate the incentive, in large part, in a normal pipeline to keep cost overruns down? He surmised there'd only be a certain parameter that the negotiation allowed one to go up to, and then it would be on the pipeline company. MR. PULLIAM suggested an analogy where someone has negotiated with a contractor to build a house. REPRESENTATIVE SAMUELS surmised that person would absorb some of the risk. The only difference would be that this is a $30 billion or $40 billion project, and the risk from cost overruns accelerates quickly because of the size of the project. MR. PULLIAM concurred. He turned to slide 48, also labeled "Potential to Use Government Guaranteed Loan for Cost Overruns," a chart with the following columns: total capital in 2008 dollars; overrun; amount of debt at 75 percent debt/equity ratio; amount of loan guarantee in 2008 dollars; non-guaranteed debt; and average debt rate by percentage. MR. PULLIAM said this shows what is available from the federal government and how it would look at different capital-cost levels. He indicated if cost projections were as TransCanada proposed, $25.8 billion in 2008 dollars with no overrun, it would be as shown: debt at $19.4 billion, the loan guarantee at $20.1 billion, zero non-guaranteed debt, and an average debt rate of 4.7 percent. MR. PULLIAM added that if costs go up, the guaranteed amount doesn't go up, but the required debt does in order to keep the debt-to-equity ratio. If it costs more, it can be termed an overrun or just "higher capital." At 50 percent more, about $39 billion total, $29 billion in debt would be required; one- third or $9 billion would be non-guaranteed funds. Using TransCanada's spreads, this would raise the average debt cost by about 0.5 percent. 2:47:16 PM REPRESENTATIVE JOHNSON highlighted slide 6, "What Does TransCanada Ask From the State?" He drew attention to the following point: "Cooperation of State in efforts with the Federal Government to obtain support for project - Use of loan guarantees for cost overruns." He asked: Does the state have any cost-overrun responsibility under the proposal? And if we say yes to this, would the state have to provide a guarantee for those, above and beyond what the federal government does? MR. PULLIAM gave his understanding that this refers to use of the federal guarantees, not a state guarantee. 2:48:09 PM MR. PULLIAM showed slide 49, "Sensitivities," which said: As discussed above, capital costs are the biggest driver of costs. The critical elements are: - Overall Capital - Capitalization (i.e., Debt/Equity) - Debt Cost - Return on Equity MR. PULLIAM specified that capital costs will be the biggest costs in the tariff. Overall capitalization - what the debt costs and the return on equity - is important in the tariff as well. Slides 50-52 would show sensitivities, how the tariff would change under different assumptions relative to what TransCanada has put into its baseline tariff assumption. MR. PULLIAM showed slide 50, "Tariffs ($/MMBtu)," a chart with the following note: "Base tariff is per TransCanada assumptions re: costs, capital state and financing (i.e., $25.8bn, 75% debt / 25% equity, 4.7-6.2% debt cost, 14% return on equity)." He indicated the vertical line in the middle represents $2.41, the number from TransCanada's proposal. The graph depicts what happens to the tariff if various factors are increased or decreased by a certain percentage. MR. PULLIAM pointed out that debt is the biggest part of the capital. The tariff is sensitive to debt costs; if debt is reduced by 1 percent, the tariff drops about 12 cents, for instance. Return on equity is a little less sensitive because there is less equity in the proposal, 25 percent. There'd be a movement of 5 or 6 cents either way on the equity piece; that is relative to a 14 percent return. MR. PULLIAM showed slide 51, "Estimated State Revenues (Billion $)," a chart with the following note: "Base ($226.9bn) is per TransCanada assumptions re: costs, capital state and financing (i.e., $25.8bn, 75% debt / 25% equity, 4.7-6.2% debt cost, 14% return on equity)." MR. PULLIAM said this shows the projected impact on state revenues, generally following the same pattern. Capital costs are the more sensitive. These are nominal dollars expressed over 25 years. The debt ratio is a little lower and debt costs are somewhere between the two. SENATOR THERRIAULT remarked that this shows why it was important that the state's desired debt-to-equity ratio be a "must have." This shows the impact on the return. He said FERC will allow a debt-to-equity ratio within what it calls a "zone of reasonableness." He recalled that for the Rockies Express Pipeline this was 55/45. SENATOR THERRIAULT said if the State of Alaska allowed that kind of spread and there was a lot more equity, there'd be a tremendous impact to the state. He asked why Mr. Pulliam had chosen just a +5/-5 percent range here. MR. PULLIAM replied this is for illustration, how it would move over a relatively small range of 5 percent. It certainly could be expanded to show much larger ranges. With movement of 25 percent, the bar on the chart would be commensurate. SENATOR THERRIAULT surmised proposals outside of AGIA that want higher equity could have a sizable impact on the state's earnings. MR. PULLIAM agreed. He said these are more like changes on the margin. But they could be run with wider sensitivities. 2:52:44 PM MR. PULLIAM showed the final chart on sensitivities, slide 52, "Estimated Shipper Revenues (Billion $)," which had the following note: "Base ($122.5bn) is per TransCanada assumptions re: costs, capital state and financing (i.e., $25.8bn, 75% debt / 25% equity, 4.7-6.2% debt cost, 14% return on equity)." MR. PULLIAM said these again are nominal dollars. The pattern is similar to what was seen earlier, although the sensitivity range is a little narrower for shippers because the forecast under the current system shows more total dollars flowing to the State of Alaska than to the shippers. REPRESENTATIVE DOOGAN referred to the timeline on slide 4 and asked when the tariff rates will be set. MR. PULLIAM answered that he believes the initial tariffs will be set at the point of certification to build the pipeline. REPRESENTATIVE DOOGAN asked whether that applies whether there are recourse rates or negotiated rates for the tariffs. 2:54:45 PM MR. PULLIAM suggested Dr. Neri might comment, but said it's subject to what those terms provide. For instance, capital may end up being higher or lower than what is set forth. If it's higher, for instance, then the actual per-unit tariff could be higher than what is there at the certification point. But the methodology at least, what goes into those rates, would be set at that point of certification. REPRESENTATIVE DOOGAN asked: Will there be another tariff- setting procedure at the end of construction? DR. NERI answered that generally when FERC grants a certificate to construct a pipeline, especially for recourse rates, one certificate condition is that the pipeline at some point - usually three years later - come in and justify the rates, document costs, and maybe even file a rate case. So there's usually a three-year review by FERC of the cost and the rates. REPRESENTATIVE DOOGAN asked: If a pipeline company is trying to get commitments at an open season, does it have to be able to predict at least the initial rates? DR. NERI replied that during the open season, in the open season documents, the pipeline will indicate what it thinks the rate will be. Potential shippers will submit bids. After the open season, if the pipeline decides to file its certificate, it will have more information and will, in the certificate application, file for rates to be charged to the shippers. If those rates are approved by FERC, they'll go into effect. REPRESENTATIVE DOOGAN asked whether there could be three sets of rates, then: the rates at the open season, the rates at certification, and then the rates upon completion. DR. NERI replied no. The rates at certification would go into effect. But, as part of the certificate condition, FERC generally requires pipelines to come in three years later to justify the rates that were approved in the certificate. REPRESENTATIVE DOOGAN asked: If there were significant cost overruns between the time of certification and completion, how would those be handled in the rate making? MR. PULLIAM responded if capital costs were higher than anticipated, he believes in the initial certification process the company would apply to have a certain return on capital that would then apply to the higher capital base. It would be those rates that go into effect. That would be reviewable three years or so after the pipeline began operation, when the pipeline would have to justify those rates. 2:59:01 PM MR. PULLIAM discussed slides 53-55, "Expansion Issues," which listed the following points: - Expansion of pipeline capacity would occur either via addition of compression, or through looping (i.e., additional pipeline) - TransCanada estimates that expansion up to 5.9 bcf/day (30% increase) could occur through the addition of compression - Expansions between 5.9 bcf/day and 6.5 bcf/day would occur through either compression or looping - Looping involves adding parallel pipeline sections along a portion of the main line - Beyond 6.5 bcf/day, expansion could occur up to 7.2 bcf/day through looping - AGIA requires TransCanada to study demand for expansion every two years and offer non-binding Open Seasons if demand is warranted - AGIA also requires TransCanada to offer "rolled-in" rates as long as they do not result in increase over original rates by more than 15% (i.e., 115% of original rates) - Rolled-in rates mean that the costs of the expansion "rolled-in" with the original costs and the total is spread out over total volumes - This could result in higher or lower rates for original shippers depending on the cost of the expansion - The alternative is incremental rates for expansion. Under incremental pricing, the shipper[s] for the expansion capacity bear the entire cost of the expansion. Again, this could be lower or higher than the original rates MR. PULLIAM noted that expansions were addressed earlier as well. He specified that the 30 percent increase in the second bullet point is 30 percent over the 4.5 initial throughput. With rolled-in rates, both the initial shippers and the expansion shippers pay on the same basis. MR. PULLIAM, in response to Senator Green, gave his understanding that the 115 percent applies to the initial rate. As the pipeline expands to about 5.9 Bcf/day, rates likely would decrease; compression would be added, and the initial costs would be spread over a higher volume. There could be a situation wherein an expansion after that leads to an increase over those lower rates. 3:01:55 PM REPRESENTATIVE SAMUELS posed an example with an initial rate of $3.00. There is compression expansion and the rate drops to $2.50. Anadarko comes in and bids $2.50 for its gas, and everyone pays $2.50. Then there's an expansion with looping, and the rate rises to $3.25. He asked whether Anadarko would be on the hook for 15 percent above $2.50 or above $3.00. MR. PULLIAM gave his understanding that it would be relative to the initial rate, up to 15 percent above $3.00. REPRESENTATIVE SAMUELS suggested also asking the administration and TransCanada what their understanding is. He said Anadarko in this instance could sign up at $2.50 and go to $3.45, 15 percent above a rate that Anadarko hadn't agreed to ever, the $3.00 rate. MR. PULLIAM affirmed that as his understanding from what he'd read and seen presented thus far. Returning to the slides, he said rolled-in rates can lead to higher or lower rates for initial shippers, depending on the cost of the expansion. The alternative is incremental rates in which expansion shippers pay the entire cost of expansion; this could be higher or lower than the original rates, depending on how efficient the expansion is. MR. PULLIAM showed slide 56, "Example of Rolled-In Rate Treatment," a bar graph showing how rolled-in rates could either lower or raise rates for initial shippers. He specified that it wasn't based on the proposal. MR. PULLIAM noted if there were initial tariffs of $2.00 and an incremental expansion with relatively low-cost compression, it would result in $1.50 on the incremental volume to support that expansion; rolling that in leads to a lower average rate for everyone. Conversely, if the expansion was relatively costly so it went up to $2.50, then rolling the higher expansion cost in would result in a higher tariff for everyone. 3:04:38 PM REPRESENTATIVE GATTO asked what happens if the amount of gas available to put in the pipeline keeps dropping. There'd be a commitment that someone wouldn't have to pay more than 15 percent above the base rate. But the rate would start to climb for everyone if less gas were in the pipe. He asked: Under that scenario, how do you prevent the rate from climbing above the initial rate? MR. PULLIAM replied that's a different risk issue. That's why there are transportation commitments to begin with. Shippers will agree to put a certain amount of gas in; if they don't ship that amount of gas, they'll pay as if they did. 3:05:43 PM SENATOR THOMAS observed that the gas treatment plant wasn't mentioned here and asked: If the GTP is built for 4.5 Bcf/day and then the line expands to 7.2 Bcf/day, what impact does that have and how does it affect the tariff? He suggested there might be a huge capital cost for the GTP in that instance, depending on who owns it. MR. PULLIAM said that's a good question. TransCanada's proposal doesn't include a scenario for expanding the GTP. He said engineering for the GTP is a out of his area of expertise, but the gas would have to be conditioned in some way, either from adding to the central GTP facility or perhaps through constructing small facilities to address incremental volumes. As to which would be most efficient, he didn't know. SENATOR THERRIAULT asked Mr. Pulliam why he'd stopped the expansion through looping at 7.2 Bcf/day. He surmised if it were still cost-competitive, someone could lay pipe to get around bottlenecks or have parallel lines. MR. PULLIAM answered that it matched with estimates in TransCanada's proposal, which ran the numbers up to 7.2 Bcf/day. As to how efficient it is to loop beyond that, he wasn't sure. 3:08:20 PM SENATOR WIELECHOWSKI recalled for the base pipeline the debt-to- equity ratio is 70/30 under AGIA, but for expansions TransCanada wants 60/40. He asked: What economic impact does that have if it's up to 6.5 or 7.2 Bcf/day and there's a 44 percent increase, changing that ratio from 70/30 to 60/40? He surmised it would be significant. MR. PULLIAM answered it would have the effect of raising capital costs on a per-unit basis, though he wasn't sure how significant it would be. SENATOR WIELECHOWSKI suggested it would be a loss of billions of dollars to the state. MR. PULLIAM replied that relative to using a 70/30 ratio, depending on how big the expansion is, it could be billions. However, the value of having the expansion would, in itself, be a big benefit to the state. If it could be done on a 70/30 basis, though, and was a significant expansion, that difference could be quite valuable to the state. 3:09:52 PM MR. PULLIAM discussed slide 57, also labeled "Expansion Issues," which had a graph and the following points: - TransCanada estimates that expansions up to 6.5 bcf/day (44% increase in capacity) would reduce rates on a rolled-in basis - At 7.2 bcf/day, TransCanada estimates that rolled-in treatment of expansions could increase rates (depending on timing of expansions(s)), but by less than the 15% threshold MR. PULLIAM said the graph shows what TransCanada anticipates at different expansion levels. A horizontal line shows 115 percent of the initial tariff. The figures refer to pipeline tariffs, not the GTP. He noted TransCanada predicts expansions generally would reduce the tariff, inclusive of fuel, up to about 6.5 Bcf/day. It would start to increase as looping begins. MR. PULLIAM added that the administration has done some of this modeling as well and has verified in general, to his belief, the manner in which the pipe would be expanded, though the patterns look a bit different from this, with some increase seen at a lower level. In the end, the 115 percent level isn't approached - at least with current projections - at any of these kinds of expansions. Moving from 4.5 to 7.2 Bcf/day is a fairly large expansion, more than 50 percent, over the initial capacity. 3:12:06 PM MR. PULLIAM discussed slide 58, also labeled "Expansion Issues," which had the following points: - If TransCanada estimates are correct, existing shippers would be expected to be supportive of rolled-in treatment up to 6.5 bcf/day. Beyond that, they would rather see incremental pricing - This could differ depending on the position of the party seeking the expansion. If it is an existing shipper, it may still favor rolled-in treatment above 6.5 bcf/day depending on how much existing capacity it has relative to the amount of incremental capacity it is seeking - For example, if a shipper had 10% of the original capacity, but was going to have 100% of the expansion capacity, then it would likely favor rolled-in treatment even if it raised the cost for it[s] original capacity - This is because it can spread the costs of the incremental (relatively expensive expansion) across others' volumes - Neither FERC nor NEB are required to accept rolled- in treatment of rates as required by AGIA, though FERC has stated that there will be a presumption of rolled-in treatment MR. PULLIAM added, with respect to different positions of parties, that it would depend on a shipper's mix of gas as well as how much initial capacity that shipper has relative to the expansion capacity. The FERC presumption of rolled-in treatment is rebuttable; the pipeline or shippers could present evidence that it should be done on an incremental basis instead. 3:13:47 PM MR. PULLIAM summarized slide 59, "In-State Tariffs," which said: - TransCanada has proposed offering at least 5 in- state "off-take" locations, one of which would accommodate a "spur" line to the Anchorage area - In-State Study before Open Season - Tariffs would be offered on distance sensitive basis, with a single "zonal" rate offered for all Alaska off-take locations - Rates to the different locations would be calculated based on their relative distances to the total Alaska section, then a weighted average rate would be applied to all off-take in Alaska MR. PULLIAM added that the in-state study is consistent with AGIA. In response to Representative LeDoux, he specified that TransCanada proposes to do a study of demand for gas within the state and make that available before the open season. Thus folks would have a sense of gas requirements in Alaska. MR. PULLIAM said the final chart, slide 60, also labeled "In- State Tariffs," is a simplified version with off-take locations at 200, 300, and 500 miles and examples of off-take volumes; the overall rate to the border is $1.00 per Mcf and the distance is 800 miles. Total cost is allocated based on the distance to each location and the weighted volume coming off each. MR. PULLIAM said while it is relatively cheap to serve location A and more expensive for location C, those are weighted together. In this case, the average distance is 52.5 percent of the distance to Canada, so the rate is 52.5 percent of the total rate to Canada. 3:16:00 PM REPRESENTATIVE HAWKER remarked that philosophically he can see certain simplicities in having a single-zone tariff for all of Alaska. But he asked why folks taking gas off at the Yukon River should subsidize shipping gas all the way to the Kenai, for instance, and why Fairbanks residents should subsidize gas going to LNG or urea plants further south. MR. PULLIAM replied he thinks it boils down to administrative ease and simplicity. Ultimately, there'll be a balancing between equity and administrative ease, which often is one of the tensions in the regulatory process. The postage-stamp type of rate provides that administrative ease. 3:17:18 PM REPRESENTATIVE LeDOUX asked whether it's correct that this TransCanada proposal won't work unless the producers agree in the open season to ship their gas. MR. PULLIAM answered that a pipeline to commercialize the gas has certainly got to have gas in it. Right now, that gas is controlled by producers under the leases they have. There has to be some way for that gas to get into the system, either by agreement or coercion or some process. REPRESENTATIVE LeDOUX asked: Why is or isn't TransCanada's proposal better than what the producers have proposed under the name Denali? REPRESENTATIVE SAMUELS suggested moving forward, rather than beginning the debate that will occur over the next two months. Legislators would hear five days of presentations from the administration and TransCanada on why they believe this is the best path to monetize North Slope gas. He pointed out that the process was set up so the LB&A consultants could highlight questions for legislators to ask and what to look for. MR. DICKINSON noted there's a general PowerPoint slide presentation on the Denali website, but there are thousands of pages on the TransCanada proposal. Any comparison will suffer as a result. The committees took an at-ease from 3:21:10 PM to 3:39:10 PM. 3:39:32 PM MS. ADAIR gave her background, saying she's a chemical engineer by training and a registered professional engineer in Texas and Oklahoma; she indicated she also has a master's of business administration (MBA) from Southern Methodist University (SMU). She has designed pipelines, gas-processing facilities, and so on. In her day-to-day job, she looks at issues where the technical part of the energy industry collides with economics. She does work on due diligence for financing and lots of work on damages, contract disputes and negotiations, and so on. 3:40:57 PM MS. ADAIR began her presentation, "Financial Assessment of the Impact of the Alaska Gas Pipeline," which was duplicated in a handout. She showed slide 2, "Key Study Aspects," which said: - Financial Analysis of the Alaska Gas Pipeline Project from the perspective of TransCanada and Producer Project - Assessment of the future performance of TransCanada's Canadian gas assets in two cases, With and Without Alaska Gas Supply - High-level overview other TransCanada assets - Evaluation of supply and demand/competition issues in North America that may impact the TransCanada pipeline assets - Evaluation of impact of the Alaska gas on TransCanada's future earnings MS. ADAIR noted that, for the most part, Muse Stancil has taken base-case forecasts of the pipeline, rather than doing an analysis of TransCanada's proposal or an independent analysis of the pipeline. The effort has been to put this project in the context of the environment in which it will function; to address how the pipeline will affect TransCanada's assets; to discuss issues that may impact TransCanada's pipeline assets on the North American front; and to look at the impact of the Alaska gas pipeline on TransCanada's future earnings as a corporation. 3:42:13 PM MS. ADAIR showed slides 3-4, "Financial Analysis of the Alaska Gas Pipeline," which had the following points: Assess the investment philosophy, asset portfolio, and financial structure of potential owner companies - TransCanada - Producer Project Owner - ConocoPhillips (COP) - British Petroleum (BP) Assess the risk/reward and potential return of the investment in the pipeline project - Assuming certain percentage of firm transportation (FT) committed before investment - Assuming no FT commitment until year 2 of operations - Assuming all FT sold prior to initial construction Evaluate the potential investment in the Alaska Pipeline Project in the context of each company's investment philosophy, asset portfolio, and financial structure - Assess how investing in the project could impact each company's financial stability - Assess the project in light of other likely alternative project investments available to the companies MS. ADAIR explained that for the analysis of the pipeline from the perspective of the marketplace, Muse Stancil was asked to talk about how the companies differ that ultimately may be owner-operators. Muse Stancil was contracted before the Denali project was announced; ConocoPhillips and BP were added as specific companies following that, instead of the generic producer project owner intended originally. 3:43:01 PM MS. ADAIR said everything she would show is publicly available information obtained from annual reports, stock analyst reports, and so on. MS. ADAIR discussed slides 5-6, "TransCanada." Slide 5 was a map of Canada and the U.S. depicting gas storage, power plants, wholly owned pipelines, and affiliated pipelines. She said TransCanada has a vast footprint in North America, including a lot of power generation; it is an integrated energy company, at least on the gas side. Slide 6 had the following points: Corporate Vision and Investment Philosophy - Become the leading energy infrastructure company in North America - Deliver strong financial performance - Maximize corporate financial flexibility - Execute on the current portfolio of large, attractive projects and initiatives - Create and cultivate a high-quality portfolio of future growth opportunities Asset Portfolio - Natural Gas Transportation - 36,500 miles of wholly-owned pipelines connecting North American gas producing basins to downstream markets - 15 billion cubic feet per day (Bcf/d) of natural gas transported in 2007 - Natural Gas Storage - 355 billion cubic feet (Bcf) of storage capacity - Crude Oil Transportation - Keystone Pipeline Project linking growing Canadian oil sands supplies with refineries in the U.S. Midwest - New build, plus conversion of underutilized Mainline capacity - Power Generation - Assets in Canada and the U.S. - Diverse portfolio of nuclear, natural gas, coal, hydro, and wind - LNG - Two LNG import terminals in the development phase - Quebec location on the St. Lawrence River - New York State in Long Island Sound - Marketing 3:44:00 PM MS. ADAIR said she believes this came from TransCanada's latest annual report. The company's focus is on the midstream sector, providing services to producers and people who buy gas all over North America; it also cares about its shareholders. In the past three years or so TransCanada has grown quite a bit, based on projects it has identified and executed as well as acquisitions in the marketplace. The Alaska gas pipeline project is a great growth opportunity for the company. MS. ADAIR, with respect to TransCanada's assets, added that the natural gas storage capacity is primarily in Canada, but also is affiliated with the ANR Pipeline system that it owns in the Lower 48. TransCanada is just beginning to enter the crude oil side; the conversion of underutilized mainline capacity refers to converting lines in Canada to oil. Diverse power generation assets are primarily in Alberta and Northeastern U.S. She mentioned the LNG projects and also said the marketing relates to TransCanada's unregulated assets. 3:47:06 PM MS. ADAIR addressed slides 7-8, also labeled "TransCanada," noting this information came from stock reports and what they'd seen in TransCanada's annual report. Slides 7-8 said, with a few details omitted: Key Facets of Current Portfolio - Planned investment of approximately $10 billion in a number of energy infrastructure projects currently under construction throughout North America - Pipeline Segment - Approximately $5.3 billion of committed capital projects - Alberta System's North Central Corridor - Keystone Oil Pipeline - Energy Segment - Plan to invest more than $4.6 billion in a variety of projects Future Investments Criteria - Select only the very best opportunities and move those initiatives forward - Build on existing large and attractive portfolio of projects and investment opportunities in the Pipeline and Energy Segments - Cultivate a portfolio that provides the opportunity to reinvest substantial discretionary cash flow into opportunities in natural gas and crude oil pipelines, power generation facilities, natural gas storage, and LNG terminals - Capitalize on North America's increasing demand for cleaner and more efficient energy - Continue to deliver strong and sustainable financial returns to shareholders MS. ADAIR added that in Alberta, TransCanada is doing pipeline expansion and looping in the north central corridor. The Keystone oil pipeline is a joint venture with ConocoPhillips. As for the energy segment, this is power generation as well as LNG and gas storage. MS. ADAIR explained that for future investments, TransCanada is looking for opportunities in sectors that grow the businesses the company already participates in or that are adjacent to those; TransCanada wants to explore its core competencies in ways that meet criteria in terms of increasing demand for cleaner and more efficient energy in North America. And the company wants to continue to deliver strong and sustainable financial returns for its shareholders. 3:48:55 PM MS. ADAIR turned to slide 9, which had a graph of TransCanada's long-term debt in U.S. dollars and the following points: Financial Structure - Current Market Capitalization, $23 billion - Long-term debt as of March 31, 2008, $13 billion - Detailed 2007 Financial Performance analysis located in Appendix REPRESENTATIVE RAMRAS recalled during the legislative session TransCanada executed a $2.8 billion power-generation transaction. He opined that equity markets generally discourage large companies that deviate from their primary business. He asked whether Muse Stancil had analyzed that transaction and, if so, whether the market had rewarded TransCanada for broadening its energy portfolio. He also asked whether Ms. Adair had any references here to TransCanada's immediate peer group that speaks to its capacity to execute this Alaska project. MS. ADAIR answered no to the last question. As to the first, she surmised he was talking about the Ravenswood project out of New York. She said her information wasn't extensive, but she'd had Muse Stancil's "power guy" look into it. MS. ADAIR opined that one problem with Ravenswood is it's a peaking facility, not utilized 100 percent of the time. It also has reserve or standby payments, to her understanding, to maintain the equipment and have it ready to go; there is some concern as to how long those payments may be available. Furthermore, she believes there's some concern that the acquisition might dilute earnings, at least short term. MS. ADAIR said those are things shareholders don't like to hear, especially when looking at the record for acquisitions, which have been accretive to earnings. She opined that this particular acquisition might have been a momentary blip. She recalled reading and hearing that the company has plans to repower that facility and turn it around. REPRESENTATIVE RAMRAS said his question was relative to the size of the market capitalization of TransCanada and the fact that a $2.8 billion acquisition for Ravenswood was that dilutive, to his understanding. He expressed concern about the scale and TransCanada's ability to execute the Alaska project. MS. ADAIR answered that with respect to this Alaska pipeline, the FT component won't be a function of the company's size; it will relate to the creditworthiness of the parties to the FT contracts. That is what will carry the day on the debt. REPRESENTATIVE RAMRAS asked Ms. Adair to expand her answer with respect to construction risk when it comes to a project between $21 billion and $36 billion, given what he said is FERC's view about risks associated with global Arctic gas projects; that the Trans-Alaska Pipeline System (TAPS) oil pipeline ran 800 percent over budget; and TransCanada's present market capitalization relative to the risk of 50, 100, or 200 percent cost overruns. 3:53:15 PM MS. ADAIR answered with regard to cost overruns that she believes it's a question the legislature and the market in general will have to grapple with. That risk more than likely won't be laid off to an engineer, procure, and construct (EP&C) contractor, at least not completely; it will have to be managed. MS. ADAIR suggested looking at the stock-value market cap of TransCanada at $23 billion and a total enterprise value if the company's long-term debt is added to the market cap of about $36 billion. Compared with the types of overruns talked about - 50 percent on $20 billion - it's a lot of money. MS. ADAIR said, however, that this project is meant to ride on its own merits and not on a parent guarantee of any particular company. So management of construction risk is key to financing the project. The ultimate question is how to manage risks sufficiently to satisfy the debt and equity that must be raised, since TransCanada will have to raise equity to do this. 3:54:36 PM SENATOR WIELECHOWSKI noted the value of the U.S. dollar has plummeted relative to Canadian dollars. He asked whether that has affected any of the numbers shown for TransCanada. MS. ADAIR answered that Muse Stancil tried to do everything in U.S. dollars in order to have an apples-to-apples comparison. She didn't believe it would have any impact because corrections had been done in everything she would show today. 3:55:17 PM REPRESENTATIVE GARDNER asked what is meant by EP&C contractors. MS. ADAIR replied those are the companies that build pipelines, supply equipment, and would put together the project. Usually when there is a turnkey construction contract for a big project, there are penalties associated with missing milestones, certain cost overruns, and so on. The EP&C contractor cannot insure against every possible delay or lay it off on someone else. An example is a delay or cost increase related to regulatory issues. Certain inherent risks to the project rest with those who own it. 3:56:38 PM MS. ADAIR noted TransCanada doubled its debt in the last five years, but also raised equity during this time and almost doubled its net income, as shown on slides 10-12. Those slides had graphs depicting net income by segment, capital expenditures by segment, and capital expenditures and acquisitions. MS. ADAIR highlighted segments of TransCanada's business. She explained that "power" relates to power-generation assets and gas storage, whereas "gas transmission" is specifically pipeline assets. TransCanada has a pretty good distribution between those two segments, moving around a little bit, depending on markets; it isn't highly leveraged in one segment or the other. MS. ADAIR also highlighted a fairly drastic increase in expenditures over time. At least in the last couple of years, she said, spending has focused on the energy sector including wind projects, hydroelectric power, and so on, with less direct spending in the pipeline segment. MS. ADAIR noted there has been significant spending on acquisitions, through which TransCanada has been successfully growing. In 2007 that included acquiring ANR Pipeline - a significant pipeline from the Gulf of Mexico to Midwest markets - and the outstanding interest in Great Lakes Pipeline. In response to a question, she opined that Ravenswood wasn't included here. 3:58:48 PM MS. ADAIR briefly showed slide 13, "Financial Analysis of Potential Owner Companies," which said: Producer Project Owners - ConocoPhillips - British Petroleum MS. ADAIR discussed slides 14-18, "ConocoPhillips Asset Portfolio," which had a map, graphs, and the following points: Exploration activities in 23 counties Production activities in 16 countries - Total 2007 production 2.3 million barrels per oil equivalent day - Including Lukoil and Syncrude Refineries - 12 in the U.S. - 4 in Europe - 1 in Asia - 2007 Refining Capacity 2.7 million barrels per day (MMbp/d) - 2.04 MMbp/d in U.S. - 669 thousand barrels per day (Mbp/d) Internationa[l] As of December 31, 2007: - Third-largest integrated energy company in the U.S. - Market capitalization - Oil and natural gas reserves - Oil and natural gas production - Fourth-largest refiner in the world - Sixth-largest worldwide reserves holder, non- government-controlled company Refined Products Marketing - U.S., Europe, and Malaysia - Phillips 66, Conoco, 76, and JET brands Joint Venture Operations - DCP Midstream in the U.S., 50 percent interest - 63 Natural Gas Processing Plants - 58,000 miles of natural gas gathering - Chevron Phillips Chemical Company, 50 percent Interest - 36 Production Facilities in 7 countries - 6 Research and Technology Centers Corporate Vision and Investment Philosophy - Exercised a consistent, proven investment strategy that balances allocations of cash flow - Grow the asset base - Return capital to shareholders through dividends and share repurchases - Manage debt - Investment allocations are based upon the dynamic industry environment including identification of new investment opportunities - In the recent past, the company has completed key acquisitions and new investments while reducing corporate debt - 2007 Uses of Cash are summarized in the chart below Financial Structure - Current market capitalization, $144 billion - Debt as of March 31, 2008, $22 billion - Long-term debt, $20 billion MS. ADAIR said while TransCanada is primarily a North American service provider with a couple of investments in South America, ConocoPhillips has activities all over the world and is fully integrated in the oil and gas market sectors. It has chemicals investments and a fairly significant investment with DCP Midstream - Duke ConocoPhillips; its 58,000 miles of natural gas gathering is primarily in North America. MS. ADAIR drew attention to statistics for year-end 2007, saying ConocoPhillips is the third-largest integrated energy company in the U.S., looking at factors like market cap, reserves, and production rates. It is the fourth-largest refiner in the world, with 17 refineries, primarily in the U.S. It has a lot of reserves as well. 4:00:14 PM MS. ADAIR referred to recent financial reports and said ConocoPhillips, like any company, wants to grow its asset base. It has been returning capital to shareholders through dividends and share repurchases. When a company buys its own stock back instead of investing in projects, that typically means its board of directors feels its in-house projects and those being cultivated are better than current marketplace opportunities. ConocoPhillips has a pretty significant investment in its own company and projects. MS. ADAIR told members probably the hardest thing for any company right now is to figure out what to do in the current marketplace. Nobody knows if prices will remain at $110 or $120 or whether this is just a blip. Long-term planning is tough. Most big companies have reacted by using oil and gas price forecasts that are significantly lower than the current prices. MS. ADAIR noted ConocoPhillips has done quite a bit in acquisitions and new investments, paying down its debt. It is looking to shore up its balance sheet some. 4:02:08 PM MS. ADAIR highlighted stock value of $144 billion and $22 billion in debt for ConocoPhillips, of which $20 billion is long-term debt. Commensurate with the run-up in oil prices, she said, ConocoPhillips has taken on additional debt, likely to try to find more oil. MS. ADAIR said because ConocoPhillips is such a diverse business, there are lots of segments, including Lukoil, a Russian oil company joint venture. ConocoPhillips's exploration production and income has driven it for the last four years, though it was down a bit in 2007; that happened with many companies as costs finally caught up with runaway oil prices. MS. ADAIR said ConocoPhillips' refining and marketing sector has done well, also seen across the board until this year because it was relatively stable and because relatively low oil price refining margins have been strong as demand for products has increased worldwide. MS. ADAIR noted ConocoPhillips' capital budget for 2007 was about $12 billion, significantly higher than TransCanada's. The bulk of it has been in exploration and production because lots of money must be spent to develop reserves and there are worldwide operations. Some money is being spent on refining and marketing. 4:04:00 PM MS. ADAIR turned attention to BP, slide 19, "BP Worldwide," which had the following points: Exploration activities in 29 countries Over 24,000 service stations worldwide Interest in 17 crude oil refineries Corporate Vision and Investment Philosophy - Continue to support the strong list of projects under development and coming on stream - Newly delineated the business into groups to emphasize the key drivers of the business - Upstream - Downstream - Alternative Energy - Investments in alternative energy to provide a focus on technology to support the existing business as well as the development of the supply of low-carbon energy for the future - Focus on evaluation of long-term strategy given increased oil prices and the trends in the world economy, including the identification of the right opportunities in a challenging marketplace - Cash flows from BP's strong asset base are allowing the company to increase investment in future growth and shareholder dividends - Returning cash to shareholders through dividends and buybacks - Increased the quarterly dividend (March 2008) to 13.525 cents per share, compared with 10.325 cents per share in 2007, a 16 percent increase - $7.5 billion of shares were repurchased for cancellation in 2007 MS. ADAIR indicated while ConocoPhillips is a really big company, BP is huge. Such a company has numerous opportunities presented daily. She said BP recently reorganized its business into upstream, downstream, and alternative energy segments because it believes that investing in the latter could really impact the rest of its business. MS. ADAIR likened BP's thinking to investing in the NASA space program, which results in an enormous amount of technology that provides benefits in many areas. She said BP seems to be trying to figure out ways that the technology in alternative energy can help its upstream and downstream programs and also enhance its balance sheet. MS. ADAIR additionally said that BP speaks to the task of determining what to do in the long term, given the new era of oil prices, and is looking at growing the company, especially with respect to shareholder dividends. That BP also has been buying back its stock is another signal that it has lots of cash, but not as many good projects as desired. 4:05:57 PM MS. ADAIR showed slides 20-21, "BP Worldwide Asset Portfolio," which had the following categories and additional details not listed here: Africa Asia Australasia Europe - London is where BP's corporate headquarters are located, and the UK is, therefore, a center for trading, legal, finance, and other mainstream business functions. The UK is also home to three of BP's major global research and technology groups. North America - Exploration and Production - The BP group is the largest oil and gas producer and one of the largest gasoline retailers in the United States, and has significant natural gas production in Canada - The largest non-U.S. company on the New York Stock Exchange - BP Alternative Energy business operations center - Houston, and solar manufacturing facilities in the U.S. - Canadian activities focus on the production of natural gas and derivatives - Exploration and production work is a core aspect of BP's presence in Trinidad and Tobago - where BP is a major local producer South America MS. ADAIR noted BP has more diversity than ConocoPhillips, with investment in solar manufacturing in India and Australia, exploration and production, doing the Baku-Tbilisi-Ceyhan (BTC) pipeline, and so on; she emphasized the opportunities. In North America, there is lots of exploration and production. Some work has been done in South America, as TransCanada has also done; there BP is doing work related to chemicals and solar projects. 4:06:45 PM MS. ADAIR discussed slide 22, which had a graph labeled "BP Debt" and the following points: Financial Structure - Current Market Capitalization, $228 billion - Debt as of December 31, 2007, $31 billion MS. ADAIR noted the graph shows that the trend over time has been pretty stable, although it rose some in 2007, probably reacting to higher oil prices. MS. ADAIR addressed slides 23-24, graphs labeled "BP Capital Expenditures and Acquisitions" and "BP Operating Segment Profit." She noted that, as seen with ConocoPhillips, BP is mainly an exploration and production company; that's where most of their base revenues come from. They are spending money in those sectors to develop reserves for the long term. MS. ADAIR said BP calculates its net income equivalent a little differently than is done in the U.S. Exploration and production dwarfs other business segments. In particular, BP has had some issues with refining and marketing; surmising many legislators heard about the Texas City incidents and some refining issues, she said BP is hopeful to have those put behind it and is looking for less future spending in those areas. 4:08:08 PM MS. ADAIR discussed slide 25, "Company Financial Comparison," two graphs comparing 2007 capitalization and also the average annual capital expenditures (2003-2007) for TransCanada, ConocoPhillips, and BP. She noted that total capitalization for TransCanada was the least, whereas BP's was highest by far. For capital expenditures (CAPEX), the average over the last five years was used. As shown, BP is spending $15 billion to $16 billion annually in its capital budget. TransCanada's capital expenditures, while far less than the others, have been increasing over the entire timeframe. 4:08:50 PM MS. ADAIR turned to slides 26-27, "Risk/Reward and Potential Project Return," which had the following points: Assuming certain percentage of FT committed before investment - Revenue Risk is reduced, but not eliminated - Some Revenue Upside is lost as a result of likely lower overall negotiated tariff rates for FT shippers - Some Revenue Upside is retained as uncommitted operational capacity may be sold to spot shippers at base tariff rates - Some Capacity Risk may be eliminated depending upon the Project Developer's final technical design relative to overall system FT commitments - The Project Developer still faces significant risks - Construction risk - weather delays, design delays, construction quality issues, material / equipment availability delays, etc. - Capital Cost risk - raw material costs, labor, interest rate risk - Operating Cost risk - depending upon how FT is structured, negotiated rates will leave operational risk with Project Developer - Credit risk that is assessed based upon the creditworthiness of the companies standing behind the FT commitment - Regulatory risk Assuming no FT commitment until year 2 of operations - Not a valid reference case - The pipeline project is not likely to be built without throughput commitments, therefore, the risk is very, very high for any project sponsor looking to proceed with development in this case Assuming all FT sold prior to initial construction - If all of the FT capacity on the system is sold prior to initial construction, revenue risk is mitigated - Capacity risk is reduced as project can be "right- sized" to meet committed market demand with expansion capabilities - The Project Developer still faces significant risks - Construction risk - weather delays, design delays, construction quality issues, material / equipment availability delays, etc. - Capital Cost risk - raw material costs, labor, interest rate risk - Operating Cost risk - depending upon how FT is structured, negotiated rates will leave operational risk with Project Developer - Credit risk that is assessed based upon the creditworthiness of the companies standing behind the FT commitment - Regulatory risk MS. ADAIR elaborated. She said this is Muse Stancil's viewpoint on FT and the Alaska gas pipeline, addressing cases they'd been asked to consider. For the first assumption, that a percentage of the FT is committed before investment, there is revenue risk is for the project owners. The possible loss of some revenue upside is because the negotiated rate will, for the most part, be constant throughout. What is retained is for capacity that hasn't been committed. That can be committed on negotiated rates later or there may be a recourse rate; hopefully it won't go unused. MS. ADAIR said some capacity risk may be eliminated because of the ability to right-size the pipeline; the engineering design may be better because of knowing exactly what the FT commitment will be. That goes into the thinking for expansion as well. However, significant risks still must be dealt with, as listed above. Capital costs carry risk because of inflation. For operating cost risk, the negotiation is really an allocation of that risk on those costs going forward. MS. ADAIR explained that credit risk is assessed based on who signs an FT commitment. The debt holders and, if equity must be raised, the people who'll invest in equity in this project want to be sure that whoever executes those FT contracts can pay, whether they're selling gas or not. Ultimately, that means looking to the producers with significant balance sheets to backstop those FT commitments. MS. ADAIR noted there's ongoing regulatory risk for a pipeline. The regulatory environment is never locked in. For instance, recently there have been pipeline inspection rules about more frequent testing and greater degrees of monitoring, and there are carbon dioxide and greenhouse gas issues. 4:12:18 PM MS. ADAIR turned to the next assumption, no FT commitments when the pipeline is built. Noting she'd sought input from people with lots of experience in this area, Ms. Adair reported that they'd all responded that it's not even a valid reference case; they didn't believe the project would be built without throughput commitments, and therefore the risk would be very, very high for any project sponsor that looks to proceed on a speculation basis. MS. ADAIR spoke about the final assumption, that all the FT is sold before initial construction. She said in that case, revenue risk is pretty much taken care of, assuming a lot of reopeners haven't been negotiated in the contracts. Capacity risk is reduced significantly because the subscribed volumes will be known. Since it will likely be closer to construction, there'll be better reserve estimates and production forecast rates; thus a better design can be done to fit the project to the reserves that the pipeline is meant to service. MS. ADAIR noted the project developer will still have all those other risks discussed before. That doesn't mean the project developer has to carry them all 100 percent, but it is necessary to deal with those and think about how to mitigate them and lay those risks off or allocate them to others in order to have the most financially successful project for the project investors. 4:13:45 PM MS. ADAIR paraphrased slide 28, "Potential Company Investment," which said: Evaluate the potential investment in the Alaska Pipeline Project in the context of each company's investment philosophy, asset portfolio, and financial structure - Assess how investing in the project could impact each company's financial stability - Assess the project in light of other likely alternative project investments available to the companies TransCanada COP BP 4:14:06 PM MS. ADAIR discussed slide 29, "Potential Company Investment - TransCanada," which had the following points: Financial Stability - In the last five years, net income has doubled and the company has been able to take on additional debt, almost doubling long-term debt in the same period - The company has also been able to define and capture new opportunities that have provided a solid foundation for new equity - The "midstream" energy services sector has been in favor with investors - More than 60 percent of TransCanada's equity is held by institutional investors - Favor predictable, stable returns - Favor low risk investments for the majority of their portfolios - Sometimes take on medium to high risk investments, but do so in "small bites" - A project the size of the Alaska Gas Pipeline dwarfs cumulative total TransCanada capital spending in the last 5 years - On a stand-alone basis, at today's market capitalization, taking on this project will be highly leveraging to TransCanada, both positive and negative, in contrast to historical investments - Would likely require raising additional equity - Would likely impact equity returns in the medium-term, dependent upon project timeline and cash funding needs Relative to other TransCanada Investments - Complements existing Canadian gas pipeline and storage assets, owned by TransCanada and others - Long lead time does not provide support for near- to medium-term earnings growth; TransCanada would have to identify, consummate, and execute other projects in the interim - May provide needed infusion of natural gas liquids into Alberta - Supports expected supply shortfall in petrochemical feedstock - May provide some supply to meet heavy crude diluent demand Note: Diluent is pentanes plus NGL used to mix with heavy crude for shipment MS. ADAIR added that TransCanada has been able to capture new opportunities and is growing through acquisition. Investors like the mid-stream sector because of predictable returns for the most part, though there might be projects such as Ravenswood that those sorts of investors aren't happy with. At last check, 60 percent of equity was held by institutional investors, which tend to invest in things like state employee pension funds. MS. ADAIR said the Alaska project is huge relative to what TransCanada has taken on. However, TransCanada has the core competencies in its gas businesses to manage a project like this. If TransCanada were a stand-alone owner-operator for the project today, taking the project on would be highly leveraging to the company. Also, it will have to raise equity, and there's a chance that medium-term equity returns for its shareholders would be affected, depending on the project timeline, cash funding, and details for getting the project off the ground. MS. ADAIR noted this project certainly complements TransCanada's portfolio of Canadian gas pipeline and storage assets. The long lead time could be a problem for the company, depending upon how it's structured, because TransCanada has been adding projects that are accretive to earnings, adding acquisitions, and growing the company. MS. ADAIR said because this project will feed into the TransCanada system, as mentioned this morning, the infusion of NGLs from the Alaska gas will support a couple of issues facing Canadian producers today: petrochemical feedstock and diluent for heavy crude oil. Heavy crude oil can be almost like road tar. To get it to flow in pipelines, it is diluted, usually with "C5" plus heavy NGLs. Having a ready supply could benefit the market in Alberta, depending on quantities available and how much actually makes it that far in the pipeline. 4:18:01 PM REPRESENTATIVE RAMRAS gave an analogy in the hotel business. He asked about the scale of TransCanada's proposed project in relation to its market capitalization, debt, and so on, compared with the relative scale for ConocoPhillips and BP. He asked Ms. Adair to return with a single slide, a one-page recap, to demonstrate risk. MS. ADAIR suggested thinking about increasing the size of any business through finding partners to put in seed money. For instance, if hotel rooms were sold for 10-15 years before commencing a building project, the bank would loan money on it. As long as there are project partners to help put the equity seed money in, she said, the money could probably be borrowed from the bank to do the project. REPRESENTATIVE RAMRAS took issue if the hotel rooms would be sold for a fixed cost, saying there'd be construction risk if his construction cost was unknown. Returning to this project, he surmised this would cause the producers to absorb an inordinate amount of risk that would dampen the environment in which a business transaction could be consummated. 4:21:41 PM MS. ADAIR replied she believes the negotiation of that rate would come into play for the willing buyer or seller. Someone would look at what the market would bear and what partners would be willing to do. Any developer for this project will have to assess how much equity return is needed, how much risk is acceptable, and so forth. It's not a slam-dunk. MS. ADAIR further responded by showing slide 25, "Company Financial Comparison," two graphs comparing 2007 capitalization and also the average annual capital expenditures (2003-2007) for TransCanada, ConocoPhillips, and BP. She noted the first graph depicts enterprise value, adding the companies' market equity value to their debt. If this project is presumed to be about $20 billion, it's below the total market cap of TransCanada, but certainly much lower than BP or ConocoPhillips. 4:23:11 PM REPRESENTATIVE GARA offered that this will be the biggest project in TransCanada's history, since to his belief it's the biggest in North America. He asked how it compares with pipelines that BP and ConocoPhillips have built. He also asked Ms. Adair, based on what she knows, whether she believes TransCanada can pull this off. MS. ADAIR responded to the first question by saying most integrated companies like ConocoPhillips and BP have their exploration and production assets together. Some but not all include their gas conditioning plants, processing and gathering, and so forth in those same segments, although some companies like Exxon have separate pipeline segments. MS. ADAIR said the tendency is that when any large company takes on a megaproject, it almost always does it with partners; it doesn't want to take on all the risk in its own portfolio for that one project. So companies pool assets - financial, intellectual, engineering, and so on - and diversify the risk of the project among all of them. MS. ADAIR turned to whether TransCanada can do the project. She opined, based on public information review, that TransCanada has the core skills to do it; it operates lots of gas pipelines, builds projects, and does things all the time. MS. ADAIR said the sheer size of this project will be big for anybody. Noting she'd received an e-mail from BP recruiting engineers to come to Alaska, she highlighted the current shortage of engineers that affects everyone. She surmised, however, that by pooling interests and working together - either collectively as owners or helping each other because it's in everyone's best interests - they can do the project. REPRESENTATIVE GARA asked whether this would also be the biggest pipeline project for the other companies. MS. ADAIR replied she hadn't searched the world over, but suggested looking at projects of the same magnitude, especially in today's dollars. TransCanada's mainline system from Alberta to the eastern coast of Canada has five pipelines in the ditch in some places, for instance. There are many systems where one was built and then others were added, and there are lots of big projects. But in one lump sum this may be the biggest. 4:27:09 PM REPRESENTATIVE SAMUELS noted Representative Kerttula had asked to hear TransCanada's take on some of the conclusions. He suggested that would be appropriate during the roundtable discussion, when TransCanada could have its financial analysts available; the same could be done for ConocoPhillips and BP if they wished. REPRESENTATIVE SAMUELS, on behalf of Representative Gara, proposed tasking Muse Stancil with seeing if there are other projects of this magnitude that ConocoPhillips and BP or others have done and how the risk has been mitigated. REPRESENTATIVE KERTTULA recalled last week legislators heard from Goldman Sachs, whose representatives provided a similar answer about TransCanada's ability. 4:28:46 PM MS. ADAIR discussed slide 30, "Potential Company Investment - ConocoPhillips," which said: Financial Stability - COP routinely takes on large, medium- to high- risk projects; however, as a large, integrated multi-national corporation, such higher risk projects are offset by long-term producing reserves, midstream assets, and other investments - Approximately 80 percent of COP equity is held by institutional and mutual fund investors that own the stock because of the corporation's ability to manage such risks - The capital required for execution of the project is of the same order of magnitude as COP's current capital budget - In any case, the financial risk of the Alaska Gas Pipeline Project will ride on the shoulders of those companies that own or control the majority of the gas reserves in the state - Companies like [COP] are used to taking on such risks in return for developing reserves - Investors in companies like [COP] expect corporations to take on such risk to develop the reserves, but also trust the established track record of these companies in assessing and managing development risk Relative to other ConocoPhillips Investments - The COP investment philosophy is based upon allocation of capital - [That] COP has been investing in stock buybacks in the last couple of years suggests that management views returning recent cash increases to investors to be more profitable than investing in additional new projects - COP likely views the Alaska Gas Pipeline Project as leveraging and important to the company's future reserve position as they have allocated the initial capital to pursue the first phases of the Denali project development MS. ADAIR explained that ConocoPhillips and BP are probably in the same situation in terms of financial stability and how they would view this project. For them, it's a way to monetize their gas reserves, which is important. They're used to taking on big, high-risk projects. They do lots of investing in exploration and production, and exploration is a very high-risk business. They know how to model projects like this to understand the risks and to manage them. MS. ADAIR also addressed slide 31, "Potential Company Investment - BP," which said: Financial Stability - Even larger than COP, BP is one of the largest, integrated multi-national energy corporations and does take on medium- to high-risk projects in balance with the corporation's total portfolio risk - The capital required for execution of the project is in line with BP's current capital budget - In any case, the financial risk of the Alaska Gas Pipeline Project will ride on the shoulders of those companies that own or control the majority of the gas reserves in the state - Companies like [BP] are used to taking on such risks in return for developing reserves - Investors in companies like [BP] expect corporations to take on such risk to develop the reserves, but also trust the established track record of these companies in assessing and managing development risk Relative to other BP Investments - Like COP, BP has also been buying back stock - BP also invests, as do most large, integrated companies, based upon an allocation model that considers the health of each asset sector and the ranking of available projects on a risk/return basis - Stock buyback typically signals board confidence in the existing asset base and a preference for returning recent cash increases to investors rather than increasing capital spending with additional new investments 4:29:23 PM MS. ADAIR told members whereas about 80 percent of ConocoPhillips' shareholders are institutional investors, mutual funds, and pension-type funds, BP has perhaps 15-20 percent of those. As shown on a previous slide, capital budgets for both far exceed this pipeline. MS. ADAIR said it's important to note, however, that on an annualized basis the investment in the pipeline doesn't happen in one day. The $23.2 billion will be spent over a long period of time. When looked at that way, it brings the total amount they're managing yearly to a much lower number. MS. ADAIR added that both ConocoPhillips and BP have been buying back their stock and paying good dividends. They're looking for good investments for their shareholders. Both have validated at least the study phase of this project with the announcement of their capital commitments to the Denali project. 4:31:10 PM SENATOR WIELECHOWSKI recalled hearing that the rates of return on the upstream portion are much higher than the 14 percent for the pipeline. He asked why these companies would spend billions of dollars developing something for which they get such a lower rate of return. MS. ADAIR answered this isn't about the pipeline to them. The pipeline is just the equipment they need to get the gas from the ground to the market. While it isn't true if gas is at $1.75 to $2.00 per MMBtu, at today's higher market prices, the reserves in the ground will likely always be worth more to them than the ownership interest in the pipeline. SENATOR WIELECHOWSKI asked: Why wouldn't they be happy with having an independent company come in and build the pipeline so they can make the huge profits that are predicted for the upstream portion? MS. ADAIR cited her experience operating gas plants, oil wells, and gas wells in the field. She said when the operatorship is turned over to someone else, especially someone not as focused on the upstream, goals aren't always aligned. There are issues of flexibility, cost savings, and intangibles that a producer wants to control within the whole producing operation. Producers can be juxtaposed to pipelines in terms of when they're curtailed, when maintenance is done, and so on. Those issues are eliminated by being the operator of that equipment. 4:33:32 PM SENATOR WIELECHOWSKI asked what is meant by the final point on the ConocoPhillips slide, that the company likely views this project as leveraging. MS. ADAIR answered that every exploration and production (E&P) company is trying to add reserves to its balance sheet. If there isn't a conduit for those to get to the marketplace, they aren't on the balance sheet. So companies want to monetize those and get them on the balance sheet as asset. 4:33:53 PM SENATOR THERRIAULT asked: In looking at the companies, did you pull together any information on their reserve replacement ratios? MS. ADAIR indicated Muse Stancil could get that information, which is readily available. REPRESENTATIVE SAMUELS announced the meeting would reconvene at 9:00 a.m. tomorrow morning. SB 3001 and HB 3001 were held over.