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The Parnell and Berkowitz campaigns recently traded barbs regarding the plan Ethan Berkowitz put forward to allow individual Alaskans to own a piece of the pipe through a dividend check-off program. Although the debate was interesting from a political posturing standpoint, substantive debate on the issues was not advanced by their exchange.
The Proposal
Ethan Berkowitz advanced the idea that Alaskan’s should own a piece of the pipe through a dividend check-off program. The implication was that all Alaskans would have a right to participate and that 20% of them probably would elect to participate. The impression was also given that the 20% participation would be from a cross-section of Alaskans. Diane Benson, the lieutenant governor candidate, added weight to that impression by stating that she would have been excited to have had an opportunity like this when she was a young mother of limited means. The intent of the campaign was to appeal to all Alaskans. This may have been a good political sound-byte, but it had problems its application to reality.
The truth is the average Alaskan could not afford to give up their dividend to invest it in a pipeline. Only those Alaskans with surplus spendable income would be able to participate in the project and only a small percentage of them would participate after they found out how long it would take for them to begin to receive a return on their investment. An optimist might suggest that 20% of Alaskans could afford to participate in the program and maybe 20% of those eligible would elect to do so. That would mean an optimistic estimate of 5% of Alaskans would participate, and I am not an optimist; so I believe the number would be much smaller.
The Parnell Campaign Response
The Parnell campaign then decided to assume the Berkowitz plan was accurate, crunched the numbers using a report produced by Scott Goldsmith and argued that the own a piece of the pipe proposal would cost the state 2,000 jobs. The reasoning was that if investing the PFD in the economy created 10,000 jobs, taking 20% of that investment out of the economy would cost the economy 20% of the jobs created; thus the state would lose 2,000 jobs through the own a piece of the pipe proposal.
The Parnell campaign knew as well as anyone that a cross-section of Alaskans would not participate in the own a piece of the pipe dividend check-off. They knew that the average Alaskan could not afford to participate in the program and that the impact of the program would be much smaller that what they projected. But instead of arguing the truth, that the program would not be effective, they decided to “believe” what Berkowitz proposed and argue that the program was bad because it was going to cost Alaskans jobs. They went for the sound-byte instead of the truth. Then to add insult to injury, when they were caught at assuming bad numbers, their response was effectively, “that was my response and I am sticking to it.”
Berkwitz Response
Not to be outdone by the Parnell campaign’s poor judgment, the Berkowitz campaign accused the Parnell campaign of playing political games. The only thing that came to mind at this point is the old saying about the pot calling the kettle black. The Berkowitz campaign, apparently forgetting what they initially suggested in their initial rollout of the proposal, now argued that the Berkowitz campaign can’t control what people will do with their dividends and that they won’t control what people are doing under the plan, apparently supporting what Goldsmith had said about the impact of the plan not being the potential loss of 2,000 jobs. I assume they now believe that 20% of Alaskans won't participate in the dividend check-off proposal.
The Result
Both campaigns have soiled their reputations by their responses to each other. Hopefully this is not a sign of what is to come in this election.
Pipeline Ownership
The Berkowitz campaign has stated that individual ownership through the dividend check-off proposal will enhance the likelihood of success of getting a pipeline. The Parnell campaign believes that staying the course through AGIA provides the state with the greatest likelihood of getting a pipeline.
A substantial amout of research and analysis was done during the Murkowski administration regarding providing Alaskans the opportunity to own a piece of the pipe and regarding the importance and value of state ownership of the pipeline despite the Berkowitz campaign argument that they are the first.
In a future article I will discuss state ownership of the pipeline, what is required if the state wants to participate and the timing of that participation. I guarantee it won’t be what either campaign is recommending.
Thursday, September 23, 2010
Tuesday, September 21, 2010
Berkowitz Revenue Proposal Analysis
The 100% Royalty Solution
Ethan Berkowitz has proposed a new approach for the State of Alaska to use for collecting oil revenue through its two main sources: royalty and taxes. What follows is a quote from his web page.
“The debate about Alaska’s oil and gas revenues has been too much about short-term gain and not enough about long-term interests. The result is a system that fails to optimize outcomes for either the state or industry. Alaska can do better – we can have a system that reduces development risk, increases production and jobs, gives Alaska a fair share of the revenues, enforces budget discipline in Juneau, strengthens the Permanent Fund, and takes the politics out of the state's relationship with the oil industry. Doing better, however, requires a new approach.” – Ethan Berkowitz
I like the goals he has set for the new system, but how does his proposal stack up against reality?
Ethan Berkowitz states that a 100% royalty solution provides fiscal certainty for the oil and gas industry. The industry has been looking for a way to lock in the state’s share of production. This would lock in the state’s share for the term of the contract, as long as 40 to 50 years. This would seem to provide the oil and gas industry with what it is looking for.
But the first problem with a 40 to 50 year lock on the state’s share is that the state has not been able to predict a reasonable tax structure for more than about 15 years. After about 15 years, unforeseen problems with the tax structure begin to show up. The economic limit factor worked for about 15 years before the problems with disproportionate revenue sharing created a need to change the tax laws. ACES has only lasted a couple of years before signs of problems have begun to show up. Heavy oil development and exploration on state and federal lands where the state has the power to tax are both showing signs of being impacted by the tax. If the state agrees to a fixed royalty system for the life of the leases, which could be 40 to 50 years, the system is sure to fail. Oil and gas prices are too volitile. A fixed 100% royalty solution will only work for a narrow range of oil and gas prices. When oil prices are low, the industry will be paying too much revenue to the state and when oil prices are high, Alaskans will believe they are not getting their fair share. That is why progressivity was added to the tax so that the revenue paid to the state by the producers could more closely match the revenue stream: lower taxes during times of lower prices and higher taxes during times of higher prices.
There can be debates about the rate of progressivity, but the intent of progressivity was to more closely match a fair split of the revenue stream between the producers and the state at low and high oil and gas prices.
In addition the only way a 100% royalty solution would work is for the state to pass an amendment to the constitution prohibiting oil and gas production from being taxed. Otherwise there would be no certainty for the oil and gas industry. If a constitutional amendment was not passed, the royalty would be fixed as it is in the current leases and the state could still impose a tax on the revenue if the state determined some day in the future it was not getting its fair share. Thus the industry’s fiscal certainty that it got through signing the 100% royalty leases would be lost anytime the next legislature wanted to pass a tax.
Passing a constitutional amendment prohibiting the state from taxing the oil and gas revenue would create its own problems. The state gets royalty and tax revenue from state lands but it only gets tax revenue from NPRA; so a 100% royalty solution would mean that the state would give up any revenue it might receive from production in the NPRA. I don’t think this was Ethan Berkowitz’s intention. I think he probably didn’t understand that the state doesn’t have the right to negotiate a royalty share from NPRA. And the state has neither the power to receive royalty or to tax the federal OCS.
As far as I can determine from the proposal, the state would negotiate royalty leases on existing production, presumably giving up something to get the industry to agree to the new contracts. The producers will not negotiate fixed long-term contracts to put them in a worse position than they already are. These 100% royalty only leases would then give the industry the fiscal certainty to explore new oil and gas prospects. Once again this sounds good until the proposal is applied to the facts.
According to the NETL Report, existing units on state lands have approximately 6 billion barrels of reserves left to produce. So the state would give up a certain amount of revenue on the 6 billion barrels left to produce to incentivize the oil and gas industry to explore for the additional 3 billion barrels of oil yet to be found on state lands. Existing units on state lands have approximately 34 trillion cubic feet of natural gas to produce. The state will also fix the royalty on the 34 trillion cubic feet of natural gas for the life of the leases as an incentive for the oil and gas industry to explore for and additional 30+ trillion cubic feet of natural gas on state lands. If the additional gas is discovered, those leases will also have fixed royalty rates for the life of the leases and pay no tax. The deal sounds more like giving up two in the hand for one in the bush than getting Alaska its fair share of the revenues.
In addition, in the NPRA the state does not have the right to collect royalty from the leases and only has the power to tax. So the state would be giving up the ability to tax all future oil and gas revenue from NPRA. According to the NETL Report, that would be an additional 6.5 billion barrels of oil and an additional 31 tcf of gas that the state would give up the right to tax.
Ethan Berkowitz could argue that the State of Alaska would only give up the right to tax oil and gas revenue on state lands and continue to tax the revenue on federal lands. This may sound like a good idea but it wouldn’t stand up to a challenge in the courts. The law would not allow the state to discriminate against owners of lease rights on federal lands by taxing them and not the owners of lease rights on state lands.
Ethan Berkowitz has recognized the need for changing circumstances in his proposal. He has proposed that all contracts should have reopener clauses. This would reduce the effect a fixed royalty would have on a fluctuating oil or gas price. When prices were low the unit owners would request a contract reopener and ask for a lower royalty. If the state determined that the royalty should be reduced, a contract amendment could be negotiated reducing the royalty rate. When prices were high the state could ask for a reopener…… but the industry wouldn’t agree. There is no incentive for a Unit owner to agree to pay a higher royalty unless it is getting something additional in return. The only way for the state to get a rate increase under that circumstance would be the take the Unit owners to court and argue that the new price of oil or gas was not contemplated when the original 100% royalty lease was negotiated. The industry would argue that of course the higher price was within the contemplation of the parties since the historical price of oil has been well over $100.
Ultimately reopeners will not work for oil and gas leases in the United States because the State does not have the right to nationalize the oil if they cannot come to an agreement with the Unit owners. Reopeners require both parties to have something to gain and something to lose for a reopener to be successful.
Alternatives that make sense
There does seem to be a problem with the current ACES tax system. The bellweathers for problems with the tax system are heavy oil production and exploration. Heavy oil production should see declines in production before all other production because it is the most expensive to produce. And exploration will see impacts because higher taxes changes project economics and requires larger potential field sizes to be worth spending the money to explore. Both heavy oil and exploration have shown signs of declining investment.
Based on this, it is probably time to reexamine the ACES tax system. Are tax credits sufficient incentive to change industry economics? Does the progressivity factor need to be reexamined? What about the base tax? Does it need to be adjusted downward? Wholesale change is probably not necessary, but a methodical approach to the problem is essential. New ideas and innovation are good but they need to be tested before they are proposed as a final solution to our problems.
Ethan Berkowitz has proposed a new approach for the State of Alaska to use for collecting oil revenue through its two main sources: royalty and taxes. What follows is a quote from his web page.
“The debate about Alaska’s oil and gas revenues has been too much about short-term gain and not enough about long-term interests. The result is a system that fails to optimize outcomes for either the state or industry. Alaska can do better – we can have a system that reduces development risk, increases production and jobs, gives Alaska a fair share of the revenues, enforces budget discipline in Juneau, strengthens the Permanent Fund, and takes the politics out of the state's relationship with the oil industry. Doing better, however, requires a new approach.” – Ethan Berkowitz
I like the goals he has set for the new system, but how does his proposal stack up against reality?
Ethan Berkowitz states that a 100% royalty solution provides fiscal certainty for the oil and gas industry. The industry has been looking for a way to lock in the state’s share of production. This would lock in the state’s share for the term of the contract, as long as 40 to 50 years. This would seem to provide the oil and gas industry with what it is looking for.
But the first problem with a 40 to 50 year lock on the state’s share is that the state has not been able to predict a reasonable tax structure for more than about 15 years. After about 15 years, unforeseen problems with the tax structure begin to show up. The economic limit factor worked for about 15 years before the problems with disproportionate revenue sharing created a need to change the tax laws. ACES has only lasted a couple of years before signs of problems have begun to show up. Heavy oil development and exploration on state and federal lands where the state has the power to tax are both showing signs of being impacted by the tax. If the state agrees to a fixed royalty system for the life of the leases, which could be 40 to 50 years, the system is sure to fail. Oil and gas prices are too volitile. A fixed 100% royalty solution will only work for a narrow range of oil and gas prices. When oil prices are low, the industry will be paying too much revenue to the state and when oil prices are high, Alaskans will believe they are not getting their fair share. That is why progressivity was added to the tax so that the revenue paid to the state by the producers could more closely match the revenue stream: lower taxes during times of lower prices and higher taxes during times of higher prices.
There can be debates about the rate of progressivity, but the intent of progressivity was to more closely match a fair split of the revenue stream between the producers and the state at low and high oil and gas prices.
In addition the only way a 100% royalty solution would work is for the state to pass an amendment to the constitution prohibiting oil and gas production from being taxed. Otherwise there would be no certainty for the oil and gas industry. If a constitutional amendment was not passed, the royalty would be fixed as it is in the current leases and the state could still impose a tax on the revenue if the state determined some day in the future it was not getting its fair share. Thus the industry’s fiscal certainty that it got through signing the 100% royalty leases would be lost anytime the next legislature wanted to pass a tax.
Passing a constitutional amendment prohibiting the state from taxing the oil and gas revenue would create its own problems. The state gets royalty and tax revenue from state lands but it only gets tax revenue from NPRA; so a 100% royalty solution would mean that the state would give up any revenue it might receive from production in the NPRA. I don’t think this was Ethan Berkowitz’s intention. I think he probably didn’t understand that the state doesn’t have the right to negotiate a royalty share from NPRA. And the state has neither the power to receive royalty or to tax the federal OCS.
As far as I can determine from the proposal, the state would negotiate royalty leases on existing production, presumably giving up something to get the industry to agree to the new contracts. The producers will not negotiate fixed long-term contracts to put them in a worse position than they already are. These 100% royalty only leases would then give the industry the fiscal certainty to explore new oil and gas prospects. Once again this sounds good until the proposal is applied to the facts.
According to the NETL Report, existing units on state lands have approximately 6 billion barrels of reserves left to produce. So the state would give up a certain amount of revenue on the 6 billion barrels left to produce to incentivize the oil and gas industry to explore for the additional 3 billion barrels of oil yet to be found on state lands. Existing units on state lands have approximately 34 trillion cubic feet of natural gas to produce. The state will also fix the royalty on the 34 trillion cubic feet of natural gas for the life of the leases as an incentive for the oil and gas industry to explore for and additional 30+ trillion cubic feet of natural gas on state lands. If the additional gas is discovered, those leases will also have fixed royalty rates for the life of the leases and pay no tax. The deal sounds more like giving up two in the hand for one in the bush than getting Alaska its fair share of the revenues.
In addition, in the NPRA the state does not have the right to collect royalty from the leases and only has the power to tax. So the state would be giving up the ability to tax all future oil and gas revenue from NPRA. According to the NETL Report, that would be an additional 6.5 billion barrels of oil and an additional 31 tcf of gas that the state would give up the right to tax.
Ethan Berkowitz could argue that the State of Alaska would only give up the right to tax oil and gas revenue on state lands and continue to tax the revenue on federal lands. This may sound like a good idea but it wouldn’t stand up to a challenge in the courts. The law would not allow the state to discriminate against owners of lease rights on federal lands by taxing them and not the owners of lease rights on state lands.
Ethan Berkowitz has recognized the need for changing circumstances in his proposal. He has proposed that all contracts should have reopener clauses. This would reduce the effect a fixed royalty would have on a fluctuating oil or gas price. When prices were low the unit owners would request a contract reopener and ask for a lower royalty. If the state determined that the royalty should be reduced, a contract amendment could be negotiated reducing the royalty rate. When prices were high the state could ask for a reopener…… but the industry wouldn’t agree. There is no incentive for a Unit owner to agree to pay a higher royalty unless it is getting something additional in return. The only way for the state to get a rate increase under that circumstance would be the take the Unit owners to court and argue that the new price of oil or gas was not contemplated when the original 100% royalty lease was negotiated. The industry would argue that of course the higher price was within the contemplation of the parties since the historical price of oil has been well over $100.
Ultimately reopeners will not work for oil and gas leases in the United States because the State does not have the right to nationalize the oil if they cannot come to an agreement with the Unit owners. Reopeners require both parties to have something to gain and something to lose for a reopener to be successful.
Alternatives that make sense
There does seem to be a problem with the current ACES tax system. The bellweathers for problems with the tax system are heavy oil production and exploration. Heavy oil production should see declines in production before all other production because it is the most expensive to produce. And exploration will see impacts because higher taxes changes project economics and requires larger potential field sizes to be worth spending the money to explore. Both heavy oil and exploration have shown signs of declining investment.
Based on this, it is probably time to reexamine the ACES tax system. Are tax credits sufficient incentive to change industry economics? Does the progressivity factor need to be reexamined? What about the base tax? Does it need to be adjusted downward? Wholesale change is probably not necessary, but a methodical approach to the problem is essential. New ideas and innovation are good but they need to be tested before they are proposed as a final solution to our problems.
Thursday, September 16, 2010
Berkowitz Oil Revenue Proposal
Ethan Berkowitz has proposed a new approach for the State of Alaska to use for collecting oil revenue through its two main sources: royalty and taxes. What follows is a quote from his web page.
“The debate about Alaska’s oil and gas revenues has been too much about short-term gain and not enough about long-term interests. The result is a system that fails to optimize outcomes for either the state or industry. Alaska can do better – we can have a system that reduces development risk, increases production and jobs, gives Alaska a fair share of the revenues, enforces budget discipline in Juneau, strengthens the Permanent Fund, and takes the politics out of the state's relationship with the oil industry. Doing better, however, requires a new approach.” – Ethan Berkowitz
I like the goals he has set for the new system. My next article will address how effective his proposal is in accomplishing those goals.
“The debate about Alaska’s oil and gas revenues has been too much about short-term gain and not enough about long-term interests. The result is a system that fails to optimize outcomes for either the state or industry. Alaska can do better – we can have a system that reduces development risk, increases production and jobs, gives Alaska a fair share of the revenues, enforces budget discipline in Juneau, strengthens the Permanent Fund, and takes the politics out of the state's relationship with the oil industry. Doing better, however, requires a new approach.” – Ethan Berkowitz
I like the goals he has set for the new system. My next article will address how effective his proposal is in accomplishing those goals.
Wednesday, September 15, 2010
Analysis of the Twenty "Must Haves" of AGIA
Overview
There was a substantial amount of importance placed on the twenty "must haves" during the debate on the Alaska Gasline Inducement Act (AGIA). The twenty “must haves” were the basis and reason for the State of Alaska being willing to provide the applicant with up to $500 million in reimbursement for a commitment to the twenty must haves and to move the project forward to applying for the FERC certificate of convenience and necessity. To quote one administration official, the must haves were required to force the applicant to do what they otherwise would not do.
When looked at individually many of the must haves didn’t seem that important or were completed the moment the RFA application was filed. For example, the very first must have required the applicant to submit their application by the filing deadline established by the commissioners. Not exactly, something to fall on your sword over. All contract RFA’s have a filing deadline, and if the applicant does not file by the deadline, their application will not be considered. It was unnecessary to put this item in statute. It merely beefed up the number or requirements without providing additional value to the state.
Other must haves seemed to have little in the way of substantive analysis as the basis for their inclusion. For example, must have number 12 required the applicant to commit to at least five delivery points. The only justification for five points seemed to be that the previous governor, Governor Murkowski, has proposed at least four.
A couple of commitments seemed to make up the core of why the administration needed the must haves and were willing to pay the applicant to make sure they occurred. Must have number 3 requiring the applicant to file for a certificate of public convenience and necessity by a date certain, and must have number 7 regarding rolled-in rates were at the top of the administration’s list. For the reasons listed below, I did not find either of these must haves compelling.
But even if none of the must haves hold any remaining value there may still be a reason to maintain the State’s financial obligation (the $500 million reimbursement) under AGIA.
TransCanada just completed its open season process and Denali is in the midst of its open season. Normally, at the conclusion of the open season process, if it is unsuccessful, the pipeline company will spend most of its energy attempting to determine what went wrong, then rewriting its plan to meet the needs and concerns of its shippers. It would then hold a new open season process in an attempt to have a successful open season. AGIA circumvents this process and requires the applicant to move forward to filing the FERC application even if it doesn’t have the shipping commitments to justify such action. TransCanada is willing to do so because the State of Alaska has agreed to reimburse the pipeline company for 90% of its costs up to $500 million.
As a practical matter this will allow TransCanada to continue to move the engineering and field work forward for at least a year while TransCanada, ExxonMobil, BP, and ConocoPhillips attempt to settle their differences and merge their efforts into a single pipeline proposal. So long as the State is willing to allow the parties to use the $500 million as a bargaining chip and is willing to waive those must haves that get in the way of the negotiations, then AGIA may still have some value left in it for at least another year.
The remainder of this article is a summary analysis of each of the twenty must haves and their remaining value to the State of Alaska.
For those interested in seeing the twenty must haves in context of the rest of the statute, please refer to the State of Alaska AGIA webpage reference below:
http://gasline.alaska.gov/Findings/Appendix%20B%20-%20AGIA%20Statute.pdf
Short Summary of the twenty "must haves"
1) Done. File the application by specified deadline.
2) Done. Provide a thorough description of proposed project.
3) Only remaining obligation is to file for a FERC certificate of public convenience and necessity by a date certain. TransCanada has proposed October 2012.
4) Done. N/A reference to Regulatory Commission of Alaska.
5) Ongoing obligation to assess market demand every two years.
6) Ongoing obligation to expand pipeline in reasonable engineering increments.
7) Ongoing obligation to commit to propose rolled-in rates.
8) Done. State how applicant plans to deal with gas treatment plant.
9) Done. Propose percentage and total dollar amount of reimbursement.
10) Ongoing commitment to propose capital structure of not less than 70% debt.
11) Done. Describe means of preventing and managing cost overruns.
12) Done. Commit to minimum of five delivery points.
13) Done. Commitment to offer distance sensitive rates and firm transportation service to delivery points in Alaska.
14) Done. Commit to establish local headquarters.
15) Ongoing local hire obligation.
16) Done. Waiver of right to appeal department license decisions.
17) Ongoing commitment to negotiate project labor agreements.
18) Done. Commitment that state reimbursement won’t go into rate base.
19) Done. Provide detailed description of applicant and all participating entities.
20) Done. Demonstrate readiness, financial and technical resources to build pipeline.
Analysis of AS 43.90.130 – the twenty "must haves"
The 20 “must haves” of the Alaska Gasline Inducement Act are found in Alaska Statutes Section 43.90.130. Application Requirements. Section 130 requires the application for a license must meet certain criteria – the twenty must haves. Some are timing obligations, some are information requirements that must be submitted as a part of the Request for Applications (RFA), some are obligations with commitments in the future; others are met at the moment the application is filed.
AS 43.90.130(1) requires that the application must be filed by the deadline established by the commissioners. This obligation was met at the moment the applications were filed, and there are no ongoing or future obligations associated with this “must have.”
AS 43.90.130(2) requires that the application provide a thorough description of the proposed natural gas pipeline project, including the proposed route, the location of receipt and delivery points, an analysis of the project’s economic and technical viability, and a technically viable work plan, timeline, and associated budget. The requirements of this “must have” are common to all pipeline projects moving forward to an open season process. They are not unique to the Alaska Natural Gas Pipeline and are not in the category of those requirements that are needed to force the applicant to do what it would not otherwise do. This obligation was generally met at the moment the application was filed, and there are no ongoing or future obligations associated with this “must have.”
AS 43.130(3) requires that the applicant agree to (A) conclude a binding open season within 3 years of receiving a license, (B) apply to the FERC to use the prefiling process before filing an application for a certificate of public convenience and necessity, and (C) apply for a FERC certificate of public convenience and necessity by a date certain.
Subsections (A) and (B) have been completed, and TransCanada has proposed filing for the FERC certificate by October 2012 in compliance with (C). The date certain can be amended under AS 43.90.210 Amendment or Modification of the Project Plan.
The “date certain” obligation under AS 43.120(3)(C) is a continuing obligation that will not be met until the applicant files for a FERC certificate of convenience and public necessity. This certainly is one of the obligations that are in the category of those requirements that are needed to force the applicant to do what it would not otherwise do. This is one of the provisions that most pipeline companies would not agree to because they know that, statistically, date driven projects have a greater chance of failure and cost overruns than projects that are milestone driven. The saving grace of this provision is that the language of the statute provides for an “out” if the applicant runs into difficulty complying with the date they proposed, i.e., the project can still be milestone driven and if the applicant doesn’t meet the “date certain” they will have justification for an amendment so long as they have diligently pursued the project. The additional “sweetener” for this provision is that the State of Alaska will reimburse the applicant for 90% of its costs after Open Season up to $500 million to pursue the project through filing of the FERC certificate.
AS 43.90.130(4) provides that if the project is subject to the jurisdiction of the Regulatory Commission of Alaska (RCA), the applicant will commit to similar obligations that it was obligated to do in (3) above. Since there has been no allegation that the project is subject to the jurisdiction of the RCA, this “must have” can be deemed complete or not applicable.
AS 43.90.130(5) requires to applicant to assess market demand for expansion every two years. This obligation is specific and will require some form of documentation that the applicant met the obligation. As a practical matter, every pipeline company is continually assessing the market demand for capacity. Pipeline companies are incentivized to provide expansion when it is needed by the market. Although this “must have” is ongoing, the value of it is limited because pipeline companies do not need to be told to be on the lookout for pipeline expansion opportunities. This provision had little value when enacted unless you were a conspiracy theorist and believed that the major oil companies on the north slope would conspire to lock up initial capacity on the pipeline and ship only their gas and not expand the pipeline to allow other gas owners on the slope access to the pipeline. Even conspiracy theorists are no longer concerned with this provision because TransCanada won the license and TransCanada, a pipeline company, is incentivized to expand the pipe at every economic opportunity made available to them.
AS 43.90.130(6) requires the applicant to commit to expand the pipeline in reasonable engineering increments and on commercially reasonable terms. This provision sounds good, but is unnecessary. No rational pipeline company would try to expand a pipeline on non-commercially reasonable terms or in unreasonable engineering increments, and the FERC wouldn’t allow such an irrational act to occur even if you found a pipeline company that would consider such unreasonable behavior. This provision, although still an ongoing requirement, is not important to the overall goal of getting Alaska’s gas to market. It will happen with or without the State of Alaska’s insistence.
AS 43.90.130(7) requires the applicant commit to propose rolled-in rates for all expansions so long as the final rates would not result in rates that are more than 15 percent above the initial maximum recourse rates for capacity. This provision is interesting because of the strong positions taken by the State of Alaska and by the major oil and gas owners on the North Slope. Yet the likelihood of this provision ever becoming a real issue is very small. In order for there to be a conflict over this provision there would have to be three expansions of the pipeline.
Everyone generally agrees, based on the submittals of TransCanada and Denali that the first two expansions would result in a reduced tariff and “rolled-in” rates would be perfectly acceptable to all. Only the third expansion would result in a difference in rates.
The third expansion would be through “looping”, that is, building a parallel pipeline alongside the proposed gas pipeline for certain sections of the route.
The State of Alaska argues that a third expansion might not be economic without rolled-in rates; and therefore the pipeline company should propose them.
The North Slope oil and gas owners argue that they should not be required to subsidize a third party gas owner’s expansion through rolled-in rates.
As a practical matter, the only probable scenario that could result in expansion by looping is if Shell found substantial amounts of gas in the Chukchi Sea. The pipeline would have had two expansions by compression and any gas that Alaskans needed would have been under contract in one of the first two expansions. The likely recipients of gas from the third expansion would be Canada, the lower-48, or Pacific Rim markets.
The State of Alaska would require the pipeline company to propose rolled in rates in the third expansion which would mean higher rates for everyone currently receiving gas from the pipeline, and if the FERC approved the rolled-in rates, rates for Alaskans would increase. The State of Alaska effectively made a requirement that was against its own interests. Rolled-in rates for the first two expansions makes sense for Alaskans. Rolled-in rates for the third expansion through looping will increase rates to Alaskans in order to pay for Shell or another major gas producer to ship their gas from the Chuckchi Sea through Canada and to the lower-48. To add insult to injury, the major gas producers will pay no royalty or taxes to the State of Alaska for this benefit bestowed upon them. Once again there is a saving grace to this provision, the chance of explorers finding sufficient gas reserves to keep the current pipeline full, find enough reserves to expand the pipeline twice through compression, and then find enough gas to make an expansion through looping is slim to none. Neither the State of Alaska or the North Slope oil and gas owners should spend any energy arguing over this provision.
There is an additional problem with requiring an applicant to propose rolled-in rates. The obligation must be considered in the context of how it relates advocacy before a regulatory body. The obligation to propose rolled-in rates results in exactly the opposite impact from what the State was attempting to do. First, recognize that a regulatory agency is going to fulfill its responsibilities regardless of what the State has contractually obligated a party to do. Next, if a party is legally obligated to advocate for a particular position, the regulatory agency will know that. The regulatory will discount that advocacy to the extent they believe the position is based on a legal obligation rather than what the party believes. If two parties come before the regulatory agency with a comment, one has a legal obligation to advocate a particular position, and the other can advocate what it believes, the regulatory agency will accept both comments but will recognize that one party may or may not be advocating what it believes.
AS 43.90.130(8) requires the applicant to state how it proposes to deal with a North Slope gas treatment plant. This provision was complete once the application was filed.
AS 43.90.130(9) requires the applicant to purpose the percentage and total dollar amount for the State’s reimbursement of the applicant. This provision was complete once the application was filed.
AS 43.90.130(10) requires the applicant to commit to propose and support rates that are based on a capital structure for rate-making that consists of not less than 70 percent debt. This provision requires a “commitment to propose” and was completed once the application was filed. The license binds the applicant to the commitment. Although this provision is considered complete so long as the applicant does not violate its obligation under the license agreement, the provision itself is not a strong provision. When the State of Alaska was considering participation as an owner of the pipeline, they were evaluating a provision that required a capital structure for rate-making that consisted of not less than 80 percent debt if the financial market would allow it. This would have been a much greater benefit to the people of the State of Alaska than the 70 percent debt number required as a part of the twenty must haves.
AS 43.90.130(11) requires the applicant to describe the means for preventing and managing cost overruns and for minimizing their effect on the tariff. This provision is an important part of the applicant’s proposal in the open season. All bidders want to know how cost overruns will be handled. This provision was unnecessary because it would have been required as a part of any proposed open season, but it is also complete because the TransCanada open season has been held.
AS 43.90.130(12) requires the applicant to provide a minimum of five delivery points of natural gas in the state. This provision is interesting in that there was no real justification for five delivery points. The only justification was that Governor Murkowski proposed four delivery points. Actually the best way to approach delivery points is to talk to the engineers that are designing the compressor stations. Th compressor stations will probably be used as the delivery points for natural gas because using an existing compressor station will be the least expensive way to access gas for Alaskans. When I asked the engineers (one pipeline company set of engineers) if they could design all the compressor stations so that access to gas would be available at each station, they said they could do so without substantial additional cost. If a compressor station is built along the line, it should be designed in such a way as to easily allow access to gas for local use. The local user would still have to pay for the connection costs, including compression and processing, but the access would be available wherever there was a compression station. In addition the federal government requires the applicant, in their notice of open season to provide for delivery points at the locations identified in the in-state needs study which effectively makes this provision unnecessary.
AS 43.90.130(13) requires to applicant to commit to offer firm transportation service to delivery points in the state and to offer distance sensitive rates to delivery points in the state. Interestingly the provision also cites the federal CFR that requires that same thing effectively making the “must have” unnecessary.
AS 43.90.130(14) requires to commit to establish a local headquarters in Alaska. For TransCanada, at least until it is further along in the project, this means it must open a token office to comply with the provision. It is logical for TransCanada to keep most of its staff in Canada close to its executive management team prior to commencement of construction. For Denali (ConocoPhillips and BP), since they both have offices in Alaska, it is easy for them to open local headquarters and staff them with more individuals since they are close to their management teams here in Alaska. This provision has been met by the applicant and is complete.
AS 43.90.130(15) requires the applicant to hire qualified residents and contract with local businesses. This provision looks good but does little to encourage pipeline companies to pursue Alaska workers. The State of Alaska should encourage the pipeline companies to work with local businesses in advance of contract bids. The pipeline companies should size contracts so that local business can bid on the projects. One of the easiest ways to prevent local participation in the bid process is to create a contract that is so large that the local business cannot compete. The pipeline companies need to size contracts to encourage local participation in the bid process. Then the pipeline companies should create programs that help local businesses write business plans that would allow them to participate in the project and allow them to survive after the project is completed.
AS 43.90.130(16) requires all applicants to waive their rights to appeal rejection of their applications. It only applies to applicants and was complete at the time the application was filed.
AS 43.90.130(17) requires applicants to commit to negotiate project labor agreements. This provision sounds good but requires nothing of substance. The provision does not require the applicants to agree to project labor agreements, merely to negotiate them. In all probability the pipeline companies will come to terms with the unions and will agree to project labor agreements, but it will not be because it was required by the State of Alaska. It will happen because it is economic and expedient.
AS 43.90.130(18) requires the applicant to agree to not include the state reimbursement in the applicant’s rate base. I’m not sure the FERC would allow an applicant to add costs to its rate base if it ultimately could not prove it paid for them; so I assume that the FERC would not allow the applicant to add the state reimbursement to its rate base even if the state did not have this provision. This provision is fine but is probably covered by the FERC.
AS 43.90.130(19) requires the applicant to provide a detailed description of themselves and all entities participating with the applicant including the commitments of the other entities participating with the applicant. This provision can assure the State that if a number of entities got together to propose an application, the State could evaluate the entities as a whole to determine if the applicant was ready and able to complete the project. This provision was complete at the time the application was filed.
AS 43.90.130(20) requires the applicant to demonstrate its readiness, financial resources, and technical ability to perform the activities specified in the application. This provision was compete at the time the application was filed.
There was a substantial amount of importance placed on the twenty "must haves" during the debate on the Alaska Gasline Inducement Act (AGIA). The twenty “must haves” were the basis and reason for the State of Alaska being willing to provide the applicant with up to $500 million in reimbursement for a commitment to the twenty must haves and to move the project forward to applying for the FERC certificate of convenience and necessity. To quote one administration official, the must haves were required to force the applicant to do what they otherwise would not do.
When looked at individually many of the must haves didn’t seem that important or were completed the moment the RFA application was filed. For example, the very first must have required the applicant to submit their application by the filing deadline established by the commissioners. Not exactly, something to fall on your sword over. All contract RFA’s have a filing deadline, and if the applicant does not file by the deadline, their application will not be considered. It was unnecessary to put this item in statute. It merely beefed up the number or requirements without providing additional value to the state.
Other must haves seemed to have little in the way of substantive analysis as the basis for their inclusion. For example, must have number 12 required the applicant to commit to at least five delivery points. The only justification for five points seemed to be that the previous governor, Governor Murkowski, has proposed at least four.
A couple of commitments seemed to make up the core of why the administration needed the must haves and were willing to pay the applicant to make sure they occurred. Must have number 3 requiring the applicant to file for a certificate of public convenience and necessity by a date certain, and must have number 7 regarding rolled-in rates were at the top of the administration’s list. For the reasons listed below, I did not find either of these must haves compelling.
But even if none of the must haves hold any remaining value there may still be a reason to maintain the State’s financial obligation (the $500 million reimbursement) under AGIA.
TransCanada just completed its open season process and Denali is in the midst of its open season. Normally, at the conclusion of the open season process, if it is unsuccessful, the pipeline company will spend most of its energy attempting to determine what went wrong, then rewriting its plan to meet the needs and concerns of its shippers. It would then hold a new open season process in an attempt to have a successful open season. AGIA circumvents this process and requires the applicant to move forward to filing the FERC application even if it doesn’t have the shipping commitments to justify such action. TransCanada is willing to do so because the State of Alaska has agreed to reimburse the pipeline company for 90% of its costs up to $500 million.
As a practical matter this will allow TransCanada to continue to move the engineering and field work forward for at least a year while TransCanada, ExxonMobil, BP, and ConocoPhillips attempt to settle their differences and merge their efforts into a single pipeline proposal. So long as the State is willing to allow the parties to use the $500 million as a bargaining chip and is willing to waive those must haves that get in the way of the negotiations, then AGIA may still have some value left in it for at least another year.
The remainder of this article is a summary analysis of each of the twenty must haves and their remaining value to the State of Alaska.
For those interested in seeing the twenty must haves in context of the rest of the statute, please refer to the State of Alaska AGIA webpage reference below:
http://gasline.alaska.gov/Findings/Appendix%20B%20-%20AGIA%20Statute.pdf
Short Summary of the twenty "must haves"
1) Done. File the application by specified deadline.
2) Done. Provide a thorough description of proposed project.
3) Only remaining obligation is to file for a FERC certificate of public convenience and necessity by a date certain. TransCanada has proposed October 2012.
4) Done. N/A reference to Regulatory Commission of Alaska.
5) Ongoing obligation to assess market demand every two years.
6) Ongoing obligation to expand pipeline in reasonable engineering increments.
7) Ongoing obligation to commit to propose rolled-in rates.
8) Done. State how applicant plans to deal with gas treatment plant.
9) Done. Propose percentage and total dollar amount of reimbursement.
10) Ongoing commitment to propose capital structure of not less than 70% debt.
11) Done. Describe means of preventing and managing cost overruns.
12) Done. Commit to minimum of five delivery points.
13) Done. Commitment to offer distance sensitive rates and firm transportation service to delivery points in Alaska.
14) Done. Commit to establish local headquarters.
15) Ongoing local hire obligation.
16) Done. Waiver of right to appeal department license decisions.
17) Ongoing commitment to negotiate project labor agreements.
18) Done. Commitment that state reimbursement won’t go into rate base.
19) Done. Provide detailed description of applicant and all participating entities.
20) Done. Demonstrate readiness, financial and technical resources to build pipeline.
Analysis of AS 43.90.130 – the twenty "must haves"
The 20 “must haves” of the Alaska Gasline Inducement Act are found in Alaska Statutes Section 43.90.130. Application Requirements. Section 130 requires the application for a license must meet certain criteria – the twenty must haves. Some are timing obligations, some are information requirements that must be submitted as a part of the Request for Applications (RFA), some are obligations with commitments in the future; others are met at the moment the application is filed.
AS 43.90.130(1) requires that the application must be filed by the deadline established by the commissioners. This obligation was met at the moment the applications were filed, and there are no ongoing or future obligations associated with this “must have.”
AS 43.90.130(2) requires that the application provide a thorough description of the proposed natural gas pipeline project, including the proposed route, the location of receipt and delivery points, an analysis of the project’s economic and technical viability, and a technically viable work plan, timeline, and associated budget. The requirements of this “must have” are common to all pipeline projects moving forward to an open season process. They are not unique to the Alaska Natural Gas Pipeline and are not in the category of those requirements that are needed to force the applicant to do what it would not otherwise do. This obligation was generally met at the moment the application was filed, and there are no ongoing or future obligations associated with this “must have.”
AS 43.130(3) requires that the applicant agree to (A) conclude a binding open season within 3 years of receiving a license, (B) apply to the FERC to use the prefiling process before filing an application for a certificate of public convenience and necessity, and (C) apply for a FERC certificate of public convenience and necessity by a date certain.
Subsections (A) and (B) have been completed, and TransCanada has proposed filing for the FERC certificate by October 2012 in compliance with (C). The date certain can be amended under AS 43.90.210 Amendment or Modification of the Project Plan.
The “date certain” obligation under AS 43.120(3)(C) is a continuing obligation that will not be met until the applicant files for a FERC certificate of convenience and public necessity. This certainly is one of the obligations that are in the category of those requirements that are needed to force the applicant to do what it would not otherwise do. This is one of the provisions that most pipeline companies would not agree to because they know that, statistically, date driven projects have a greater chance of failure and cost overruns than projects that are milestone driven. The saving grace of this provision is that the language of the statute provides for an “out” if the applicant runs into difficulty complying with the date they proposed, i.e., the project can still be milestone driven and if the applicant doesn’t meet the “date certain” they will have justification for an amendment so long as they have diligently pursued the project. The additional “sweetener” for this provision is that the State of Alaska will reimburse the applicant for 90% of its costs after Open Season up to $500 million to pursue the project through filing of the FERC certificate.
AS 43.90.130(4) provides that if the project is subject to the jurisdiction of the Regulatory Commission of Alaska (RCA), the applicant will commit to similar obligations that it was obligated to do in (3) above. Since there has been no allegation that the project is subject to the jurisdiction of the RCA, this “must have” can be deemed complete or not applicable.
AS 43.90.130(5) requires to applicant to assess market demand for expansion every two years. This obligation is specific and will require some form of documentation that the applicant met the obligation. As a practical matter, every pipeline company is continually assessing the market demand for capacity. Pipeline companies are incentivized to provide expansion when it is needed by the market. Although this “must have” is ongoing, the value of it is limited because pipeline companies do not need to be told to be on the lookout for pipeline expansion opportunities. This provision had little value when enacted unless you were a conspiracy theorist and believed that the major oil companies on the north slope would conspire to lock up initial capacity on the pipeline and ship only their gas and not expand the pipeline to allow other gas owners on the slope access to the pipeline. Even conspiracy theorists are no longer concerned with this provision because TransCanada won the license and TransCanada, a pipeline company, is incentivized to expand the pipe at every economic opportunity made available to them.
AS 43.90.130(6) requires the applicant to commit to expand the pipeline in reasonable engineering increments and on commercially reasonable terms. This provision sounds good, but is unnecessary. No rational pipeline company would try to expand a pipeline on non-commercially reasonable terms or in unreasonable engineering increments, and the FERC wouldn’t allow such an irrational act to occur even if you found a pipeline company that would consider such unreasonable behavior. This provision, although still an ongoing requirement, is not important to the overall goal of getting Alaska’s gas to market. It will happen with or without the State of Alaska’s insistence.
AS 43.90.130(7) requires the applicant commit to propose rolled-in rates for all expansions so long as the final rates would not result in rates that are more than 15 percent above the initial maximum recourse rates for capacity. This provision is interesting because of the strong positions taken by the State of Alaska and by the major oil and gas owners on the North Slope. Yet the likelihood of this provision ever becoming a real issue is very small. In order for there to be a conflict over this provision there would have to be three expansions of the pipeline.
Everyone generally agrees, based on the submittals of TransCanada and Denali that the first two expansions would result in a reduced tariff and “rolled-in” rates would be perfectly acceptable to all. Only the third expansion would result in a difference in rates.
The third expansion would be through “looping”, that is, building a parallel pipeline alongside the proposed gas pipeline for certain sections of the route.
The State of Alaska argues that a third expansion might not be economic without rolled-in rates; and therefore the pipeline company should propose them.
The North Slope oil and gas owners argue that they should not be required to subsidize a third party gas owner’s expansion through rolled-in rates.
As a practical matter, the only probable scenario that could result in expansion by looping is if Shell found substantial amounts of gas in the Chukchi Sea. The pipeline would have had two expansions by compression and any gas that Alaskans needed would have been under contract in one of the first two expansions. The likely recipients of gas from the third expansion would be Canada, the lower-48, or Pacific Rim markets.
The State of Alaska would require the pipeline company to propose rolled in rates in the third expansion which would mean higher rates for everyone currently receiving gas from the pipeline, and if the FERC approved the rolled-in rates, rates for Alaskans would increase. The State of Alaska effectively made a requirement that was against its own interests. Rolled-in rates for the first two expansions makes sense for Alaskans. Rolled-in rates for the third expansion through looping will increase rates to Alaskans in order to pay for Shell or another major gas producer to ship their gas from the Chuckchi Sea through Canada and to the lower-48. To add insult to injury, the major gas producers will pay no royalty or taxes to the State of Alaska for this benefit bestowed upon them. Once again there is a saving grace to this provision, the chance of explorers finding sufficient gas reserves to keep the current pipeline full, find enough reserves to expand the pipeline twice through compression, and then find enough gas to make an expansion through looping is slim to none. Neither the State of Alaska or the North Slope oil and gas owners should spend any energy arguing over this provision.
There is an additional problem with requiring an applicant to propose rolled-in rates. The obligation must be considered in the context of how it relates advocacy before a regulatory body. The obligation to propose rolled-in rates results in exactly the opposite impact from what the State was attempting to do. First, recognize that a regulatory agency is going to fulfill its responsibilities regardless of what the State has contractually obligated a party to do. Next, if a party is legally obligated to advocate for a particular position, the regulatory agency will know that. The regulatory will discount that advocacy to the extent they believe the position is based on a legal obligation rather than what the party believes. If two parties come before the regulatory agency with a comment, one has a legal obligation to advocate a particular position, and the other can advocate what it believes, the regulatory agency will accept both comments but will recognize that one party may or may not be advocating what it believes.
AS 43.90.130(8) requires the applicant to state how it proposes to deal with a North Slope gas treatment plant. This provision was complete once the application was filed.
AS 43.90.130(9) requires the applicant to purpose the percentage and total dollar amount for the State’s reimbursement of the applicant. This provision was complete once the application was filed.
AS 43.90.130(10) requires the applicant to commit to propose and support rates that are based on a capital structure for rate-making that consists of not less than 70 percent debt. This provision requires a “commitment to propose” and was completed once the application was filed. The license binds the applicant to the commitment. Although this provision is considered complete so long as the applicant does not violate its obligation under the license agreement, the provision itself is not a strong provision. When the State of Alaska was considering participation as an owner of the pipeline, they were evaluating a provision that required a capital structure for rate-making that consisted of not less than 80 percent debt if the financial market would allow it. This would have been a much greater benefit to the people of the State of Alaska than the 70 percent debt number required as a part of the twenty must haves.
AS 43.90.130(11) requires the applicant to describe the means for preventing and managing cost overruns and for minimizing their effect on the tariff. This provision is an important part of the applicant’s proposal in the open season. All bidders want to know how cost overruns will be handled. This provision was unnecessary because it would have been required as a part of any proposed open season, but it is also complete because the TransCanada open season has been held.
AS 43.90.130(12) requires the applicant to provide a minimum of five delivery points of natural gas in the state. This provision is interesting in that there was no real justification for five delivery points. The only justification was that Governor Murkowski proposed four delivery points. Actually the best way to approach delivery points is to talk to the engineers that are designing the compressor stations. Th compressor stations will probably be used as the delivery points for natural gas because using an existing compressor station will be the least expensive way to access gas for Alaskans. When I asked the engineers (one pipeline company set of engineers) if they could design all the compressor stations so that access to gas would be available at each station, they said they could do so without substantial additional cost. If a compressor station is built along the line, it should be designed in such a way as to easily allow access to gas for local use. The local user would still have to pay for the connection costs, including compression and processing, but the access would be available wherever there was a compression station. In addition the federal government requires the applicant, in their notice of open season to provide for delivery points at the locations identified in the in-state needs study which effectively makes this provision unnecessary.
AS 43.90.130(13) requires to applicant to commit to offer firm transportation service to delivery points in the state and to offer distance sensitive rates to delivery points in the state. Interestingly the provision also cites the federal CFR that requires that same thing effectively making the “must have” unnecessary.
AS 43.90.130(14) requires to commit to establish a local headquarters in Alaska. For TransCanada, at least until it is further along in the project, this means it must open a token office to comply with the provision. It is logical for TransCanada to keep most of its staff in Canada close to its executive management team prior to commencement of construction. For Denali (ConocoPhillips and BP), since they both have offices in Alaska, it is easy for them to open local headquarters and staff them with more individuals since they are close to their management teams here in Alaska. This provision has been met by the applicant and is complete.
AS 43.90.130(15) requires the applicant to hire qualified residents and contract with local businesses. This provision looks good but does little to encourage pipeline companies to pursue Alaska workers. The State of Alaska should encourage the pipeline companies to work with local businesses in advance of contract bids. The pipeline companies should size contracts so that local business can bid on the projects. One of the easiest ways to prevent local participation in the bid process is to create a contract that is so large that the local business cannot compete. The pipeline companies need to size contracts to encourage local participation in the bid process. Then the pipeline companies should create programs that help local businesses write business plans that would allow them to participate in the project and allow them to survive after the project is completed.
AS 43.90.130(16) requires all applicants to waive their rights to appeal rejection of their applications. It only applies to applicants and was complete at the time the application was filed.
AS 43.90.130(17) requires applicants to commit to negotiate project labor agreements. This provision sounds good but requires nothing of substance. The provision does not require the applicants to agree to project labor agreements, merely to negotiate them. In all probability the pipeline companies will come to terms with the unions and will agree to project labor agreements, but it will not be because it was required by the State of Alaska. It will happen because it is economic and expedient.
AS 43.90.130(18) requires the applicant to agree to not include the state reimbursement in the applicant’s rate base. I’m not sure the FERC would allow an applicant to add costs to its rate base if it ultimately could not prove it paid for them; so I assume that the FERC would not allow the applicant to add the state reimbursement to its rate base even if the state did not have this provision. This provision is fine but is probably covered by the FERC.
AS 43.90.130(19) requires the applicant to provide a detailed description of themselves and all entities participating with the applicant including the commitments of the other entities participating with the applicant. This provision can assure the State that if a number of entities got together to propose an application, the State could evaluate the entities as a whole to determine if the applicant was ready and able to complete the project. This provision was complete at the time the application was filed.
AS 43.90.130(20) requires the applicant to demonstrate its readiness, financial resources, and technical ability to perform the activities specified in the application. This provision was compete at the time the application was filed.
Saturday, September 11, 2010
Alaska Gasline Inducement Act (AGIA)
My next set of articles will address the “must have” requirements of the Alaska Gasline Inducement Act (AGIA) found at AS 43.90.130. The AGIA “must haves” can be categorized into three groups:
1) Provisions that apply to the Request for Application (RFA),
2) Mom and Apple Pie requirements, and
3) Requirements that an applicant might not otherwise do if not required to do so by the State.
I will address which requirements have been completed, which are unnecessary, and the value, if any still exists, in the remaining requirements of AGIA.
1) Provisions that apply to the Request for Application (RFA),
2) Mom and Apple Pie requirements, and
3) Requirements that an applicant might not otherwise do if not required to do so by the State.
I will address which requirements have been completed, which are unnecessary, and the value, if any still exists, in the remaining requirements of AGIA.
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