Alaskan Advocate

The Luck of the Draw

2011-10-09T22:27:00.000-07:00

In a recent editorial, Senator Kevin Meyer touted the importance of the recently constructed and to be constructed energy projects around Alaska. He stated that there are 66 projects in the pre-construction phase and 58 projects under construction or completed. That’s 124 projects supported by legislators from around the state, 124 projects where legislators brought home the bacon, 124 projects that helped legislators get reelected. Regarding those projects, Senator Meyer suggests that it is “important to monitor the state’s investment. The legislature must remain vigilant, as granting money without strong oversight, review or audit can sometimes be more harmful than investing none at all.”

The problem is that the legislature failed to use the same vigilance, review and analysis when approving the projects. Projects were placed on the Legislature’s renewal energy project wish list with little or no analysis of the future viability of those projects. Most were merely ideas without any analysis of the long term viability of the project after it gets built. Most were not even required to submit a business plan that could show the long-term economic viability of the project.

The result will be that most of the approved projects will fail from an economic standpoint no matter how much vigilance the legislature puts forth. You can’t make a poor project successful merely by auditing it to death. You will, at least, be able to record your own failure in approving the project in the first place. The old adage “fail to plan and plan to fail” will once again raise its ugly head.

As with any appropriation, there is some value in the approved projects. Some projects actually put forth viable business plans and would have been approved on their own merit if the legislature had done the analysis they should have done before approving the projects. The projects will probably succeed because they can prove, at least on paper, that they will be successful and economically viable in the long-term if built. For those projects, I congratulate them for their diligence, their preparation, their analysis, and their willingness to do what it takes to ensure the successful viability of their project. For the rest of the projects that were approved without the proper preparation, without the proper analysis, without a business plan, good luck. Perhaps another old saying “by the luck of the draw” will be your story. Perhaps you will be successful inspite of your own poor efforts.

And to the legislators that approved the 124 projects without the proper analysis, if you approve any more renewable energy projects, at least make sure they have submitted a viable business plan. Even an optimistic business plan, which it inevitably will be, is better than none at all.

My prediction is that 10 percent of the approved projects will clearly succeed, 50 percent will fail, and 40 percent will be hoping for “the luck of the draw.”

Loan Guarantees and Pipeline Economics

2011-09-22T22:22:00.000-07:00

In a recent letter to Governor Parnell, Alaska Senator Mark Begich stated that it would be difficult for Alaska’s congressional delegation to get an increase in the federal loan guarantees anytime soon; so, Senator Begich proposed that the state should consider loan guarantees for the remainder of the debt that the federal government would not cover – in the realm of $9 billion in loan guarantees. The problem with his proposal is that it requires a substantial amount of legislative energy, time, and effort and does nothing substantial to change the economics of the gas pipeline.

Loan guarantees tend to reduce the cost of debt and consequently reduce the tariff. This is good, but it reduces the cost of debt only by a small margin making only a minor change to the tariff.

The loan guarantees are important to the pipeline builders, but they do little to create incentives for the shippers. The risk to the shippers is substantially unchanged. The State of Alaska needs to look for solutions that reduce the risk to the shippers and solutions that make a substantial reduction to the tariff and thus increase the economics of the pipeline.

I have two recommendations regarding how to change the economics of a large diameter pipeline: one for the Alaska portion of the pipeline and one for the Canada portion of the pipeline.

Alaska Portion of the Pipeline

Regarding the Alaska portion of the pipeline, I recommend the State of Alaska fund the equity portion of the pipeline, take a debt rate of return, and not start receiving payment on its investment until the original debt is paid off. This funding mechanism could take the form of a financial interest or an ownership interest. That could be determined by discussing the proposal with companies that might want to participate in the ownership of the pipeline.

The benefit of this proposal is that it would change the economics of the pipeline and reduce the tariff more than any other single proposal that has been put forth so far. Combined with other risk reduction actions, it may be sufficient to move the gas pipeline forward.

The cost of this proposal would probably be up to $10 billion for a success scenario but less than $2 billion to see if it would be likely to succeed. The risk capital would be invested to develop a proposal and hold an open season. If the open season was successful, then the project could move forward to a FERC certificate. It is possible that up $3 billion would have to be expended to get to a project sanction decision, but this capital would only be expended after a successful open season and signed precedent agreements from the shippers.

One hundred percent of equity contribution should be invested in the Alaska portion of the pipeline only. That way Alaska gets the full benefit of the investment, and the tariff on the Alaska portion of the pipeline sees the greatest impact, thus providing cheaper gas for Alaskans.

If Alaska decides to make such a commitment to the pipeline, Alaska should approach the federal government to see what they can do to support Alaska’s commitment. The two things Alaska should ask for are 1) Alaska’s fair share of the revenue from federal offshore development, and 2) Alaska should ask for the chance to explore in ANWR.

Regarding AGIA and TransCanada, Alaska should get TransCanada to either agree that the current AGIA plan is uneconomic or get TransCanada to waive their rights to damages under AGIA in exchange for the opportunity to participate in the Canadian portion of the pipeline. I am fairly certain that TransCanada would not want to own a piece of the Alaskan portion of the pipeline under to above plan. I am also not worried about TransCanada threatening to sue under AGIA. It is clear that the present plan is uneconomic; so, there will be no liability under AGIA if TransCanada does not agree to waive their rights.

In addition, contrary to AGIA’s capital contribution, Alaska would get a return on its capital investment and future generations would receive the benefit. Consider the investment a savings account for the future when Alaska may need the return.

Canada Portion of the Pipeline

TransCanada has proposed a 70/30 debt equity ratio (with some modifications). They propose to invest 30% of the cost of the pipeline in equity. The equity rate of return on the pipeline will probably be greater than 12%. The cost of the debt, on the other hand is closer to 5% depending on who the borrower is and their credit rating. Clearly it is better to have more of the pipeline funded by debt and less by equity because the return on the equity is more than twice as expensive to the pipeline as the debt.

Alaska should try to get TransCanada to agree to an 80/20 debt equity ratio. This will lower the tariff by a certain amount and save the State of Alaska and the shippers over the life of the pipeline billions of dollars. In the alternative Alaska should argue to the Canadian government for an 80/20 debt equity ratio. Alaska should also argue for a return on equity of 12% or less on the Canadian portion of the pipeline. Once again this would lower the tariff and make the pipeline more economic. These two terms are not unreasonable. Both were given serious consideration during the initial pipeline negotiations with the producer group.

As a reminder, gas pipeline economics is a major element of achieving a successful gas pipeline, but there are many more elements that must be addressed to move the project forward.

The issues that need to be addressed are:

1) Fair oil and gas taxes
2) Long term fiscal plan
3) Short term annual capital and operating budgets
4) The permanent fund, its present and future use
5) Gas pipeline economics (discussed in this article)
6) Exploration and filling TAPS and the Gas Pipeline
7) Fiscal certainty/stable oil and gas tax environment
8) Point Thomson (hopefully this will be resolved soon by the State of Alaska and the Point Thomson owners)

In summary if Alaskans really want an Alaskan Gas Pipeline, they need commit their resources to its success. They need to be disciplined fiscally. They need to lead instead of follow. They need to take charge of their future. The result is they will be better off by pursuing such a direction. If the pipeline is a success because of their efforts, they will reap the benefits. If the pipeline is not a success then they will be prepared for the new world they will find.

A Comprehensive Plan - What is Necessary

2011-09-20T21:20:00.000-07:00

In May of this year Bud Fackrell, Denali Pipeline Project President announced that “Denali is ending its efforts (to continue the pipeline project) because of a lack of customer support.” This was not a surprising outcome. The pipeline project, without a more comprehensive strategy, will not proceed ahead. The price of gas in the lower-48, current oil and gas taxes and the uncertainty of those taxes in the future, and the lack of a long term plan to finance state government, all contribute to decisions by the shippers of the gas not to commit their gas to a pipeline.

Some will say that TransCanada’s Alaska Pipeline Project is still moving forward, but the only reason it is still moving forward is because the State of Alaska is financing 90% of the costs from the open season until the filing for the FERC certificate. TransCanada’s project will flounder as well once the FERC does not award a certificate due to the lack of shippers for the gas. Gas pipelines aren’t awarded certificates and pipelines don’t get built if they do not have gas to ship.

What is necessary for any gas pipeline to proceed is a comprehensive plan that changes the playing field, a plan that assures a reasonable tax, a plan that provides a modicum of certainty that the tax will not change every time the state needs additional revenue to balance its budget, a plan that shows the industry the state can manage its short-term capital and operating budgets in a way that shows restraint/discipline/understanding of their impact on the long term, a plan that includes a long-term fiscal plan that is not dependent on the oil and gas industry to balance its budget. What the state needs is a plan that changes the economics of the gas pipeline. It is time for a more comprehensive approach to Alaska’s future.

Some have advocated the state should build a large diameter gas pipeline through Canada. Some believe LNG will save Alaska through a large diameter line to Valdez. Some believe a large gas pipeline project will never get built and that Alaska should focus on a smaller diameter in-state gas pipeline. Some tout “Alaska’s gas for Alaskans” like it is some creed or motto that will automatically make whatever project they are supporting economic. The problem with all of these ideas is that without a more comprehensive picture, none of them will be economic, and none of them will ever get built.

There are at least eight issues that must be addressed in a comprehensive manner in order to move Alaska forward in bringing Alaska’s gas to market. Every proposal to bring Alaska’s gas to market should be required address all eight issues.

1) Fair oil and gas taxes

2) Long term fiscal plan

3) Short term annual capital and operating budgets

4) The permanent fund, its present and future use

5) Gas pipeline economics

6) Exploration and filling TAPS and the Gas Pipeline

7) Fiscal certainty/stable oil and gas tax environment

8) Point Thomson (hopefully this will be resolved soon by the State of Alaska and the Point Thomson owners)

Over the next several weeks I will propose alternatives that will address all eight issues. I have written previously about most of them, but I have a few additional ideas I would like to place on the table in advance of the October 18th Alaska Gas Pipeline Forum.

Alaskan Advocate - Where to From Here?

2011-03-25T14:02:00.000-07:00

Over the last year I have maintained a this blog as a commitment to Alaskans to provide them with a view that may be different than what they are hearing from the industry or government. My goal was to comment primarily on Alaska energy issues. The focus of the blog has been on oil and gas taxes, short and long-term fiscal responsibility, and gas pipeline issues. Because of personal obligations I may not be able to contine to comment on Alaskan issues, but I will attempt at least one additional article that will propose a more comprehensive plan on how to move the State of Alaska forward. It will include a discussion of a short and long-term fiscal plan, fiscal certainty, oil and gas taxes, a large diameter gas pipeline, in-state gas needs and Point Thomson. Some of the proposal will not be as specific as I would like because detailed information is lacking; other proposals will be quite specific. Regardless, I will recommend sufficient direction in each area to enable the state to move forward.

I am also not arrogant enough to assume my recommendations will be followed just because I made them. But I hope the article will at least move the debate forward in each of the areas I discuss.

Below is a list of the articles I have written over the last year. My next article will incorporate much of what I have already written below.

12/30/2009 - The Sovereign’s Responsibility

12/30/2009 - Fiscal Certainty and a Fair Gas Tax

12/30/2009 - Fiscal Certainty and a Stable Tax Environment

01/02/2010 - Timing of the Legislative Debate

01/02/2010 - Restructure Alaska’s Revenue System

01/05/2010 - Bob Swenson – Instate Gas Czar

01/06/2010 - PFD – To Enshrine or Not To Enshrine

01/13/2010 - Point Thomson – Where to From Here?

01/19/2010 - Do Oil Taxes Need Revision

01/27/2010 - Two Important Pipeline Variables

02/20/2010 - DNR Point Thomson Study Evaluated by Feds

02/21/2010 - Resource Potential of the Alaska North Slope

02/23/2010 - Geology is King

03/13/2010 - Which Pipeline Project is Best

03/14/2010 - Boring

03/21/2010 - In-State Gas Line

04/05/2010 - The Point Thomson Unit – The Next Step in the Process

04/28/2010 – A System Failure and An Idea

05/03/2010 – The Red Pen Challenge Update

05/27/2010 – Evaluation of Exploration in the Arctic OCS

06/14/2010 – BP Gulf Oil Spill Response Plan Review

07/30/2010 – Alaska Gasline Port Authority Proposal to Purchase Fairbanks Natural Gas LLC

09/06/2010 – Energy Issues in the Alaska Gubernatorial Race

09/08/2010 – Own a Piece of the Pipe – Part 1

09/09/2010 – Own a Piece of the Pipe – Part 2

09/11/2010 - Alaska Gasline Inducement Act (AGIA)

09/15/2010 - Analysis of the Twenty “Must Haves” of AGIA

09/16/2010 - Berkowitz Oil Revenue Proposal

09/21/2010 - Berkowitz Revenue Proposal Analysis

09/23/2010 - Political Posturing

09/26/2010 - State Ownership of the Pipeline

10/07/2010 - Clarification of the MidAmerican Deal

10/15/2010 - Natural Gas Pipeline Options

10/17/2010 - Equal Time for Parnell

10/19/2010 - Security Guards Need Education on Private Rights

10/26/2010 - Repost – Resource Potential of the Alaska North Slope

10/27/2010 - NPRA Oil and Gas Reserves History

11/01/2010 – Consider the Candidate

11/02/2010 – Legislative Agenda Proposal

11/15/2010 – Roadmap to a Fair Tax

01/26/2010 – The Real Cost of the Governor’s Proposed Oil Tax Change

02/10/2010 – An Either/Or World

03/14/2010 – The Specious Argument

03/17/2010 – Just the FACTS

03/24/2010 – Who to believe? Does it matter?

Who to believe? Does it matter?

2011-03-24T15:16:00.000-07:00

The Alaska State Legislature is currently engaged in a debate regarding changing ACES, the production tax on oil and gas, in hopes of encouraging new investment on the north slope and ultimately additional production to fill the TransAlaska Pipeline System (TAPS).

Many have entered into the debate regarding the tax. Some have argued that a change to the tax will increase jobs that have been lost due to the current production tax, known as Alaska’s Clear and Equitable Share (ACES); others have argued that the current tax system is working because jobs have increased on the north slope.

Some have argued that a change in the tax will multiply the revenue to the state many times over the cost of the change; others have argued that the tax change will cost the state billions of dollars over the next decade.

Some have argued that exploration drilling on the north slope has become almost nonexistent because of ACES. Others have argued that there were more wells drilled in 2010 than 2009. In fact the number of wells drilled in 2010 was the highest number of wells drilled since 2005.

Some have argued that the pipeline will be shut down if we don’t change the tax, but no one is arguing if we stay the present course that oil production will increase and the pipeline will once again be full.

Who to believe? Does it matter?

All who enter the debate seem to believe they need to justify their position based on either a positive or negative impact from the current production tax, ACES. But all are focused on the wrong question. It does not matter what has happened in the past, even what the actual impact of ACES has been. This is especially important since they will never agree on the results of that impact anyway.

What is clear is that production is falling on the north slope, and everyone agrees with this fact. What is also clear is that everyone would like to see production increase. The real question is how to go about encouraging industry decision-making so that more is invested on the north slope in hopes of increasing production to the benefit of both the industry and the state.

Where might the potential reserves be found and how many reserves can we expect or hope for?

Infield drilling and satellite fields - Small increases to production that will help stem the decline of production if produced, up to a few billion barrels here.

Heavy and viscous oil - Over 20 billion barrels of oil in place. If the technology could be conquered and the economics could be enhanced, perhaps several billion barrels of this heavy oil could be produced.

Exploration - Exploration could bring in several hundred thousand barrels of oil, so even though the amounts may be smaller, exploration should be encouraged.

NPRA - The State of Alaska receives half the bonus and royalty revenue from NPRA plus the state receives a production tax on all oil produced in NPRA. The federal government believes there are still hundreds of millions of barrels of oil to be found in NPRA. Even though this is not a large amount, it should be encouraged.

Federal OCS - Even though the state gets no revenue from the majority of offshore development, offshore production would provide jobs to Alaskans, increase the life of the pipeline, and perhaps someday the state could share in the OCS revenue if Congress changes the current law. Even though OCS development should be encouraged, it does not enter into the debate over changing the state's oil and gas tax.

What is the potential value of those reserves?

This is the estimation of the “golden egg” if the reserves can be found and produced. This estimation is the easiest to determine. Plug in the potential reserves from above, plug in a range of prices and the current tax and the potential value (or range of values) of those reserves can be determined. Any change in the tax can be compared against this range of values. Any change in the tax should be justified against the potential for the state to benefit through production of these additional potential reserves.

What are the options for encouraging industry to pursue those reserves?

The debate is not an either/or debate. It is not “reduce the tax on all production or don’t reduce the tax.” The decisions the legislature needs to make are more complex than that. There are several options or combination of options the legislature could pursue.

Credits - Credits gives the state one of the most measurable benefits of any alternative. One of the concerns is ensuring the state receives something in return for any reduction or benefit it provides to the industry. With a credit the state is guaranteed that the industry must invest in Alaska before it can apply for the benefit. Credits are a good option, but they may not supply sufficient benefit to entice the industry to produce all the reserves Alaska would like to see produced.

Focused reduction in tax - A tax that is focused on the reserves the legislature would like for the industry to pursue, i.e., additional reserves that could be produced through infield drilling, heavy and viscous oil additions, and exploration success.

Broad reduction in tax – this option is overinclusive, giving additional reduction in tax to reserves that would have been developed without the reduction, and it will be difficult to determine if the broad reduction was necessary or if a more strategic alternative would have worked just as well. But the legislature may determine it is the best means to obtain the results they are after.

Summary

The debate in the legislature often turns on looking backwards and using, or misusing, that data to justify a particular position the individual is advocating. The legislature should avoid getting into that debate. The key to moving forward is to recognize the current status of production on the north slope (decreasing production), what the state wants to happen (increased production), and where the potential production can come from (NPRA, infield drilling, heavy and viscous oil, and exploration) and most importantly how the state believes it can achieve its desired goal while obtaining the maximum return to the state for the benefit conveyed.

Just the FACTS

2011-03-17T11:57:00.000-07:00

Recently, in an editorial in the Anchorage Daily News, Representative Mike Hawker recognized how important the decision regarding changing the oil tax is to the future of Alaska. He expressed the concern that all Alaskans feel, that oil production on the North Slope is declining. He also noted that the difference between what the Department of Natural Resources predicted a few years ago for 2011 production and current expectations is 200,000 barrels per day. He went on to state, “Between the two forecasts, 600 million total barrels have been lost for the years 2010 to 2020”, a stark statement of what is in Alaska’s future. He concluded his editorial by recommending a change to the progressivity tax and stated that “These changes will result in real improvements to Alaska’s economic prospects if we stick to the FACTS - - that is, a Fair and Competitive Tax System. Just the Facts.”

Representative Hawker’s advice is important to remember. We should all strive to understand all the facts regarding the oil tax issue before jumping to any conclusions. For example, let’s take a look at the facts Representative Hawker uses in his editorial. He states,

“Just three years ago, DNR predicted 816,000 barrels per day production in 2011. Now the expectation is only 616,000. That is 200,000 barrels a day less. Between the two forecasts, 600 million total barrels have been lost for the years 2010 to 2020.”

He goes on to say,“The facts are clear. Exploration has all but ceased and production has been lost as a result of ACES.”

According to the facts Representative Hawker has provided in his article the reader should come to the conclusion that a change to ACES is necessary because ACES caused the production decline in the last three years. But nothing could be farther from the truth. Let's take a look at the real facts.

First, DNR is not the state agency that predicts future production. That would be the Department of Revenue, in their annual Revenue Sources Book. The Crude Oil Production – Forecast can be found in Appendix C-2b of each year’s Revenue Sources Book. The following list is the Department of Revenue production forecast for the year 2011 for north slope oil from the years 2004 through 2010.

Fall 2004 forecast 975,000 bbls/day

Fall 2005 forecast 853,000 bbls/day
difference from 2004 – 122,000 bbls/day

Fall 2006 forecast 782,000 bbls/day
difference from 2005 – 71,000 bbls/day

Fall 2007 forecast 676,000 bbls/day
difference from 2006 – 106,000 bbls/day

Fall 2008 forecast 644,000 bbls/day
difference from 2007 – 32,000 bbls/day

Fall 2009 forecast 623,000 bbls/day
difference from 2008 – 21,000 bbls/day

Fall 2010 forecast 616,000 bbls/day
difference from 2009 – 7,000 bbls/day

So what does the above tell us. First that three years ago the revenue forecast predicted 676,000 bbls/day, not the 816,000 bbls that Rep. Hawker stated. The resulting difference would be 60,000 bbls/day instead of the 200,000 bbls/day the representative stated.

The reason the representative had to go back so many years is because in recent years the change in the production forecast has not been significant. To find a substantial difference between predictions the representative would have had to go back to the Fall 2006 forecast. Between the Fall 2006 forecast and the Fall 2007 forecast the state lost 106,000 bbls/day. Perhaps that can be attributed to the change in the tax from PPT to ACES.

The best place to look for the answer would be in the Fall 2007 Revenue Sources Book. There the Department of Revenue states at pp. 46-47:

“To account for unforeseen production interruptions slopewide, as well as anticipated scheduled interruptions attributed to renewal projects, we have increased our estimates of downtime at the Greater Prudhoe Bay Area, the Greater Kuparuk Area, Milne Point Unit and Endicott for the next 6-8 years, depending on the field. The impact of this deferred production is significant in the near term, ranging from 30,000 – 70,000 barrels of oil per day slopewide. This is in addition to the rate impacts attributed to reevaluating the scope and timing of projects under development and under evaluation.”

So even the significant change that occurred in the 2011 production projection from 2006 to 2007 had nothing to do with taxes. It had to do with attempting to incorporate downtime into future production scenarios.

In addition, if you graph the Revenue Sources Book production projections for each year from 2004 to 2010, what you will find is that the state is generally more optimistic in its production projection than what actually occurs. Production projections are based on what the Department of Revenue consultants can project will probably occur in the future based on what they know about the reservoir, decline curves and industry plans to bring a development online. Production predictions have nothing to do with tax changes.

So as you review the facts relating to impacts from a change in the oil tax, make sure you understand the FACTS, all of the FACTS, and nothing but the FACTS.

The Specious Argument

2011-03-14T23:24:00.000-07:00

I recently finished watching the March 10, 2011 Governor’s Press Availability on Gavel to Gavel where the governor discussed his tax change legislation. He discussed the three areas of focus for the bill, 1) new units (tax reductions for areas not in production now), 2) infield drilling tax credits, and 3) progressivity changes. And he explained that his administration is “focused on creating more production here, more investment here, more jobs here.”

This is all well and good and I commend him for his energy and effort, but I question his response to those who have expressed concerns that his legislation could cost the state billions of dollars. In response to those stated concerns about the cost of the legislation he stated “Let’s talk about that specious argument before we go any further.” His comment was out of character for the governor and without a rational basis for the position taken. In the past the governor has not used such a pejorative comment in referring to those who oppose him. Normally he would merely have responded with his position, supported by facts and analysis without putting the opposition down. So why did he use such a strategy this time?

There are several possible reasons why he attacked the opposition with name calling instead of analysis.

Perhaps because he didn’t remember that it was his own staff who wrote the fiscal note that stated the financial impact of the change to the tax would be in the billions. Perhaps he was not around to listen to his Department of Revenue Commissioner and revenue staff explain that the impact would be in the billions. Perhaps he did not read his consultant’s report and did not listen to his consultant testify that the long term cost of the change could be approximately $20 billion.

Or perhaps he is just uncertain about the position he has taken and doesn’t know how to logically defend it; so he reverted to name calling and putting down the opposition.

Or perhaps he doesn’t understand cost/benefit analysis. In its most basic form cost/benefit analysis is first understanding the short and long term cost of the change as well as you can. Once you fully understand the costs of the change, you must determine what the proposed benefits will be and the chance of those benefits occurring. Then you calculate the difference. The result may be that there will be more jobs for Alaskans or the life of the pipeline will be extended, or the possibility that the state may never recoup the difference in tax it gave up in the legislation. Even with the potential negative impact of not recouping the cost of the change in tax, the state may determine the change is still a reasonable course of action. The state may determine it wants short and long-term jobs and an extended life of the pipeline more than it wants to fill its savings account. This would be an acceptable analysis.

But what is not acceptable is not counting the costs and arguing that those costs are not real, that they are “fantasy,” that concerns regarding the costs are “specious.” The costs are real. They can be determined within in a reasonable range, and they range in the billions of dollars. What is not real, what cannot be determined, and what can only be hoped for are the benefits from such a tax change. Those benefits may occur, but they cannot be calculated because a third party must make an independent decision sometime in the future based on present actions by the legislature. Maybe it will be worth it, but the state should count the cost and understand the risk before making such an important decision.

What the governor should have done is provide the analysis necessary to support his position, provide the analysis necessary for the Alaska public to support his legislation, provide the analysis necessary for the legislature to pass his proposed legislation.

What the governor should have done is provide the legislature with an analysis of possible decline curves.

The governor’s consultant used a 6% decline curve to define what might happen if the legislation was not passed; yet the governor’s Revenue Commissioner presented an estimation of future revenue based on a 3.2% decline curve under the current tax. What does the governor believe to be true? What are the ranges of possible decline and what are the bases for those assumptions?

What the governor should have done is explain to the legislature where the governor believes the new reserves are to be found.

A thorough understanding of reserves potential is essential for the legislature to understand so they can determine if there are sufficient potential reserves to compensate the state for the lost revenue from the change in the tax.

What follows are projections from the United States Geological Survey and the State of Alaska, Department of Natural Resources, Division of Oil and Gas of resource potential of exploration areas of the north slope.

NPRA: consists generally of lands west of the Colville River and north of the Brooks Range.

The National Petrolem Reserve-Alaska is not a good source for future oil revenue. The USGS has recently substantially reduced the reserves of technically recoverable conventional accumulations of oil it believes are located in NPRA to less than a billion barrels of oil, about 10 percent of what it previously projected to be in NPRA (See 2010 Updated Assessment of Undiscovered Oil and Gas Resources of the National Petroleum Reserve Alaska (NPRA) ).

Beaufort Sea: consists of all offshore state lands between Pt. Barrow and the U.S-Canadian border.

The Department of Natural Resources, Division of Oil and Gas has projected: “The petroleum potential in the area is considered moderate to high.” (See the January 2011 Five-year Program of Proposed Oil and Gas Leasing Program Report at page 22).

But concerns about oil spills in the offshore environment, concerns about the oil industry’s ability to clean up oil in broken ice, concerns about bowhead whales, polar bear habitat and two species of endangered seals may make it difficult to explore for or produce oil from offshore in the near-term.

North Slope Areawide Oil and Gas Lease Sale: the area consists of all state-owned lands between the National Petroleum Reserve-Alaska (NPRA) and the Arctic National Wildlife Refuge (ANWR), and from the Beaufort Sea to the north and the Umiat Meridian Baseline to the south (an east/west line drawn just north of Umiat, Alaska).

The Department of Natural Resources, Division of Oil and Gas has projected: “Petroleum Potential in this area is considered low to moderate with the potential generally increasing from south to north.” (See the January 2011 Five-year Program of Proposed Oil and Gas Leasing Program Report at page 27).

North Slope Foothills: the area consists of all state-owned lands between the National Petroleum Reserve-Alaska (NPRA) and the Arctic National Wildlife Refuge (ANWR) south of the Umiat Meridian Baseline and north of the Gates of the Arctic National Park and Preserve.

The North Slope foothills are not a good source future oil potential. The Department of Natural Resourses, Division of Oil and Gas has stated “Petroleum potential in the area is considered relatively high for gas, and relatively low for oil." (See the January 2011 Five-year Program of Proposed Oil and Gas Leasing Program Report at page 30).”

Even though the governor believes that these areas “have not been touched for thousands of years,” they have actually been evaluated and tested geologically. That is why the Division of Oil and Gas can project the potential for oil in this area as relatively low. The legislature should request a map of the north slope depicting all the wells that have been drilled. Then the legislature should ask one of the geologists at the Division of Oil and Gas to explain why they believe the oil potential in this area is low.

Federal OCS: the offshore area in the Chukchi and Beaufort Seas seaward of the state offshore.

Even though the governor referred to Shell’s exploration activities in the Chukchi Sea during his press availability, the governor’s tax legislation does not affect Shell’s offshore projects from an economic standpoint because the tax credits do not apply to the federal offshore and the state has no power to tax the federal offshore.

What the governor should have done is explain to the legislature when the new reserves are projected to be produced.

The state land with the greatest oil potential (high potential) is the state offshore, the most difficult area to permit and develop a field. Bringing production on from the state offshore will take at least 10 years and probably closer to 15 years if it can be done. In fact even permitting and developing a new onshore field (low to moderate potential) will take at least 10 years. Therefore we should not expect or depend on any revenue from new exploration in the short-term and little in the long-term.

What the governor should have done is explain the projected revenue and the timing of that revenue from the reserves he proposes will be found.

Even though we don’t expect much from new exploration, the credits have not cost the state much. But maybe someday, many years from now, any new production to be found will be a net positive from a revenue standpoint (after deducting the cost of the credits). In addition, what can be determined with reasonable certainty is that revenue from new exploration will not begin to balance the cost from the tax change for at least 10 years.

What the governor should have done is explain to the legislature the criteria the governor is using to determine if or when the tax change has failed.

In his Press Availability the governor suggested that the legislature would not sit idly by if the proposed tax change was not having the desired effect. What the governor needs to share with the legislature are his expectations for a successful outcome. What would he consider a success? What would the governor consider a failure? How long is the governor willing to wait to see positive impacts from the tax change?

Finally the governor in a final posture challenged the press to ask the “nay sayers” that say the governor’s proposal is going to cost so much what their plan would be. Well I’m not necessarily a nay sayer, and I am certainly not a legislator, but I do believe the governor and the legislature should count the cost before they make such broad sweeping changes to the oil tax. And as far as proposing a plan, I have written close to 40 articles in this blog proposing what the governor and legislature should do, but if the governor doesn’t understand what I am suggesting he is free to give me a call and I will be glad to help him out.

Additional Note

The governor made one comment regarding the large diameter pipeline that is worth clarifying. In referring to the position of the pipeline companies he stated that “Before we commit to buying pipe, we need fiscal certainty.” That would suggest he believes that TransCanada and Exxon or Denali pipeline company needs fiscal certainty before they can commit to buy pipe. Actually the pipeline company does not need fiscal certainty; the shippers need fiscal certainty and they need it before they are willing to commit their gas to the open season. Fiscal certainty has nothing to do with the pipeline companies buying pipe. Fiscal certainty is being requested by the shippers before they are willing to commit their gas at the open season. That is one of the reasons why the open season process has stalled. I am surprised at this basic misunderstanding of who needs fiscal certainty, when it is needed and the risks associated with moving a pipeline project forward.

An Either/Or World

2011-02-10T08:55:00.000-08:00

At times in Alaska’s history individuals saw a vision of what Alaska could be and committed themselves to the success of that vision. The purchase of Alaska from Russia, the discovery of gas in Cook Inlet, Alaska Statehood, the discovery of oil at Prudhoe Bay, the creation of the Permanent Fund; each took vision, each took commitment, each took leadership, each took work, each carried a substantial amount of risk of success, and each resulted in a significant change to Alaska’s future. Each was a decided break with the past. Sometimes in history choices need to be made. Sometimes a specific direction needs to be taken. Sometimes decisions need to be made. If those decisions are not made, opportunities escape. Sometimes life really is an either/or world.

It is time to either develop a strategic plan to develop and produce Alaska’s resources or muddle along and see Alaska’s future dwindle away.

It is time to either choose a direction and develop a plan for an Alaska Gas Pipeline or allow the opportunity to pass Alaska by.

It is time to either address Alaska’s long term fiscal needs or inherit the results of indecision 20 years from now.

If Alaska wants a gasline; if Alaska wants to see continued production; if Alaska wants continued oil and gas exploration and development in its future; if Alaska wants future generations to inherit a strong stable economy, it is time for action.

But merely taking action without evaluating what action should be taken is irresponsible. Those who want do something because it is better than doing nothing at all are misguided. Change must be based on rational analysis. A good strategic plan will analyze the State’s resources and strengths. It will analyze the impediments to success, and it will develop a plan to move forward that hopefully increases the likelihood of success and reduces the likelihood of failure. So what are Alaska’s resources and strengths? What are its weaknesses? And what would a viable strategic plan look like?

Alaska’s strategic resources

1) Prudhoe Bay/Kuparuk – North Slope oil production has provided Alaska with substantial wealth in the past and can continue to be the base upon which Alaska builds its future. The goal regarding Prudhoe should be to create a fiscal environment where the producers have incentive to:

a. Maximize the production from currently discovered reservoirs

b. Encourage exploration for satellite fields close to development

c. Encourage development of heavy and viscous oil

2) Alpine/Colville River/Eastern NPRA Development – Discoveries have been made here but development of additional reserves has been stalled due to permitting delays. The goal for this development region should be to:

a. Work with producers and state and federal agencies to bring these known resources to market and to develop the infrastructure to encourage additional exploration.

b. Northeastern NPRA is one of the few areas onshore North Slope where there is still potential for finding significant oil reserves. Work with the various stakeholders, including the North Slope Borough, the village of Nuiqsut, and the federal and state agencies to develop an environment where cultural values are protected and development can still occur.

3) NPRA in general – encouraging exploration of the rest of NPRA is somewhat a waste of time until and unless the gas pipeline issues are resolved. A recent report by the USGS titled “2010 Updated Assessment of Undiscovered Oil and Gas Resources of the National Petroleum Reserve in Alaska (NPRA) makes it clear that the largest potential for undiscovered oil lies in northeastern NPRA and the largest potential for nonassociated gas resources is in structural plays in southern NPRA. If the gas pipeline issues are resolved, NPRA exploration will once again become viable.

4) OCS Beaufort Sea/Chukchi Sea – OCS development will not add much to the State general fund because the state receives no royalty from OCS development and it does not have the power to tax that development, but oil discoveries from the OCS will extend the life of the TAPS oil pipeline. And if a gas pipeline is built, exploration for gas in the OCS will also increase. The North Slope Borough is currently opposed to all exploratory drilling that cannot be done in the winter from an ice island or from a bottom-founded drillship. They oppose all summer exploration that must be done from a floating drillship because of concerns about oil spills and how those spills might affect the bowhead whale and other marine mammals. The state needs to work with the North Slope Borough to see if there is a way that exploration can move forward in open water without their opposition. If a way cannot be found to resolve the North Slope Borough’s concerns, OCS exploration and development will probably not occur in the near term. And if it does occur, it will happen only after costly and time consuming litigation.

5) Point Thomson – enough has been said about Point Thomson in previous posts. It is time for the State and ExxonMobil to resolve their differences and move ahead with this project.

Alaska’s strengths

1) Alaska has the ability, given the proper leadership, to respond to circumstances and change course quickly. This is one strength that most other states are incapable of. Most other states take years to make minor changes to the direction they have taken, but Alaska is unique in that it can recognize circumstances that require a change in course, and it can respond quickly to take advantage of opportunities that may present themselves.

2) Alaska has funds in reserve. Alaska has its Permanent Fund and billions of dollars in savings. Revenue in reserve always provides options.

Impediments to Success

Alaska currently has no vision regarding an Alaska Gas Pipeline. Some want an instate line, some want a trunk-line to Fairbanks, some want to export the gas to the Pacific Rim, some want to stick with AGIA, others are rooting for large diameter line through Canada but don’t believe in AGIA. What is clear is that a State divided over this issue will not succeed.

Proposed solution

So how do Alaskans wade through all the options to come up with the optimum outcome. The first question to ask is what does Alaska really want? If Alaskans could choose from all the above outcomes, which one would they choose? Which one would have the greatest benefit to the people of Alaska? Actually, the answer is clear. A large diameter pipeline, if it can be built, would have the greatest benefit for the people of Alaska.

Then what about an AGIA line vs a pipeline to tidewater for an LNG project vs a non-AGIA line? These are actually questions that don’t need to be answered today. A line to tidewater vs a line through Canada are commercial questions that the owners of the gas will decide at the open season. They are questions that don’t need to be decided by the legislature.

Well what about an AGIA pipeline vs a non-AGIA gasline? Are the remaining benefits of AGIA worth $500 million?

First, the 20 “must-haves” of AGIA have either been accomplished or created no additional value when the Act was passed. See the previous article on this blog titled “Analysis of the Twenty “Must Haves” of AGIA” posted September 15, 2010. It is clear that the only remaining value of AGIA is the $500 million in exchange for TransCanada continuing to move the project forward through the filing of the FERC certificate.

Some have argued that the data collected and the documentation created, if the state allows it to be used by the new consolidated group of TransCanada, ExxonMobil, ConocoPhillips and BP, may save the project up to a year in getting to a project sanction decision. Others have said it is just wasted money that should not be spent on useless paper. If there is value to the $500 million reimbursement, this is where you would find it.

With all that said, AGIA doesn’t really matter. Currently there are two competing projects. Ultimately there will only be one project and AGIA will be immaterial to the successful outcome of that project. The key question for the state is what can the state do now to increase the likelihood of success of that large diameter gas pipeline project.

Elements of a successful large diameter pipeline strategic plan

This is the area where the need for a strategic plan is greatest. A disjointed, non-directional plan here will result in failure. A strategic plan for success requires leadership. It requires broad support from affected stakeholders. And it requires specific actions to address specific problems and concerns.

1) A fair gas tax – the issue of a gas tax must be addressed. It is interesting that the oil tax has garnered a substantial amount of energy and effort, but discussion of the tax on gas is non-existent. The idea seems to be that the State will wait for the producers to come to them and tell them what is needed. This apparently will come in the form of conditions for committing gas to the pipeline. This thinking is not logical, and the state will eventually find that the information obtained from a failed open season will not result in a specific proposal from the producers. The producers will only reiterate what they have stated in the past – that the state needs to provide them with fiscal certainty/stability and a fair gas tax. It is time for the state to start the discussion regarding a fair gas tax. Do the research. Acquire the information necessary to make a reasoned decision, and pass a fair gas tax.

2) Fiscal Certainty/Stability – the producers say they need fiscal certainty because they are concerned that if the state is running short on revenue to balance its budget, the legislature will change the tax on gas once the gas pipeline is built, thus changing the economics upon which the producers committed to ship their gas.

Fiscal certainty can take many forms. Certainty can be created by contract; it can be created by an amendment to the State Constitution; it can be created by statute, although the producers have said they are not comfortable with certainty created by statute because the legislature in the next legislative session can change the certainty provided for in the last legislative session. Another form of certainty can be created by making sure that the legislature cannot change the tax on gas in order to resolve its short term financial problems. If the gas tax was not available to the general fund, a certain level of fiscal certainty would be provided to the producers. The producers have not taken a position on this form of certainty and whether it would suffice to meet their concerns, but it is one option that should be considered.

3) Risk Sharing – If the state is truly committed to a large diameter pipeline project, it might consider sharing some additional risk in the construction of the project. The two easiest means for sharing risk are 1) participation in the ownership of the pipeline, and 2) committing to ship the state’s royalty gas on the pipeline. Both of these options have been considered by prior administrations, and there is a significant amount of analysis available to the legislature if it would like to pursue either one of these options.

Summary

In summary, a great opportunity lies before the state. The state can either commit the effort and resources necessary to make a large diameter gas pipeline project a success or the state can prepare for the gradual decline of its resource base followed by a dependence on the Permanent Fund to finance governmental services in addition to whatever taxes the people of Alaska agree to pay. It’s an either/or world, and it’s time to choose.

THE REAL COST OF THE GOVERNOR’S PROPOSED OIL TAX CHANGE

2011-01-26T21:12:00.000-08:00

Recently Governor Parnell addressed the Alaska Legislature in his State of the State address. In that address he mentioned his proposal to lower taxes on oil but did not go into any great detail regarding the proposal. For perspective I have included herein the entire paragraph from the governor’s speech regarding the need to lower oil taxes:

“So the question tonight is, how do we continue growing an even more vigorous and diverse economy? And how do we create that gravitational pull for private-sector investment and job growth? It takes four things: keep taxes low, gain access to our resources, invest in Alaska energy, and strategically expand undeveloped resources. That's why this year I'm asking that we work together to lower taxes on oil, and create more jobs in Alaska. Let's build off the success of last year's tourism head tax reduction that pulled more investment to Alaska. Let's pass legislation to make our oil tax regime more globally competitive. Lower taxes lead to more resource development, and that leads to more jobs for Alaskans.” – Governor Parnell

House Bill 110 was submitted to the legislature at the request of the governor to address his recommended changes to the oil tax. According to the Department of Revenue fiscal note, the tax change could cost the people of Alaska approximately $5 billion over the next five years. But the tax is not just a five year tax. It affects all existing and future producing properties in the State of Alaska for the life of the leases. So why has the impact been projected to cost $5 billion? A quick look at the nature of fiscal notes gives us the answer. The impact of the tax change was projected to be $5 billion merely because of the relatively arbitrary reason that fiscal notes are only required to identify impacts for five years. The real question someone should ask is, “What happens in year six and every year thereafter?” The answer they will find is that this is not a $5 billion tax. It is a tax change that will cost the people of Alaska in excess of $10 billion over the life of the leases.

So what does the governor propose the people of Alaska get for their $10 billion? The answer is more jobs and hopefully more oil and gas exploration and development. But how do we know if this is a good deal?

Alaska jobs makes a good emotional appeal but certainly cannot justify the price tag of $10 billion. The only way to justify a tax change of this magnitude is through exploration and new production. The following examines the value of the proposed tax change to bring about new exploration and production.

Impact of the tax change on exploration and production

To determine the impact of the proposed oil tax change on production and on production from successful exploration it is important to first determine the projected production based on the current tax system. The best source for that information is the recent Department of Revenue, Oil and Gas Production Tax Status Report to the Legislature dated January 18, 2011. On page 10 of that report the department displays a chart showing production from all existing and discovered fields that the department expects will be produced between now and 2030. This is the Department of Revenue’s projection of present and future production based on the current oil tax without the proposed changes.

Impact of the tax change on production

Changes to the tax should see significant increases in production in addition to what has been identified in the chart. The problem is that state land, from the Colville to the Canning Rivers, is a mature province for oil production. We should not expect to see nor project discoveries in this area of anything greater than what we have seen over the last ten years, basically incremental satellite production which will, at best, reduce the production decline curve but should not be expected to increase production substantially over the next 20 years. The state will not capture a lot of incremental value here.

In terms of the legislation, the section that amends Alaska Statutes 43.55.011(e)(1) and (g)(1) reduces the oil tax by over $10 billion over the term of the life of the leases on the currently producing units with the hope that this change will increase exploration and development to sufficiently offset the tax change. The likelihood of this occurring on state lands is almost nonexistent. The only hope of significant additional production on state lands comes from increased production of viscous and heavy oil which will be addressed later in this article.

Changing the tax structure on existing production will only incentivize the producers to increase production in the existing fields which, as I have said above, will not occur to any major extent because of the maturity of the existing fields. In addition a tax change of this magnitude will have a significant impact on the future revenue of the state.

The Department of Revenue on January 25, 2011, made a presentation to the Senate Finance Committee regarding the Fall 2010 Revenue Forecast and a 10 year Revenue/Spending projection. On slide 9 of that presentation the department showed their projection of the potential revenue surplus over the next 10 years based on estimated revenue and spending projections. The tax change as proposed in HB 110 would all but wipe out this projected surplus and by the year 2021 would probably result in a deficit. The legislature should assure itself of the value it expects to receive in exchange for such an extreme change in the future revenue picture of the state.

Impact of the tax change on exploration

Changes to the tax structure on existing production will not incentivize exploration. Only changes to taxes on production discovered through exploration will incentivize exploration and the only place where significant oil exploration can still occur is in NPRA. The OCS still has significant potential for oil exploration, but the state has no power to tax the OCS oil; so I have not included it in this discussion.

The changes to the tax structure to incentivize exploration is a good idea because the geology of the NPRA is not all that impressive. Analysis by the Department of Energy, National Energy Technology Laboratory suggests that we can expect to find a few fields similar in size to Alpine and a number of smaller fields but nothing the size of Prudhoe Bay. And the most prospective area around Teshekpuk Lake near the Barrow Arch is currently off limits because of cultural and environmental concerns. The proposed changes to the tax structure for exploration do not cost the state any revenue from current production. It only provides that if oil companies will explore for oil in Alaska, they will pay less tax on that oil. The tax incentive may not be enough, but it is a step in the right direction.

You cannot incentivize an oil company to explore for oil where they believe none exists, but you can incentivize an oil company to explore for oil where they believe oil might exist, even if their belief is that the chance of finding that oil is low.

If changes are made to the oil tax and additional exploration tax credits are added this year, the state may see renewed interest in exploration for oil in NPRA. In a few years, if there still seems to be a lack of interest in exploring for oil in NPRA, the legislature may need to revisit this area to see if additional incentives are appropriate.

Impact of the tax change on heavy and viscous oil

Production of heavy and viscous oil is technically challenging and costly to produce. The tax change reducing the oil tax on existing producing fields will certainly help, but it may not be enough. Plus the tax is overbroad in its application. The producers do not need a tax reduction to produce most of the current oil that remains in the existing fields, but they may need a tax reduction to produce the viscous and heavy oil. A tax reduction that is targeted to oil that is technically challenging and costly to produce makes a lot more sense than a tax change that provides reductions where none are necessary, especially to the tune of $10 billion. Plus a tax reduction that is targeted to areas where the need has been identified can be much greater than was proposed for the existing fields and the negative impact will be much less. If a change in the tax can incentivize the oil companies to produce the heavy and viscous oil, the potential revenue from this production could be substantial since there are billions of barrels of viscous and heavy oil waiting to be produced.

Summary

Tax changes should be targeted to where there is an identified need to encourage action from the producers. Tax reductions and credits that encourage production of technically challenging and costly oil make sense. Tax reductions that encourage exploration of NPRA make sense. Any other tax reductions that are directed at addressing a specific identified need make sense. Tax reductions where a need cannot be identified is a gift to those who receive the reduction.

Roadmap to a Fair Tax

2010-11-15T22:18:00.000-08:00

First, a fair tax on oil and gas will not result from “negotiations” with the producers even though it may be a good idea to meet with them to discuss and hear their concerns with the present fiscal system prior to and during any proposed changes to the current tax system.

Generally the producers will oppose what they don't agree with and aggressively oppose what they really don't agree with. The question is how to get the producers engaged in a way that creates productive exchange. The answer is you open up a public dialogue about oil and gas taxes. In that discussion they will explain what they don't like but not help you draw a line on what would be acceptable to them. Their goal will be to continue to put downward pressure on the system and to achieve the lowest tax they can achieve. That position does not allow them to support any tax changes even if the changes would be better than they are now. Their answer will be "that is not good enough." They will also not commit to additional exploration or additional investment based on a tax change.

With that in mind what is required is to get as analysis through models you can trust and try to develop a fair tax. During that analysis you will need to filter the comments made by the producers and figure out if what you are doing is fair based on their negative input. Here is how I would go about the analysis. First, separate analysis should occur for oil and for gas. The pipeline tariff on gas and the substantial volumes of gas that need to be transported to make a reasonable profit makes gas economics substantially different than oil economics.

A fair tax on gas includes an understanding of the possible range of tariffs for a gas pipeline. But the actual cost of the pipeline is not the critical element. The gas tax, like the oil tax should be fair at a range of prices from a marginal net value to a value of gas that is “wildly economic” as some used to say.

Once you distinguish the differences in economics between gas and oil, then break down the discussion between the different economic types of production and exploration, i.e., major know oil fields like Prudhoe and Kuparuk, extension exploration that extends the limits of the fields or that finds puddles near infrastructure, heavy oil production in those fields, known fields like Point Thomson which are large and have economic potential under the right circumstances, smaller marginal fields, exploration on state lands, exploration in NPRA, exploration offshore - state lands and fed lands. On offshore prospects distinguish prospects that can be explored from onshore and from bottom-founded rigs from exploration that must be conducted in the summertime from floating structures. Distinguish the Chukchi from the Beaufort. Recognize that we get no revenue from the Chukchi or Beaufort OCS but we should continue to pursue it (exploration and revenue). Next a comparative economic analysis should be done with other oil and gas provinces to determine the competitiveness of Alaska exploration and development from those in other provinces. Once you understand the relative economics of each of the above variables you can then begin to discuss deductions and credits vs reduction in tax.

Regarding progressivity - I still like some form of progressivity, but we need to remember that progressivity was based on a contractor spreadsheet that modeled Prudhoe Bay development, the most economic of all oil and gas development in Alaska. We knew at the time that there was a possibility that the tax might be too high. The bellwether areas for negative impact due to the tax would be heavy oil and exploration. We now have enough data to begin to see the impacts of the tax on exploration and heavy oil production. BUT we must always remember GEOLOGY IS KING. If the prospects aren't there, the producers won't explore no matter how low the tax. What we can't determine is if the producers aren't exploring because they think the taxes are too high or because the prospects are poor.

What we do know is that there is plenty of heavy oil and the producers aren't pursuing it aggressively. So there is a strong likelihood that economics are affecting the producers' desire to develop heavy oil on the North Slope. A discussion regarding the economics of heavy oil would be a productive discussion for the governor and the legislature to have with the producers.

If the legislature conducts the above analysis, it will have sufficient basis and understanding to make good decisions regarding one of the most important issues facing the state this year.

Legislative Agenda Proposal

2010-11-02T22:53:00.000-07:00

Responsible Annual Budgeting, Budget Surplus, Budget Transition Period, Long-term Fiscal Plan, Permanent Fund, Nonrenewable Resources, Reserves Potential, Fiscal Stability, Fiscal Certainty, Fair Oil Tax, Fair Gas Tax, Alaska Large Diameter Gas Pipeline, Alternatives to a Large Diameter Gas Pipeline, Cook Inlet Gas Requirements, Interior Alaska Gas Requirements, Southeast Energy Requirements, Rural Energy Requirements, Alaska’s Gas for Alaskans, Point Thomson, what do all the items in the above list have in common? They, along with many other issues, must be considered in the context of each other to arrive at a comprehensive strategy to move the State of Alaska forward in the coming years.

A stable long-term fiscal strategy that does not require short-term changes to oil and gas taxes to balance the budget goes a long way to create the fiscal stability the oil and gas industry requires to invest in Alaska.

A fair tax on oil and gas that is fair at low prices and high prices, that is fair for marginal prospects robust prospects, that is fair for remote prospects as well as close-in prospects creates an investment climate that encourages explorers to test Alaska waters.

An annual budget that shows fiscal restraint and forethought about the future encourages business to invest because they are not concerned that they will be the ones called upon to supply the funds necessary to balance the budget now or in the future.

Examining those actions the state can take to encourage a large diameter gas pipeline may result in identifying certain steps that actually helps the pipeline move forward.

Getting existing development back on track encourages a business climate where industry can once again believe in fair treatment in the regulatory process.

Understanding the difference between meeting Alaska’s energy needs with “Alaska’s Gas” and meeting Alaska’s energy needs with the most economic energy alternative, for the short-term and the long-term is essential prior to making major funding decisions regarding energy projects.

Understanding and encouraging exploration to capture Alaska’s reserves potential while basing budgets on known resources is essential to sound decision-making.

Understanding that the Permanent Fund must play some part in the future of Alaska, more than just paying Permanent Fund dividends, is essential in developing a viable long-term financial plan.

The State’s obligation is to create a fiscal environment whereby business is secure and willing to take the investment risk necessary to succeed. It’s time to create that fiscal environment.

The above list is long and many complex issues are included, but it is one that can be accomplished. It’s time to get started. It is time to establish a plan. It’s time to lead. My hope is that the governor and the newly elected legislature are up to the task.

Consider the Candidate

2010-11-01T09:55:00.000-07:00

My son made an interesting comment to me this morning after watching a few minutes of TV. He said, “I wish they would outlaw negative campaigning so that we could understand the views of the candidates.” His comment is important to remember. When we vote tomorrow, we should try to ignore all the negative campaigning that has occurred and try to remember what we know about the candidate.

Are they people of integrity; are they people we can trust?

Are they respected by their contemporaries? Will others respect and listen to them if they are elected?

What about their positions; have they held them a long time? Can they express them in a way that will influence others to agree with them? Will they make a difference if they are elected; is the difference they are going to make one that we want?

Consider what you know about the candidate as you go to the polls tomorrow, not merely what others have said about them. Vote for someone you think might do the best job, not against someone based on what others have said about them.

NPRA Oil and Gas Reserves History

2010-10-27T11:03:00.000-07:00

It might be helpful to understand the current USGS NPRA oil potential predictions in context. Below are some historical projections made by the USGS.

1.9 BBO USGS 1976

2.1 BBO USGS 1980

1.48 BBO December 31, 2000 (EIA, 2001)

9.3 BBO USGS 2002 NPRA Only

10.6 BBO USGS 2002 NPRA Entire Area

10.4 BBO June 30, 2005 (Bird, et al 2005 and AOGCC, 2005)

0.896 BBO 2010 Updated USGS Assessment of the NPRA

What is apparent from the above is that the current 2010 projections are only slightly less than the projections in 2000. The big change came in 2002 when the USGS increased the potential reserves almost 10 fold. The question one might want to ask is what happened between 2000 and 2002 to allow the USGS to increase reserves of the entire NPRA to such a great extent. The assumptions the USGS made in 2002 turned out to be wrong. They have now scaled back to the projections they made in 2000.

The USGS continues to be optimistic on gas. Below are the historical projections made by the USGS on gas. Please note the substantial change in reserves potential predicted in 2002.

6.3 tcf USGS 1976

8.5 tcf USGS 1980

59.7 tcf USGS 2002 NPRA Only

61.4 tcf USGS 2002 NPRA Entire Area

52.8 tcf USGS 2010 NPRA

The USGS may be right about the potential for gas reserves in NPRA because there has been very little exploration for gas in the basin, but we will not find out if they are correct about their projections unless there is a major gas pipeline from the north slope to market the gas. No exploration company will explore for gas without the reasonable likelihood of getting that gas to market.

Repost - Resource Potential of the Alaska North Slope

2010-10-26T22:35:00.000-07:00

The USGS recently published a 2010 Updated Assessment of Undiscovered Oil and gas Resources of the National Petroleum Reserve in Alaska (NPRA). The report can be found at http://pubs.usgs.gov/fs/2010/3102/pdf/FS10-3102.pdf

In that report the USGS downgraded the oil resource potential of NPRA from 10.560 billion barrels of oil to 0.896 billion barrels of oil. The new total is only about 10 percent of the total oil estimated in their 2002 assessment. They also slightly downgraded the gas potential of NPRA from 61.352 trillion cubic feet of gas to 52.839 trillion cubic feet of gas.

Earlier this year I wrote an article regarding the resource potential of Alaska’s North Slope. I am reposting it here. What I attempted to show in that article and is apparent from the recent USGS revision is that “optimistic assumptions” about Alaska’s resource potential are exactly that – optimistic assumptions. Present budgets and future budget projections should not be based on the hope that large discoveries of oil and gas will be made in Alaska in the future.

In my next article I will discuss Alaska’s long term outlook in light of the USGS revised projections. I will also discuss some potential options Alaska should consider based on a range of outcomes that may occur in order to protect itself into the future.

Repost - Resource Potential of the Alaska North Slope

The Department of Energy, National Energy Technology Laboratory published a report titled “Alaska North Slope Oil and Gas A Promising Future or an Area in Decline in August 2007. The NETL recently published an Addendum to the Report. The report has often been quoted and used as a basis for projections of future oil and gas potential of Alaska’s North Slope.

The report is helpful in evaluating the prospectivity of certain areas of the North Slope as compared with other areas. For example, onshore state lands between the Colville and the Canning rivers and State Beaufort Sea, (basically all state lands on the North Slope) represent only ten percent (10%) of the future economically recoverable oil potential on the North Slope. Ninety percent (90%) of all future economically recoverable oil potential will be discovered on lands not owned by the state: twenty-one percent (21%) will be discovered in NPRA where the state will receive a production tax but no royalty; forty-seven percent (47%) will be discovered on the federal OCS lands where the state receives no royalty or production tax; and twenty-two percent (22%) will be discovered in ANWR where it is unknown what the state’s revenue percentage will be.

The state fares slightly better in the future economically recoverable gas potential. State onshore lands between the Colville and the Canning rivers and State Beaufort Sea represents almost twenty-five percent (25%) of all future economically recoverable gas potential on the North Slope. Seventy-five percent (75%) of all future economically recoverable gas potential will be discovered on lands not owned by the state: Twenty-two percent (22%) will be discovered in NPRA where the state will receive a production tax but no royalty; fifty-one percent (51%) will be discovered on federal OCS lands where the state receives no royalty or production tax; and a small percentage of gas may be found in ANWR where it is unknown what the state’s revenue percentage will be.

While the relative prospectivity of each area may be important to understand, the reality of what may be found in each area will be quite different. The NETL has modeled the potential for each area, not what they project will be discovered in each area. Figure 3-55 on page 3-107 of the report illustrates the production forecast for oil if the NETL’s “optimistic assumptions” (their term) are accurate. What the chart shows is current production will remain relatively flat for the next 10 years followed by a substantial increase in production until production peaks in 2042 at 3,000,000 barrels per day. This would mean the current oil pipeline would be at peak capacity and the state would have built a second pipeline to accommodate the additional production. This is based on NETL’s projection of the discovery of 35 to 36 billion barrels of oil. Obviously there is a very low chance of this occurring.

Figure 3-56 on page 3-108 of the report illustrates the production forecast for gas if NETL's "optimistic assumptions" are accurate. These optimistic assumptions of the discovery of 137 tcf of gas would have the state producing 11 bcf of gas per day by 2032 which would require all expansions by compression of the proposed 4.5 bcf per day gas pipline and then looping of that line. This too is a virtual pipe dream.

Many believe that the 137 tcf referred to in the NETL report will be discovered and produced over the next 50 years. In fact, they believe the potential is much greater. The only way to ground that belief in reality is to examine what they must also believe about the oil potential that was referred to in the same report. If they believe the 137 tcf will be produced, then they must also believe the 35-36 billion barrels of oil will be produced and that the existing TAPS pipeline will once again be at full capacity and an additional oil pipeline will be build to transport the surplus oil that has been discovered. The absurdity of such a position becomes apparent once it is understood in context.

Hopefully the above perspective will bring a bit of reality and understanding to the discussion of the oil and gas potential on the North Slope. The state should be an advocate for the oil and gas potential on the North Slope, but it should base its economic and business decisions on a more realistic analysis of North Slope potential. It is one thing to dream about winning the lottery, it is another thing to base your current business decisions on that assumption.

The August 2007 Report is located at http://www.netl.doe.gov/technologies/oil-gas/publications/EPreports/ANSFullReportFinalAugust2007.pdf

The April 2009 Addendum Report is located at http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potential.pdf

If the above reference doesn’t work, the April 2009 Addendum Report can be accessed from the following page. http://www.netl.doe.gov/technologies/oil-gas/AEO/main.html

Security Guards Need Education on Private Rights

2010-10-19T16:12:00.000-07:00

The basic rule for public or quasi-public gatherings is that any member of the public has a right to attend the meeting so long as they conduct themselves in a manner expected of all members of the public in that situation.

For example, in the Miller forum conducted at Central Middle School in Anchorage members of the public were expected to come and listen to Joe Miller speak about his candidacy for Senate. They were also expected to ask questions during and after the event. So long as a newspaper reporter stayed within those boundaries, he could not be considered as trespassing on the event.

If the reporter had tried to take the stage and speak to the audience, he could have been asked to leave. If the reporter had forcibly blocked an entrance preventing people from leaving the building, he could have been asked to move. But attempting to ask a candidate a question the candidate does not wish to answer does not violate any law nor does it give the security guard the right to handcuff the reporter, even if the reporter’s persistence is irritating.

The mere renting of a facility does not give the renter an absolute right to eject a person from the facility as a trespasser just because the person does not agree with or irritates your boss. The security guard misunderstood his rights under the law when he announced to the reporter that the campaign had rented the school, and they had the right to exclude anyone. Rental of the facility gives you certain rights and obligations under the rental contract between you and the owner of the facility. Your obligation to the public that attends the meeting is different from your rights under the rental contract. Your obligation to the public is not dictated by your rental contract and your rental contract cannot withdraw rights from the public that they would otherwise have.

Your rights and obligations to the public are dictated by your invitation. Miller could have sent out invitations to specific individuals to attend his meeting. Only those receiving invitations would be allowed to attend. All others would be trespassers and could be asked to leave. But that is not what happened here.

The campaign through its invitation granted the public the right to attend and participate. The invitation and the methods of announcing the event clearly did not intend to only invite a specific group of individuals. In fact, I assume the more people that attended the event, the happier the campaign would be.

The campaign invited the public to come listen to Joe Miller and ask questions. And to the extent the campaign invited the public to attend, they must treat all members of the public equally, even those that may disagree with the campaign, even reporters.

To do otherwise would illegally tread on individual constitutional rights, rights which I am sure Joe Miller understands.

Equal Time for Parnell

2010-10-17T22:59:00.000-07:00

Some have complained that I only write about Ethan Berkowitz, but actually, I write about what I hear or read in the press. Recently, I finally got a chance to listen to a soundbyte from Governor Parnell thanks to a posting from the Fairbanks Daily News-Miner. If your are interested in watching the soundbyte go to:

http://www.youtube.com/watch?v=wLkf1TJxhH4&feature=player_embedded#!

In the video Governor Parnell defends his position on the Alaska Natural Gas Pipeline and the need to continue to support the $500 million reimbursement to TransCanada and ExxonMobil by citing the benefits of AGIA. The problem is that most of his justifications are either wrong or are of little value.

The method I have used in the article is to quote the governor and then provide my analysis and response, and where appropriate I have also provided the subject law or regulation.

It assures that there are 5 offtakes for gas for Alaska communities. – Governor Parnell

This is his first justification for supporting the $500 million.

Offtakes will occur where they are economic, not based on a demand by the state. As I stated in a previous article regarding the benefits of AGIA, or lack thereof, the only reason the Palin administration demanded 5 offtakes was because the Murkowski administration required 4. Offtakes will occur wherever the demand is sufficient to pay for the facilities necessary at the offtake site to provide access to the gas. Offtakes are about economics, not about meaningless demands. The state could have demanded 10 offtakes sites and the pipeline company would have agreed because the basis for the offtake site was that it would be paid for entirely by the entity taking the gas.

The real answer to the offtake issue is that all compressor stations should be designed to allow for offtake of gas.

My evaluation of this justification. – It’s not wrong, it’s just not important and certainly doesn’t justify giving a pipeline project $500 million.

AGIA must have #12 at AS 43.90.130(12) is reprinted here for your convenience.

(12) commit to provide a minimum of five delivery points of natural gas in this state;

It ensures that tariffs, instate tariffs for gas delivered to Alaska communities are measured by distance sensitive rates, meaning we are only going to pay for mileage for that gas from Prudhoe to Fairbanks for Fairbanks gas. We are not going to pay for mileage from Prudhoe to Chicago and back to Fairbanks which is what the producers could do if Alaska didn’t have that kind of protection. – Governor Parnell

Governor Parnell states that without the protection of AGIA the producers could charge Alaskans a tariff that included the cost of transporting the gas from Prudhoe to Chicago and back to Fairbanks. This simply isn’t true. It wasn’t true when AGIA was passed, and it is not true now. Surprisingly, AGIA even cites the federal law that would prohibit what the governor says could happen. So the Governor must know his statement is untrue and that protecting distance based tariffs is not a reasonable justification for providing TransCanada and ExxonMobil $500 reimbursement for moving the project forward.

My evaluation of this justification. – It’s wrong and doesn’t justify giving a pipeline project $500 million.

AGIA must have #13 at AS 43.90.130(13) is reprinted here for your convenience.

(13) commit to
    (A) offer firm transportation service to delivery points in this state as part of the tariff regardless of whether any shippers bid successfully in a binding open season for firm transportation service to delivery points in this state, and commit to offer distance-sensitive rates to delivery points in this state consistent with 18 C.F.R. 157.34(c)(8); and
    (B) offer distance-sensitive rates to delivery points in the state consistent with 18 C.F.R. 157.34(c)(8);

18 C.F.R. 157.34(c)(8) is reprinted here for your convenience

    (8) Based on the In-State Study and the delivery points within the State of Alaska identified in paragraph (c)(1) of this section, there must be an estimated transportation rate for such deliveries, based on the amount of in-state needs shown in the study. Such estimated transportation rate must be based on the costs to make such in-state deliveries and shall not include costs to make deliveries outside the State of Alaska;

It assures access to that pipeline on favorable rates for future explorers so that the producers don’t control the pipeline but there is possibilities for more abundant cheaper gas from other areas. – Governor Parnell

This is the state’s “rolled-in” rates argument which I have written about previously. The governor’s argument here is accurate. AGIA does require that the pipeline company advocate for “rolled-in” rates, but that does not mean that this position is in the best interest of the state. There is no argument from either pipeline proposal or the shippers that the first expansions by compression will be through “rolled-in” rates. So, as a practical matter, the demand by the state that the pipeline company propose “rolled-in” rates is unnecessary because it is in the pipeline company’s interest and the shippers interest, and the FERC will probably require it. The real debate is over expansions by “looping,” building a second parallel pipe beside the first in order to expand that segment of the pipeline. I have written about this in other articles, but the effect of requiring the pipeline company to propose “rolled-in” rates under these circumstances will probably result in the state arguing for a reduced tariff for the owners of gas found in offshore federal waters where the state receives no royalty or taxes, the reduced tariff to be paid for by existing shippers already shipping gas in the pipeline, including in-state shippers. The result will be an incremental increase in the price of gas in Alaska to be paid for by Alaskans to benefit a gas owner that will pay no royalty or taxes to the state, clearly the wrong position.

My evaluation of this justification. – This argument I would rate as accurate but either not important or slightly detrimental to the state depending on which expansion the governor is referring to. But you certainly wouldn’t pay $500 million for a pipeline company to hold a position that is either not valuable to the state or possibly could hurt the state’s interests in the future.

AGIA must have #7 at AS 43.90.130(7) is reprinted here, in part, for your convenience.

(7) commit that the applicant
    (A) will propose and support the recovery of mainline capacity expansion costs, including fuel costs, from all mainline system users through rolled-in rates as provided in (B) and (C) of this paragraph or through a combination of incremental and rolled-in rates as provided in (D) of this paragraph;

That $500 million dollars is protection for Alaskans in a deal that gets negotiated between multinational corporations. I think that’s a fair price to pay to assure that Alaska interests are protected. – Governor Parnell

I am not sure what the Governor is arguing here, but I think he is arguing that the $500 million is justified to protect Alaska’s AGIA requirements. As I stated above and in a previous article on AGIA, the $500 million was an incentive to encourage a pipeline company to do what no rational pipeline company would do, to move forward to filing for a FERC certificate after a failed open season. The only way to get a pipeline company to do this was to pay for the vast majority of the costs of doing so.

Maintaining the obligation to pay the $500 million may be the right answer, but it is not for the reasons stated by the governor. Justifying the commitment of $500 million to the project should be based on whether it helps move the project forward. Does it encourage the major players BP, ConocoPhillips, TransCanada and ExxonMobil to resolve their differences and move a single project forward or does it continue to provide one of the bases of dissention between the parties? Currently the “20 must-haves” of AGIA are one of the bases of disagreement between the parties. BP and ConocoPhillips do not agree with the requirements of AGIA. TransCanada has agreed by contract to meet the requirements of AGIA, but TransCanada’s partner, ExxonMobil has not agreed to those requirements. Currently AGIA stands in the way of the major parties to the pipeline in resolving their differences. Someday it may be time to abandon the requirements of AGIA, but the state may want to consider maintaining its commitment of $500 million to the project, but only if it can be used as a tool in the negotiations to bring the parties together and move the project forward, not as a burden that stands in their way.

Natural Gas Pipeline Options

2010-10-15T10:04:00.000-07:00

The gubernatorial candidates have been debating alternatives for a natural gas pipeline and which alternative makes more sense. Berkowitz is a staunch supporter of the state building a natural gas pipeline, I assume to Valdez, while Parnell is a supporter of staying the course and supporting AGIA. This article will provide some clarification regarding the passage of AGIA and make some recommendations on the proper path forward, or at least which path not to follow.

First, AGIA was not about the administration getting rolled as Berkowitz says in his ad. Governor Palin, Lt. Governor Parnell at the time, and 59 out of 60 legislators did not get rolled by the pipeline companies, especially Exxon. At the time Exxon was arguing against AGIA. AGIA was about rolling Exxon and the other producers. It was about bribery to get a pipeline company to, as Commissioner Galvin put it, do things they would not otherwise do. The state, through AGIA, made a requirement that the pipeline company, regardless of the results of open season, push the project forward through filing a FERC certificate. As an incentive the state would reimburse the project for up to $500 million. The percent of reimbursement after open season would be 90%. The reason for the 90% was because no rational pipeline company would move forward past open season unless the open season was successful. I assume the AGIA proponents expected the open season to fail; so they made sure the pipeline company had the incentive to move the project forward anyway.

So even though Ethan Berkowitz attempted to rewrite history in his ad and failed, we should still ask if he has a valid point regarding the state building a pipeline to Valdez or other port?

Actually, if his proposal was the right answer, and the all-Alaska option is really a viable economic option, the shippers will have bid at the Trans-Canada open season. Trans-Canada provided all shippers with the option to bid their gas to Valdez. The Trans-Canada option would also have the added benefit of a private company or companies funding and taking the risk on the project.

The only way it makes sense for the state to build the pipeline is if Trans-Canada’s open season failed. Denali’s open season would also have to have failed as well. That means that the shippers of the gas believe the project to Valdez and the project through Canada are both uneconomic. Based on this assumption let's look at the state owned and funded all-Alaska project.

Does Ethan Berkowitz propose the state retrace the same ground the pipeline companies have gone over so far? Does he propose the state appropriate the funds to bring the project to open season? Since the economics of the pipeline project haven’t changed, the pipeline costs the same to build, the owners of the gas are the same, the risks of shipping are the same, wouldn’t Ethan Berkowitz expect the same result to occur at the open season? Only two years from now? Perhaps he proposes the state not hold an open season. Who needs shippers to commit to the pipeline anyway? Maybe the state will just build the $20 to $30 billion pipeline to Valdez. Surely the gas owners will ship their gas on an existing pipeline? And if they don’t, we will sue them and take away their gas. Sounds logical enough ---- except that it is short-sighted and extremely shallow thinking.

If the state does not hold an open season and builds the pipeline without contracts, the shippers will have no contractual obligation to ship the gas. They will only have the reasonably prudent operator standard/obligation under their leases.

A reasonably prudent operator will ship gas when it can make money selling the gas and a reasonably prudent operator will leave the gas in the ground when it is not profitable to ship it.

Lets assume it cost $4 to ship the gas to the point of delivery. It may cost much more if the state is the builder of the pipeline, but lets assume the state was an efficient designer and builder of the pipeline, tankers, and all facilities to get the gas to market. Any time the gas owner can ship the gas for more than $4, they may agree to ship their gas on the state’s pipeline. Any time the price of gas is less than $4, the shippers will leave their gas in the ground and no one will ship gas on Alaska’s pipeline. The state will have taken 100% of the risk of building the pipe and 100% of the shipping risk. Eventually this will backfire on the state because sometime in the future the price of gas will go below the cost of shipping the gas and the state will eat the cost of staffing and owning an empty pipe, not to mention the other facilities required to get the gas to market.

The problem with Ethan Berkowitz’s pipeline proposal is that it sounds good and may get the votes of those who haven’t done their research or seriously considered the ramifications of his idea, but the proposal is not well thought out. He has not considered the viability of his proposal or the risk he is forcing on the state. If you don’t agree with me then help me answer just a few of the questions I have proffered above. How does Ethan Berkowitz propose to fill the pipe? Does he plan to hold an open season? Does he plan to commit the state’s gas to the state’s pipeline? How about the other facilities required to get the gas to market? Who will take the risk of building those facilities without shipping contracts? How does he plan to fund such an expensive pipe? Please don’t tell me through PFD checks. I have already written another article about the viability of that proposal.

To answer the above questions you can’t guess. You must find the answers in the documentation Ethan Berkowitz has created or in a speech he has given. If you cannot find the answers, then Ethan Berkowitz’s proposal is shallow and not well thought out. If you find the answer, please provide them to me. I will be glad to analyze them and let you know if they are viable. Campaign soundbytes can only get you so far. Eventually someone is going to ask for meat on the bones of your proposal. I'll be waiting.

Clarification on the MidAmerican Deal

2010-10-07T20:59:00.000-07:00

A recent article stated that the Berkowitz campaign says that the MidAmerican deal looked like a project that was going forward, until the Murkowski administration changed the terms and it fell apart.

In reality the MidAmerican deal fell apart because MidAmerican demanded it be granted the exclusive right for five years to develop the pipeline without any commitment to move forward with the project. This would have stopped negotiations with all other parties proposing projects under the terms of the Stranded Gas Development Act. The state was not willing to accede to MidAmerican’s demands; so MidAmerican withdrew its proposal.

The information provided in this clarification was obtained from an article written by Gianna Trinca, KTUU-TV, Updated 12:00 a.m. ET March 26, 2004

State Ownership of the Pipeline

2010-09-26T21:39:00.000-07:00

The most important thing the state can do to encourage a pipeline is get its fiscal house in order. The gas shippers are primarily concerned with fiscal certainty and fiscal stability. They want to know what they are required to pay and they want to know that they can depend on that decision for many years to come. They also want the payment, i.e., the tax, to be fair.

There are other secondary issues that, if understood and approached properly, can increase the likelihood of a natural gas pipeline. One of those is state participation in the pipeline. State participation in the gas pipeline can take two forms: one as an owner of the pipe and one as a shipper of royalty gas. Both have potential positive benefits to the state and to the overall success of the pipeline and both carry an increment of risk associated with deciding to participate.

State Ownership of the Pipeline

If the state decides to participate as an owner of the pipeline, it can bring certain valuable benefits to the ownership team. If it participates as an owner, it can advocate its interests in front of regulatory bodies and Congress in ways and with credibility that the oil companies and pipeline companies do not have.

The state as owner could shoulder its proportionate share of the risks involved in the development of the pipeline. But the value here is only achieved if the other pipeline owners know and agree to the ownership interest of the state prior to construction (and preferably sooner). The state does not increase the likelihood of success of the pipeline if it attempts to purchase an interest in the pipeline after the risk has been taken and the pipeline has been completed. The later the state waits in the process to obtain an interest in the pipeline the less value it brings to the table and the less interested the pipeline owners will be in allowing the state a participatory interest in the pipeline.

Of course, the reason the state would bring value to the pipeline by taking an ownership interest in the pipe is because it is taking the same risk through planning and construction of the pipeline as the other owners of the pipe. This is not an insignificant risk and the state should not take the risk lightly. If the state elects to negotiate a participatory interest in the pipeline, it must have a sound financial plan in place that includes how it is going to manage project failure, cost-overruns, and project delays, to name a few issues. The state must approach participation as a business decision with a sound business plan. Otherwise it should stay out of this private sector project.

Public ownership of the pipe brings no financial benefit to the state's analysis of participation in the pipeline. Financially public ownership of the pipe is more of a burden to be managed than a benefit to be encouraged. There are other reasons, primarily political, to offer pipeline ownership to the public, but those reasons do not meet any type of straight faced economic analysis. The small amounts of money the public would bring to the table and the large number of owners required to make any significant contribution would add an administrative burden to the project that far outweighted the financial benefit the public owners would bring to the table. I will discuss the benefits of public ownership later in this article, but it is important to remember that public ownership could be valuable, but that value is not financial. It is not because of the small amount of money they would bring to the table.

If the state were to own a participatory interest in the pipeline, the state would be at the table with the other owners of the pipeline. It would be able to protect the state’s interest in decision-making. Every owner of the pipeline will vote its interest in the pipeline to benefit it individual corporate interest. The state would have a better chance of protecting the interest of the people of the State of Alaska if it was at the table to argue those interests to the other owners. For example, when the state was negotiating a participation agreement in the first pipeline negotiations, the owners were considering an 80/20 debt equity ratio for funding and financing the pipeline instead of the debt equity ratios proposed by either of the current pipeline proposals now moving forward. This could have resulted in a lower tariff for gas and lower overall costs to Alaskans. If the state were an owner of the pipeline, we might have seen better tariff terms proposed by the pipeline.

There is at least an argument that if the state owned a portion of the pipeline, the legislature would be less likely to pass punitive legislation against its own interests. The pipeline company might get a fairer review by the legislature before the legislature passed legislation affecting the pipeline.

State Ownership of the Gas

The state owns its royalty share of the gas, something more than 12.5% of the gas depending on which units participate in bringing their gas to market. The state has a right to allow the owners of the gas to transport and sell the state’s share of the gas or the state can elect to take its share of its gas “in kind” which means the state can elect to take its royalty share of the gas, pay for its transportation, and sell its gas instead of having the gas owners sell the state’s gas for the state.

If the state took its royalty gas in kind, the likelihood of litigation over gas value would be substantially diminished even though there are now regulations in place that substantially reduce the likelihood of litigation regarding gas valuation of the state's gas. If the state were to sell its own gas the issue of the value the state should receive for owner sales of state's gas would go away.

Assuming the two current open seasons fail and a new open season occurs from a consolidated pipeline group, if the state elected to take its gas in kind and bid its gas at the open season, the state would be in the same risk position as the other shippers. And even though the state has argued that the risk on the shippers is not that great, I am sure the state will not elect to take its gas in kind prior to completion of the pipeline. If the state has the right to take its gas in kind prior to construction and bid its gas at the open season or sometime after the completion of construction, it does not make sense for the state to take the construction risks that are placed on the shippers through bidding at the open season and eventually leading to shipping contracts that will allow the project to move forward to construction. The state is much better off allowing the upstream gas owners to take the shipper risk prior to construction and if the state decides it wants to take its gas in kind, wait until sometime in the future after the construction of the pipeline when it knows the tariff costs and knows that the pipeline is a viable project.

ON THE OTHER HAND, if the state really wants to increase the likelihood of a pipeline getting built, it should take its gas in kind, show up at the next open season, shoulder its proportionate share of the risk with the other gas owners and commit to ship its gas on the pipeline.

Form of State Ownership

What would state ownership look like?

First, state ownership of the pipeline is not a right the state has, unless the state wants to be the owner and builder of its own pipeline. If the state wants to participate in the ownership of either of the two existing pipeline projects or in the ownership of a future consolidated group of the two pipelines, then the state must convince the other owners that the state would add value to the success of the pipeline. The other owners must see state participation as more benefit than negative and worth the hassle to allow state participation in the project.

If the pipeline companies allowed the state to participate, the pipeline companies would be looking for certain things in the creation of the state entity that would hold the ownership interest of the state in the pipeline.

The pipeline companies have certain requirements for providing information to the public and the state and federal regulatory agencies. All other information is private and kept confidential. This isn’t because they are doing something bad or illegal, it is just the way they do business from a competitive standpoint. They do not like to reveal to the public, the regulatory bodies, or their competitors anything they are not required to reveal. The state entity would have to abide by the same corporate policies regarding what is public and what is kept private. The state entity would have to be insulated from influence from the governor, the legislature, or other political or public groups. The state entity employees would be bound by the same confidentiality obligations as the employees of the other owner pipeline companies. A corporation would be the likely form the state entity would take.

The other pipeline owners would have to be assured that the state would pay its proportionate share of all costs and take all the same risks as the other corporate owners of the pipeline. The owners would have to be assured that the legislature could not hold the pipeline hostage through the appropriation process.

The other pipeline owners would have to be assured that the state would not vote against its own financial interests by attempting to influence the pipeline, through the state’s vote, to take a position that may be in the interest of some in the state, political or otherwise, but is not in the state’s economic interests regarding a successful pipeline.

In essence, the other pipeline owners would be looking for the state to create an entity that looks and acts like a private corporation without influence from the public, the governor or the legislature. And the other pipeline owners would have to be assured that the legislature would not change the state entity at some future date. The other pipeline owners might require the state entity to grant the other owners the right to purchase the state’s interest in the pipeline if the legislature attempted to change the entity. The purchase may even need to be with some penalty to the state it make sure some future legislature does not attempt to meddle in the state entity’s business in the future.

If the state is not willing to agree to the above criteria, I recommend the state not consider state participation in the pipeline because the pipeline owners will probably not consider granting the state the opportunity to own an interest in the pipeline.

Public Ownership of the Pipeline

Public ownership of the pipeline can only come through ownership in the state entity created for that purpose.

If set up properly, the state could offer ownership shares of the pipeline to the people of Alaska. This would help the people of Alaska feel like they had a stake in the pipeline. It would also add additional protection against adverse legislative action against the pipeline. If there were a substantial number of Alaskans or a number of influential Alaskans that had an ownership share of the pipeline, the legislature would more thoroughly consider any legislation potentially adverse to the interests of the pipeline company.

The other owners of the pipeline would probably not see public ownership of the pipeline as a negative so long as the public was limited to buying non-voting, non-participatory shares and public ownership did not place any additional burdens or obligations on the other owners of the pipeline. The public owners could also not have any additional rights to influence the decisions of the corporation or be given access to information that was not already available to other members of the public. Anything different from this and the other owners of the pipeline would probably not consider allowing the state to participate in the ownership of the pipeline with them.

Conclusion

The above is just a shapshot analysis of some of the issues that must be addressed if state ownership of a pipeline is considered. state ownership, in and of itself, will not increase the likelihood of a pipeline. In fact there are other issues that are more important to the success of a natural gas pipeline that need to be addressed by the legislature. But if state ownership is considered, the form that ownership should take is one that looks more like a private corporation than a public entity if the state wants it to be effective in increasing the likelihood of success of the pipeline.

Political Posturing

2010-09-23T10:30:00.000-07:00

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.

Berkowitz Revenue Proposal Analysis

2010-09-21T21:52:00.000-07:00

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.

Berkowitz Oil Revenue Proposal

2010-09-16T20:01:00.000-07:00

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.

Analysis of the Twenty "Must Haves" of AGIA

2010-09-15T22:29:00.000-07:00

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.

Alaska Gasline Inducement Act (AGIA)

2010-09-11T16:21:00.000-07:00

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.

Own a Piece of the Pipe - Part 2

2010-09-09T19:31:00.000-07:00

A Greater Likelihood of Success

In my first article Own a Piece of the Pipe - Part 1, I evaluated the use of the Permanent Fund Dividend check-off as a vehicle to fund state ownership of the pipeline. In this article I will evaluate the argument that state ownership enhances the likelihood of success of a gas pipeline; I will evaluate the justification for that position; and I will propose some principles that should be considered when developing a plan or strategy for State participation in a gas pipeline.

"If we take advantage of this opportunity, we have a greater likelihood of seeing a pipe come true."- Ethan Berkowitz.

In the Frequently Asked Questions (FAQ) portion of his website Ethan Berkowitz, as support for his position that state participation increases the chance for success of the pipeline, refers to the Alaska Natural Gas Development Authority report in FAQ Q.1, the Alaska Natural Gas Development Corporation report in FAQ Q.13, and the Alaska Gasline Development Corporation report in FAQ Q.16. The report I assume he is referring to is the Alaska Gasline Development Corporation Project Progress Report titled “Alaska Stand Alone Gas Pipeline Project Update and FY 2010 Deliverables.” Page 28 of that report states that “All cost of service models run indicate the predicted cost to consumer will be higher than the current costs in the Cook Inlet.”

Dan Fauske, the CEO of the Alaska Housing Finance Corporation, in his presentation of the report update to a group of legislators, recognized the challenged economics of the gasline when he stated "There will need to be some type of equity infusion or some type of subsidy.”

I assume this was the basis of Ethan Berkowitz's position that equity invested in the pipeline through the PFD dividend checkoff will at least partially address the need for equity infusion and create "a greater chance making a pipeline become real."

There are two problems with this position. First, the equity infusion or some type of subsidy Dan Fauske was referring to needs to be of the type of infusion that would ultimately reduce the tariff. Mere ownership does not reduce the tariff. A State capital contribution reduces the tariff, and I am sure Ethan’s PFD owners are not interested in donating their dividends to the pipeline company.

And second, and most important, the report Ethan Berkowitz is using to support his position has nothing to do with a large diameter pipeline. It was drafted as an update on the in-state gasline! The Alaska Gasline Development Corporation was created “for the purpose of planning, constructing, and financing in-state natural gasline projects or for the purpose of aiding in the planning, construction, and financing of in-state natural gasline projects.” The Alaska Gasline Development Corporation and any reports it creates has nothing to do with a large diameter pipeline.

The economics of an in-state gasline and the large diameter gasline are entirely different. And the justification for state participation in a large diameter pipeline are entirely different that the justification for participation in an in-state gasline.

Major concerns of the large diameter pipeline are pipeline costs, cost overruns, tax stability, and the long-term price of gas in the lower-48. The major hurdle for an in-state line is economics of size. The in-state need for gas doesn't justify the cost of building a gasline from the north slope to southcentral Alaska.

This means that the primary justifications Ethan Berkowitz is using to support state participation in the pipeline has nothing to do with the large diameter pipeline he is proposing to own. But it is possible for state participation to enhance the likelihood of success of the pipeline, just not for the justification proposed by Ethan Berkowitz.

Participation in a Large Diameter Gasline

In order to draft a successful plan for state participation in a large diameter gasline, it is important to understand the view of state participation from a pipeline company standpoint.

The following are some principles that should be considered and followed if possible:

1) First, it must be remembered that the State does not have an automatic right to have an ownership share of the pipeline. It will only be invited to participate as an owner if it brings value or adds value to the pipeline entity.

2) A state entity would need to act like a corporation, not a regulator.

3) A state entity would need to keep information confidential that is normally kept confidential by a private corporation participating in the pipeline.

4) The State’s shareholders cannot have access to confidential information. Only information made available to the public in general will be provided to them. The State entity’s board of directors and staff will have access to confidential information, but only if they agree to keep the information confidential.

5) The State’s ownership interest cannot fluctuate throughout the time the pipeline is being built. Voting rights are based on ownership interest and cannot be changed just because more individuals want to invest their permanent fund dividends in the ownership of the state entity.

6) If there are cost overruns and all the other owners are required to pay their proportionate part of the overrun, the State will pay its proportionate share also.

7) The rights and responsibilities of the State entity that is participating in the pipeline cannot be subject to legislative changes that would violate their obligation under the participation contract they sign, commonly an LLC agreement.

8) Some pipeline companies would like to see the state own the same share of the pipeline as its royalty share of the gas. Other pipeline companies are not as concerned with this issue.

If a participation proposal is fashioned that meets the above criteria, it will have a greater chance of getting agreement from a pipeline company to allow the State an ownership position in the pipeline than if the criteria are ignored.

Own a Piece of the Pipe - Part 1

2010-09-08T20:49:00.000-07:00

A Straight-forward Idea or a Complex Evaluation

At first blush, Ethan Berkowitz’s Owning a Piece of the Pipe idea seems fairly simple. In fact he stated, "To us and most Alaskans this is a pretty straight forward idea, the notion that Alaskans should also have the right, if they individually choose, to be able to own a piece of the pipe."

The idea may sound simple, but the implementation is decidedly more complex.

For example, Ethan Berkowitz has selected the Permanent Fund Dividend check-off as the appropriate vehicle to raise funds for participation in the pipeline project. But no analysis is provided regarding the impact on Alaska businesses if the program is as successful as he hopes.

A successful PFD check-off program will divert money from the Alaska economy and Alaska small businesses to a pipeline project that may or may not need the assistance of Alaska financial support to be viable.

"If we have about 20 percent of Alaskans participate in this proposal, which is what our projections would be, we'll see the cumulative effect of about $800 million in investment."

Ethan Berkowitz projects about 20 percent of Alaskans will participate in the opportunity to invest in the pipeline resulting in the cumulative effect of about $800 million in investment and perhaps close to $1 billion.

What will the impact be of diverting as much as $800 million to $1 billion away from the Alaska economy and into supporting a gas pipeline project? Many small Alaska businesses, in order to balance their budgets each year, depend on people spending their Alaska PFD’s and purchasing goods and services in Alaska. I think that Alaska small businesses would be very concerned about the impact on the viability of their businesses of such a large diversion of permanent fund dividends to the pipeline project.

An analysis should be done of the impacts of such a substantial loss of revenue to Alaska businesses prior to proceeding ahead with such a proposal.

Who will invest?

Diane Benson, the lieutenant governor candidate, says she would have been excited to have an opportunity like this when she was a young mother of limited means. Her statement suggests that she believes all Alaskans, regardless of their financial status, would seriously consider investing their PFD’s in the pipeline. Actually, reality is far different than the picture she projects. A young mother of limited means is barely able to balance her budget. The last thing she is going to consider is taking her PFD, investing it in a pipeline project, paying the taxes on the PFD income, and hoping some day that her investment will return a profit to her. She, and many others like her, will be using their dividends to catch up on paying bills, and possibly, they hope, have a little left over to do or spend on something special with the surplus.

The typical person that will be able to invest their PFD in the pipeline is a middle to upper income individual that does not need the PFD to pay for the basic necessities of life, a person that has sufficient surplus income that they can afford to lose it if the pipeline project fails to reap a profit.

So even though this program is touted as benefiting all Alaskans, as a practical matter, a much smaller cross-section of Alaskans will be able to avail themselves of the opportunity to participate. And if they participate, there has been no research, and apparently the question hasn’t even been asked, about the impact on the Alaska economy of these individuals diverting their PFD’s to the gas pipeline instead of investing them in their local community.

Ethan Berkowitz may want to reconsider using the Permanent Fund Dividend check-off as the vehicle for providing Alaskans with an opportunity to participate in the pipeline.

He may find that the negative impacts from the loss of revenue to the economy will exceed the benefit received by the pipeline. He might still want to consider some form of state ownership or participation in the pipeline and perhaps allow the public the opportunity to participate in the project through participating in the financing of the project. Perhaps the public could be provided the opportunity to purchase bonds in the project instead of acquiring an ownership interest. This would be a much safer, less risky venture for the Alaska public.

If Ethan Berkowitz continues to propose this idea, the next stage of his multi-part plan should begin to address this issue.

Energy Issues in the Alaska Gubernatorial Race

2010-09-06T22:02:00.000-07:00

Over the next several weeks I will add articles to this blog discussing the various oil and gas and gas pipeline issues being proposed by the Alaska gubernatorial candidates. So far, topics included in those articles will be Owning a Piece of the Pipe, AGIA, and Changing the State’s Oil and Gas Royalty and Tax Structure. As the candidates publish additional positions on various issues I will try to include analysis of those positions in future articles.

Alaska Gasline Port Authority Proposal to Purchase Fairbanks Natural Gas LLC

2010-07-30T00:29:00.000-07:00

The purchase of FNG by AGPA

The Fairbanks North Star Borough (FNSB) is currently considering authorizing the Alaska Gasline Port Authority (AGPA) to purchase Fairbanks Natural Gas LLC (FNG) as part of its proposal to truck natural gas from the Alaska North Slope to Fairbanks. In order to understand if that is a reasonable decision the FNSB needs to determine why AGPA is asking to purchase FNG. What is the goal they are trying to achieve, and what process should be followed to make that decision?

What is the goal the FNSB is trying to achieve or the value it is trying to protect?

The cost of energy has always been high in the Interior of Alaska. It is an important goal for the FNSB to ensure that future energy needs are met and that those needs are met in the most economic, cost-effective manner possible. The AGPA has proposed the purchase of Fairbanks Natural Gas LLC and the trucking of natural gas from the Alaska North Slope to Fairbanks as the method to achieve that goal. Before a decision on that issue can be made, several questions need to be answered in order to provide the context and justification for the decision, and a reasonable decision-making process needs to be followed to ensure a thorough analysis occurs. The decision should only be made to move forward with the purchase of FNG if the FNSB understands the economics and chance of success of the proposal and of the other alternatives available to the FNSB to meet its goal of long-term, low-cost energy.

What alternatives are available to meet future energy needs of the FNSB?

The AGPA has proposed the trucking of natural gas from the North Slope to Fairbanks as the most economic way to accomplish the goal of low-cost energy for the FNSB. Their proposal includes the purchase Fairbanks Natural Gas LLC (FNG) as a requirement to make that proposal a success. The assumption that trucking natural gas from the North Slope and the assumption that this necessarily means the purchase of FNG as a requirement to meet their goal must be tested against an analysis of the other viable alternatives available to meet the energy needs of the FNSB. This should be achieved through a reasonable agreed upon decision-making process. The following is a proposed process that could meet the need for a thorough analysis prior to making a decision of such magnitude.

What process should be followed before proceeding ahead with the FNG purchase?

First, compare trucking North Slope gas to all the other viable alternatives. Understand the proposed decision in context. For example, the cost of this alternative is substantially greater and the benefit (reduced energy cost) is substantially less than the benefit to the FNSB if a large diameter gas line is built. If a large diameter gas pipeline is built, the cost of energy from that pipeline will be substantially less than trucking natural gas from the North Slope to Fairbanks. But from a control and chance of success standpoint, trucking gas from the North Slope has a much greater chance of success than depending on TransCanada and the North Slope producers to build a large diameter gas pipeline.

The FNSB must also understand that if the utilities sign long-term contracts with FNG, the utilities will not need gas from the large diameter gas pipeline nor will the FNSB be able to benefit from a reduced cost of energy standpoint from a large diameter gas pipeline if it is successful. That doesn’t mean that the FNSB won’t receive any benefit from a successful large diameter gas pipeline, just that the FNSB will not be able to benefit from the reduced cost of energy that a large diameter gas pipeline would bring; the FNSB and the entire state will definitely benefit from a large diameter gasline from a jobs and taxes standpoint.

The economics of importing gas into Cook Inlet and building a gas pipeline from Cook Inlet to Fairbanks or trucking gas from Cook Inlet to Fairbanks should also be understood in comparison to the alternative AGPA is proposing.

Some have proposed building a small diameter gas pipeline from the North Slope as their preferred option. Will that project deliver gas to Fairbanks cheaper than trucking gas from the North Slope? What are the chances of that project moving forward to successful completion?

Other viable energy alternative should also be considered. Basic economics and the chance of success of each option should be the basis for any decision to move forward with an alternative.

In addition, a cost-benefit analysis of the proposed trucking option should be conducted. Assuming what GVEA says about cost savings is true and that electric bills will be reduced by about 6 percent and that 1,100 natural gas customers would save an estimated 30 percent on their electric bills, how much will be saved by the residents of the FNSB. Compare what would be saved each year over the term of the contracts to the cost of participating in the project. If the cost of the project outweighs the benefits of the project, it shouldn’t move forward with FNSB support even if it is the most viable alternative among those considered. This would be the no action alternative because none of the alternatives considered are worth supporting.

If trucking gas from the North Slope is determined to be the most economic viable alternative, what next?

If trucking gas from the North Slope is determined to be the most economic viable alternative, then the FNSB’s next decision is to what extent should the FNSB participate in the project in order to assure the project’s success.

A sovereign’s responsibility, as it relates to economic development, is normally to create a commercial environment where business can excel and grow while protecting the interests of the people. Only when a project is deemed to be essential for the benefit of the people and the business community is not willing to move forward with a project should the sovereign venture into participation in the economic arena and then only to the extent necessary assure the success of the project.

Once it is determined that participation by the sovereign in a project is essential to move a project forward, the next determination to be made is to what extent should the sovereign participate in the project. The sovereign should only participate in a project to the level necessary to accomplish the goal of moving the project forward. That participation could exhibit itself in the form of financing or ownership of any part of the project required to make the project a success.

If commercial entities had determined that the project was economic, they would have pursued the project and the AGPA wouldn’t have been given the option to participate. The FNSB, through participation of the AGPA will be required to participate by financing or ownership of the riskiest portions of the project because no commercial entity can be found to risk their capital on those portions of the project. No commercial entity can be found to take the investment risk necessary to participate in those portions of the project.

It is possible that no commercial entity can be found to participate in any portion of the project or that only a fully integrated ownership of the project makes the project viable for participation by the FNSB through AGPA. In that case there is one remaining step in the process to complete.

Valuation and purchase of the FNG asset.

If it is determined that trucking natural gas from the North Slope provides Fairbanks with the most viable low-cost energy alternative, and that no commercial entity wishes to participate in any portion of the project, or that an integrated operation is required to make the project viable, then purchase of FNG becomes a critical element in moving the project forward.

The last step is to properly value the FNG assets before a purchase offer is made or a purchase price is agreed upon. Project value should not be based on the value it ultimately brings to the FNSB, i.e., the value of the benefit to the people of Fairbanks over time. That could be tens of millions of dollars. The value should be based on what a commercial entity would pay for FNG in an arm’s length economic transaction. Based on this type of analysis a reasonable purchase price for FNG can be negotiated.

Summary

First, any action the FNSB takes in support of any proposal to bring natural gas to Fairbanks should be made in the context of how it accomplishes the goal of providing long-term, low-cost energy to Interior Alaska. At every stage of the process, what is being proposed and evaluated should be evaluated in the context of how it increases the likelihood of accomplishing the goal of long-term low-cost energy for Fairbanks. Don’t lose sight of the goal.

Next, if the above analysis is followed, and after careful and thorough economic and public policy considerations, the trucking option is chosen as a viable option to pursue, and ownership of the entire integrated operation is required, and a reasonable economic/commercial price is negotiated, then it may be reasonable to proceed ahead with this venture. But, to move forward with a project without a thorough analysis through a well-defined process is shortsighted and could lead to poor decision-making and increased risk of failure of the project. The FNSB needs to complete a thorough review of the proposal through a well thought-out process before it gives the green light for AGPA to purchase FNG.

BP Gulf Oil Spill Response Plan Review

2010-06-14T10:46:00.000-07:00

The gulf oil spill is now headed into its eighth week. Many have commented on the inaccuracies and weaknesses of the BP Oil Spill Response Plan, but few have analyzed it for what needs to be done to ensure the same results do not happen again. The plan is inadequate as it exists. BP’s Plan and all other plans like it need to be changed, and the state and federal agencies need to take this opportunity to collect additional information on performance of spill personnel and equipment to assist in the analysis of what is necessary to make future plans more effective.

The BP Oil Spill Response Plan is primarily an outline of the Incident Command structure, the responsibilities of the different members of the Incident Command Team, a listing of State and Federal Agencies that may need to be contacted in the event of a spill, incident forms, flow charts, decision diagrams, response organizations and equipment lists. It sounds like and is more of a resource manual that a response plan. It provides little assistance to the Incident Commander in determining what to expect for response times and effectiveness for deployed equipment or reaction of the oil to the environment.

The models upon which the spill plan is based were so inaccurate that they provided the Incident Commander with little or no understanding of when and where to expect the oil. They were woefully inadequate in assisting the Incident Commander in understanding the volume of the spill, the trajectory of where to look for the spill or the speed of the spill through the environment.

The models should be redesigned to provide more accurate projections now that there is actual data to compare. If the models are inconsistent with what happened, the models are wrong and they need to be changed to reflect reality. Even if the models are changed, they will still be wrong the next time, but they may not so grossly underestimate the speed and trajectory of the oil as to be useless to the Incident Command Team.

Only three pages of the 582 page spill plan are dedicated to a written analysis of the worst case scenario and much of that is merely an explanation of the scenario and a listing of the different response methods and their capacities to recover oil. An Incident Commander would find no assistance in this section of the plan on how to respond to the spill or what to expect from a spill of this magnitude.

There is little anywhere in the spill plan in the way of analysis to assist the Incident Commander in understanding what to expect from the response options he is provided. Equipment lists have nameplate capacities but no analysis of their effectiveness in the environment. Skimmers with nameplate capacities totaling 491,721 barrels per day are identified in the plan and give a false sense that they should be able to easily capture a spill of 250,000 barrels and remove it from the environment. But oil does not collect in one place waiting to be picked up, and nameplate capacities are not the same as effective rates.

Spill plan worst case scenarios should have estimations of how much oil is expected to escape into the environment; estimations of daily rates and how long will it take to contain and stop the spill from continuing; estimations of how much is being dispersed into the water column and how much is suspended in plumes in the water column. Of the oil collecting on the surface, the Incident Commander should have an understanding of how much will probably aggregate in sufficient quantities to be retrieved by mechanical skimmers and what percentage can be attacked with dispersants or burned? The Incident Commander should understand what percentage is escaping, the quantity of oil, the quality of the oil and when and where to expect the oil onshore.

BP needs to collect information regarding effective rates for deployment of its spill response equipment. For each piece of equipment deployed the following information should be collected:
1) the time required for equipment to be deployed onsite should be recorded, from the time it was requested to the time it was deployed onsite;
2) data should be collected regarding standby time for each piece of equipment, transportation time to get equipment to a new location for deployment, and time deployed in response to the spill;
3) during the time deployed the volume of liquid retrieved should be recorded, and data regarding the oil/water ratio should also be captured.

If this information is captured and analyzed it would provide the data necessary to calculate an effective response rate for each piece of equipment deployed. Effective response rates provide the Incident Commander with a more accurate tool than nameplate capacities in planning a response to a major oil spill.

Once the information has been collected from the spill it should be analyzed with the response team, state and federal agencies, and other stakeholders to determine the requirements for future offshore exploration and operations spill plans.

In addition, a plan that is only required to be updated once every two years is going to have a certain number of errors. I recommend annual updates and a certification by the person signing the plan as to the accuracy of the plan. That would require someone in the organization to attempt to verify all the numbers in the plan at least once a year.

Half of BP’s Incident Command Organization Chart did not have individuals identified to fill the incident command positions. I recommend that all leadership positions in the Incident Command structure should be identified in the organization chart and those individuals should be required to participate in a response drill at least annually.

If the above recommendations are followed, they won’t prevent incidents from occurring, but incident responders will have more effective tools to assist them in their response and they will be more prepared to respond to the incident.

Steve Porter is a former exploration permitting manager for a major oil company and was responsible for the preparation and approval of offshore oil spill response plans.

Evaluation of Exploration in the Arctic OCS

2010-05-27T23:04:00.000-07:00

The BP oil spill in the Gulf of Mexico has affected and will continue to affect the environment and the lives of many in the southern coastal states for years to come. For Alaskans the spill brought back memories of Exxon Valdez oil spill in 1989 and the impact it had on their lives.

Today the BP oil spill has resulted in a more direct impact on Alaska and the future of oil and gas exploration in the State. Today President Obama announced the suspension of Shell’s offshore arctic exploration operation plans. There is substantial uncertainty regarding when and if the Administration will allow exploration in the Arctic OCS to continue.

The purpose of this article is to outline the issues that the Administration needs to address before they decide to allow or disallow exploration in the offshore Arctic.

In the weeks following the Exxon Valdez oil spill, as the exploration permitting director for a major oil company, I submitted my first offshore oil spill contingency plan. The issues we were required to address then are the same issues that should be addressed now as the Obama administration evaluates whether or not to make the suspension of offshore exploration drilling long term or permanent.

There are four areas that should be examined during the review: 1) formation pressures and risk, 2) safety and prevention, 3) spill plan preparedness, and 4) effectiveness of equipment and personnel.

First, formation pressures and the potential risk of blowout

The risk of encountering high pressure pockets of gas or oil should be understood and planned for in the drilling and well casing program. Several wells in the Arctic have lost well control due to encountering high pressure gas pockets that were not managed properly in the drilling program. Luckily none involved loss of well control in an oil producing zone. Even though there have been several loss of well control events, statistically the industry has done a good job understanding and preparing for this type of event.

Second, safety and prevention

In the event of the loss of well control, the operator should be able to utilize the safety mechanisms in place on the rig to stop the flow of oil or gas to the surface. The most well know mechanism, especially after the BP blowout, is the blowout preventer. Functioning properly, it should be able to seal off the well and allow the operator to develop a plan to regain control of the well without release of hydrocarbons into the environment. These safety mechanisms are tested regularly and almost always work. But there are now at least two well known events where they didn’t work: the IXTOC in Mexican waters, and now the BP blowout in the Gulf of Mexico OCS.

Third, spill plan preparedness

Shell has committed a substantial amount of equipment to meet the Alaska Department of Environmental Conservation’s Response Planning Standard and to meet the Minerals Management Service requirements. On paper Shell could handle a well blowout that discharged up to 5,500 barrels of oil into the environment for up to 34 days which is the number of days Shell projects it will take to drill a relief well and stop the blowout. On paper it looks like Shell has met the spill plan preparedness standard.

Fourth, effectiveness of equipment and personnel

The Oil Discharge Prevention and Contingency Plan (ODPCP) contains lists of equipment and nameplate capacities but very little analysis in the way of the effectiveness of that equipment in the environment the equipment will probably encounter.

Generally industry spill plans and presentations regarding preparedness make it look like they are prepared and could clean up oil in any environment they encountered in their operations. Pictures of spill response vessels and spill equipment in the Arctic environment give the audience the feeling that the equipment pictured will be onsite and ready to perform the function to the effectiveness that is listed on its nameplate.

The problem is that nameplate capabilities don’t work in the Arctic. Skimmers that performed poorly in the Gulf of Mexico will perform even worse in the Arctic, even if they are “winterized” for Arctic conditions. Sea ice conditions in the Arctic may prevent spill response vessels and equipment from getting close enough to the oil to deploy the equipment. Oil may be entrained in the ice and under the ice where spill response equipment will not be effective. Oil may not collect in sufficient quantities or may be weathered to such an extent that in situ burning is not an available option.

There is documentation of the amount of equipment available to respond to a spill and the potential response times, but there is little analysis of the effectiveness of that equipment in various arctic conditions. The State of Alaska and the MMS need to understand how much oil can be expected to be picked up under different scenarios and what the impact is on the environment from the remaining oil that is not recaptured.

How effective is the use of dispersants in broken ice conditions? What is the impact on wildlife in the water column and on the ice? Some of the dispersant will get on the ice. What if it is injested by wildlife? What would seem unusual for people is not always unusual or uncommon for animals. There is at least one incident on the north slope where a polar bear injested industrial liquids resulting in the death of the polar bear.

Exploration drilling activities are planned to begin on or about July 4th and drilling in hydrocarbon bearing zones would end on or before October 31st, depending on ice and weather. What if a blowout occurred late in the drilling season, or what if sea ice prevented the drillship from getting back on location? There may not be sufficient time to drill a relief well during that drilling season and the drillship may have to return the next summer drilling season to complete the relief well. If the existing drillship burns up in the ensuing fire, the relief rig will not be available to drill a relief well until the next drilling season. What is the impact on the environment from an uncontrolled well blowout that continues to release oil in the environment for 6 months or longer?

Shell’s exploration plan states that “A very large spill from a well-control incident is not a reasonably foreseeable event in connection with the OCS exploration activities set forth in Shell’s EP, and therefore, this EA does not analyze the impacts of such a worst-case scenario.” Lets hope they are right.

You don’t plan for meteors hitting the earth, but you do plan for earthquakes. The likelihood of a catastrophic oil spill in the arctic is somewhere in between the two.

If the state and federal government approve Shell moving forward in the Alaska OCS, they need to understand that a major oil spill from a blowout will not be easier to stop or clean up in the arctic than it was in the Gulf of Mexico. It will be more difficult. The best we can hope for is good management practices and the statistical likelihood that the incident will not occur.

The Red Pen Challenge Update

2010-05-03T11:19:00.000-07:00

This morning I called and left messages regarding the Red Pen Challenge at the following gubernatorial campaigns:

Ethan Berkowitz
Hollis French
Sam Little
Sean Parnell
Bob Poe
Ralph Samuels
Bill Walker
Donald Wright

If you know of a candidate for governor that is not on this list that would like to be included in the challenge, please ask them to contact me, or if you are one of the above candidates and somehow did not receive my message, please contact me as well. For the sake of convenience I have reprinted the Red Pen Challenge below.

I call this proposal The Red Pen Challenge.

I propose that every candidate for governor should review the capital budget and identify those items they would veto and submit them to the people of Alaska at the same time the Governor submits his signed capital budget bill, with appropriate vetoes if any, to the people of Alaska.

Rules of the Challenge

1) The governor agrees, in advance, to the date and time he will make public his decision on the capital budget.

2) Each candidate will submit their proposed capital budget to the public on the same date prior to the governor’s submittal to the public.

3) Governors Rules apply. – Each candidate will be required to provide the public with a copy of the budget with the specific “vetoed” items lined out and initialed, just like the Governor is required to do.

4) All newspapers will be encouraged to post on their web pages all responses so the Alaska public can compare the “decisions” of each of the participating candidates and add this information to their overall evaluation of who they want to support for governor.

I believe the above proposal will provide the appropriate scrutiny that was not applied during the legislative process to each and every appropriation in the capital budget.

Since the capital budget has not been transmitted to the governor there is still plenty of time for each of the candidates to comply with the above challenge. They will have the same amount of time to review and analyze the capital budget as the governor has.

I am also certain that if a candidate needs more information about the value of a specific appropriation, the recipient of that appropriation will be glad to provide the candidate with as much information as the candidate needs to make their decision.

I will be contacting each candidate and the governor over the next week to see who will be willing to rise to the challenge. The governor is the only candidate that will automatically participate because he is required by law to make a decision on the capital budget. The governor still needs to agree to a specific date and time when he will communicate his decision on the capital budget to the public.

I am looking forward to sharing their responses to the challenge in a future article.

A System Failure and An Idea

2010-04-28T17:45:00.000-07:00

On the last day of the legislative session the Alaska Legislature passed House CS for CS for Senate Bill No. 230(FIN) am H also known as the capital budget. Its largess rivaled any other capital budget in the history of the State of Alaska. Some said they were being good stewards. Others likened the passage of the bill to irresponsible spending. What is clear is that in Alaska where the Permanent Fund Dividend is sacred and a proposal to tax the people to pay for public services might be cause for a revolt, members of the legislature are not rewarded for exercising fiscal restraint, especially in an election year. Did the system fail or did it produce the results it was designed to produce?

In years where there are not enough funds to balance the budget, legislators are rewarded (by reelection) for cutting the budget and minimizing the pain to their constituents. This usually means cutting special programs with limited constituents and cutting or miminizing the increase in administrative budgets.

In years of plenty politicians get elected for obtaining funds for their communities. If there are no short-term negative consequences, there is generally no opposition to spending, even excessive spending, so long as the legislator’s constituents receive a portion of the benefit of that excess.

In the legislature’s defense, they did pay back the remaining funds that had previously been borrowed from the Constitutional Budget Reserve, and they did forward fund education. So what is the problem with spending a little extra when you have it?

Perhaps that question should be asked of the Alaskans who may be most impacted by excessive spending. Perhaps we should ask the Alaskans who are not at the table and who cannot defend themselves against the poor decisions of this generation. Perhaps we should ask the Alaskans who will bear the costs of such a decision. The costs will be borne by those who are not at the table: the future generations of Alaskans. The financial impacts of excessive spending in the short term and the failure to spend in the context of a long term plan are not borne by the present generation. They are borne by future generations when the poor decisions of this generation finally come to roost. The decision makers of future generations will be blamed for the failure, for the failure to plan, for the failure not to forsee the collapse. But it is the current generation of legislators that should be held accountable.

Luckily there is a balance of power in the Alaska political process. The governor has a right to veto those appropriations he feels are inappropriate or excessive. The governor, unlike the legislature, is not accountable to a small group of constituents from a specific district. The governor can provide the leadership necessary to protect both the present and future generations. The governor can examine each appropriation with an eye to the benefit it will provide to the people of Alaska. The governor can examine each appropriation with an eye to the increased maintenance burden placed on this and future generations. The governor can examine each appropriation with an eye to understanding that perhaps saving in years of plenty is a logical choice to meet the needs of those years when there will be budget shortfalls. Perhaps the governor can provide the balance and leadership that was not available during the legislative process.

But this is an election year. Will election year politics affect the governor’s decisions? Will the governor calculate the number of votes lost by every line item veto? Will the other gubernatorial candidates cherry-pick the line item vetoes they think were wrong in an effort to gain advantage over the governor in the election? Will good decision making by the governor be sidelined in an effort to get reelected?

In light of the pressures of election year politics on good decision making, I have a proposal to make that should balance the field between the candidates and should provide a snapshot of how each gubernatorial candidate would lead the State over the next four years.

I call this proposal The Red Pen Challenge.

I propose that every candidate for governor should review the capital budget and identify those items they would veto and submit them to the people of Alaska at the same time the Governor submits his signed capital budget bill, with appropriate vetoes if any, to the people of Alaska.

Rules of the Challenge

1) The governor agrees, in advance, to the date and time he will make public his decision on the capital budget.

2) Each candidate will submit their proposed capital budget to the public on the same date prior to the governor’s submittal to the public.

3) Governors Rules apply. – Each candidate will be required to provide the public with a copy of the budget with the specific “vetoed” items lined out and initialed, just like the Governor is required to do.

4) All newspapers will be encouraged to post on their web pages all responses so the Alaska public can compare the “decisions” of each of the participating candidates and add this information to their overall evaluation of who they want to support for governor.

I believe the above proposal will provide the appropriate scrutiny that was not applied during the legislative process to each and every appropriation in the capital budget.

Since the capital budget has not been transmitted to the governor there is still plenty of time for each of the candidates to comply with the above challenge. They will have the same amount of time to review and analyze the capital budget as the governor has.

I am also certain that if a candidate needs more information about the value of a specific appropriation, the recipient of that appropriation will be glad to provide the candidate with as much information as the candidate needs to make their decision.

I will be contacting each candidate and the governor over the next week to see who will be willing to rise to the challenge. The governor is the only candidate that will automatically participate because he is required by law to make a decision on the capital budget. The governor still needs to agree to a specific date and time when he will communicate his decision on the capital budget to the public.

I am looking forward to sharing their responses to the challenge in a future article.

The Point Thomson Unit - The Next Step in the Process.

2010-04-05T19:15:00.000-07:00

In September 2005 the Director of the Division of Oil and Gas, Department of Natural Resources disapproved the Point Thomson Unit (PTU) owners’ 22nd Plan of Development (POD) because “it did not set out a plan to bring the PTU into commercial production within a reasonable time frame.”

The Director believed that the pace of prospecting and development for the PTU should be more aggressive than what the PTU owners proposed; so he rejected the POD. Ultimately the Superior Court upheld his decision rejecting the 22nd POD.

After several years of appeals, and after the current appeal to the Alaska Supreme Court, the next step in the process will be for the Director to explain what he considers necessary to diligently develop the PTU. As a part of that explanation the Director can state that if his determination is not accepted by the PTU owners, the unit will be terminated. This explanation would normally take the form of a proposed POD that would be agreed to by the PTU owners. Once the Director explains what he believes is necessary to diligently produce the PTU, the Director will give the PTU owners at least 30 days notice for an opportunity to comment on the proposed POD.

After the hearing the Director will make a final determination regarding the rate of prospecting and development for the PTU. If the PTU owners disagree with the Director’s decision, they can once again appeal that decision to the Commissioner and to the Superior Court.

The PTU owners’ obligation will be to convince the court that what the Director proposed is “in excess of that required under good and diligent oil and gas engineering and production practices.” Because the decision involves substantial agency expertise and not merely an application of the law, the court will apply the reasonable basis test and give deference to the department in its review of the Director’s decision.

To quote the court “Under the reasonable basis standard of review for administrative decisions involving complex issues involving agency expertise, the court is to give deference to the agency’s determination so long as it is reasonable, supported by evidence in the record as a whole, and there is no abuse of discretion.”

This means that unless the Director grossly oversteps his authority, the Superior Court will uphold his determination. The PTU owners understand this and will not risk losing the PTU over an appeal unless the PTU owners believe the Director clearly overstepped his authority in what he required of the PTU owners.

Once this step in the process is completed the PTU will be back on track moving toward development.

In-state gas line

2010-03-21T21:43:00.000-07:00

On Thursday, March 18th, the Senate Resources Committee held a hearing on SB287. Several dignitaries and past governors testified. The momentum seemed to be in favor of building an instate gas line and building it now. Each gave a compassionate speech on why an instate gas line should move ahead. But none gave an analysis of the economics of the line or the impediments that should be considered if the proposal were to move forward. Perhaps it is because the sum total of the combined pipeline experience of all the presenters on that day didn’t amount to the years of experience of the average mid-level manager of most major pipeline companies.

The legislature needs to hear from experts in the field of major pipeline construction, not politicians. It needs to hear statistical and economic analysis, not political speeches. Below are some of the questions that should be asked of individuals with the experience and knowledge to give the legislature the information it needs to make a reasoned decision.

Ask someone to provide you with a conservative timeline showing the various elements of the project (similar to the ones TransCanada and Denali have provided). The individual should be able to justify to the legislature’s satisfaction the timing of each phase of the proposed project. What the committee will find is that the project will take six to ten years to complete with a reasonable estimate of eight years, not the two to three years the committee heard on Thursday.

The information provided will help the legislature understand that the short-term need for Cook Inlet gas will not be solved by an instate gas line. That issue still needs to be addressed in another forum.

Also aggressive project schedules generally do not lead to projects being completed any sooner, but they do contribute to increased costs to the pipeline. Schedule driven projects are more expensive but not necessarily faster because of the mistakes they end up having to fix, e.g., higher incidence of late design changes. When the calendar, rather than the data, drives the project, the project usually fails.

Ask someone about the impact of cost on the tariff. What would the proposed tariff have to be to make a pipeline from the North Slope more economic than importing LNG? What is the expected cost of the project? What if the pipeline cost $8 billion instead of $4 billion? Would the state be willing to fund the cost overruns in order to maintain the economic advantage over LNG? Where would the state get the extra funds? There is not enough money in the CBR to cover the potential cost overruns. Is the permanent fund a consideration? Should a vote of the public be required before the legislature approves such an expensive and high risk project?

Ask someone about the route? If the route proceeds through Denali, are they sure they can acquire a right-of-way through the proposed route? By the way, what is the proposed route?

SB 287 grants the Alaska Railroad Corporation the authority to move forward with the project. It was even suggested in testimony that the railroad has a great engineering team. I appreciate the quality of the railroad’s engineering team, but I would not recommend them breaking out as gas pipeline engineers on one of the largest gas pipelines in Alaska’s history. The railroad will need to be run efficiently and without major incident to have a project of this magnitude come in on time and on budget. The railroad will need all of its engineers working full time on railroad projects. They won’t have time to contribute any level of effort toward the gas pipeline. The gas pipeline team may be located within the Alaska Railroad for convenience, but it needs to be totally independent from the railroad from a management standpoint.

The Alaska gas pipeline team is a critical consideration for the success of the project. It needs to be staffed with individuals experienced in building large gas pipelines. It needs to be independent, but the legislature needs to determine how much independence. Who makes the decisions at major milestones? What if a decision is going to cost the state an additional one hundred million dollars? An additional billion dollars? Five billion dollars? The pipeline team needs to understand its authority and when it needs to return to the legislature for additional authorizations.

If the pipeline is going to find an owner to share risk, that needs to be done first, because that owner needs to buy off on management team, management strategy, and management authority. If the pipeline bring on a significant owner after the team is established, the reorganization will increase risk of project delays and cost overruns.

A word on open seasons. It has been said that we don’t need an open season to know there is a need for the gas. The legislature needs to have someone testify about the purpose and need for an open season and the difficulties of proceeding ahead without one. Pipeline size? Customers? Shippers? Who takes the shipping risk if there are no long-term contracts? Is the state willing to pay for shipping gas in the line during the less economic times when no gas is being shipped?

Project phasing. The legislature needs to understand that there are several phases in the building of a major gas pipeline. Each phase has certain milestones that need to be met before the project proceeds to the next phase. If a particular requirement in any phase is ignored, the increased risk associated with ignoring that requirement is borne by the project. If the legislature passes SB 287 prior to receiving the project assessment currently being conducted by the governor’s office, they will have decided to move forward to the project planning phase without the information necessary to make that determination. Making the decision to move forward with the project now but waiting for the governor’s report before actually moving forward with the project doesn’t meet the requirement of reviewing the data provided before making a decision on how to proceed. This is truly form over substance, and a different decision may have been made if the legislature had waited. Once a decision is made, those making the decision often continue to support it even in light of substantial information to the contrary. It is better to make the right decision the first time rather than being required to defend a bad decision later on.

The decision to move forward with an in-state gas line seems to be a foregone conclusion, but if it wasn't the legislature should invite experts to testify regarding the economic alternatives to an in-state gas line. The legislatute may find that an alternative meets the present and future needs of the state for gas better than an in-state gas line at this time. It might also find that an in-state gas line is the best answer to the state's need for energy, but it would have arrived at that conclusion through an analytical process that justified their decision, not a political process based on the current popularity of the alternative.

The legislators are making one of the largest financial decisions of their legislative careers. They need to make sure it is based on good data, not political hyperbole.

Boring

2010-03-14T13:57:00.000-07:00

Good decision-making process is boring. It is slow. It is methodical. It does not enflame or excite. It does not get politicians elected. It does not make headlines. But it is good leadership. It results in direction that ultimately benefits the people of Alaska.

Slow growth is boring. But it is easier to manage that boom or bust cycles.

Long-term fiscal plans are boring, but future generations will thank those in leadership who had the fortitude to endure until a rational long-term fiscal plan is adopted.

A methodical approach to a large diameter pipeline is boring. Evaluating those steps the state can perform to encourage a pipeline is boring. Systematically making decisions based on a thorough analysis of the issues is boring.

Giving speeches about expediting processes to bring gas to Alaskans is not boring. Giving speeches makes headlines. Encouraging speed and quick decisions on projects as significant as a large diameter gas pipeline or an in-state gas pipeline is not boring. But it is also not good decision-making.

Good decision-making for an in-state gas pipeline requires a methodical approach. It requires the state to thoroughly evaluate all the options. It requires the state to understand the economic impact of each scenario. It requires the state to understand the risks associated with each scenario? What assumptions are being made to make each scenario a success? What options allow for phased development? What options require a substantial amount of risk? Which options require financial commitment from the state to make them successful? Options that require state participation, by definition, are not economic in and of themselves and should be understood in that context.

Sometimes the state should make a decision to support a project financially, but it should not be because of a dynamic speech, or an enflamed public. It should only be made after a boring, methodical analysis of all alternatives.

Some say we have waited too long. We need to act now. My answer to them is they are probably right. We have waited too long, but that does not mean we throw out good process. It means we put our heads down and get to work. Just because the state has waited a long time to thoroughly evaluate an issue does not provide justification for circumventing process in an effort to make a quick decision. Be leary of those who recommend speed at the risk of sacrificing process.

The in-state gas issue is an emotional one for Alaskans. Many believe that Alaskans should have had access to “Alaska’s gas” years ago. It is easy to get Alaskans emotionally excited about bringing North Slope gas to Alaska, but perhaps they would not be so excited if they understood the relative economics of that option evaluated against other options that may be equally economically viable.

The public will make their own determination of what they believe is right based on what the media and politicians feed them. Most do not have an independent source of information. It is up to the legislature and the media to provide them with good information. Good information comes from good process. Good information comes from methodical analysis. Good information comes from boring process. It is time-consuming, but the result is much better than the alternative.

An in-state gas pipeline may be the right answer, but it will only be the right answer if the proper process is followed. The public should understand an in-state gas pipeline in the context of understanding the relative economics of a large diameter pipeline. What are the chances of success of a large diameter pipeline? What is the timing of such an endeavor? If Cook Inlet needs gas before the completion of a large diameter gas pipeline, what are the option that could accommodate that need? What are the costs of importing liquefied natural gas (LNG), short-term and long-term? Without state financial support, the economics of LNG imports both short and long term may be more economic than bringing North Slope gas to Cook Inlet. What are other alternatives that may be available to span the need for short-term gas in Cook Inlet?

If an in-state gas line is built, what are the potential upside opportunities that may eventually be created because of its existence? If an in-state gas line is built, what are the ramifications on a large diameter gas line? Some believe that a large diameter gas line would then be uneconomic. A methodical, boring evaluation would shed some light on this issue.

The open seasons will shed additional light on what is necessary to bring North Slope gas to market, but in the meantime the state needs to maintain a slow and boring process that would provide them with information necessary to understand their alternatives in the event it looks like the large diameter pipeline will be delayed or perhaps never get built.

We are now entering a major election cycle - lots of speeches, lots of emotion. But it’s time to be boring. It is time to be methodical. It is time to follow rational process to get to reasoned decision-making. If someone’s speech gets you excited and makes you want to support one option over another, take a second to think about how much information was provided to get you to that conclusion. Was it based on emotion or substance. Always lean toward boring substance. It leads to better decision-making every time. In an election year it is still time to be boring.

Which Pipeline Project is Best

2010-03-13T16:11:00.000-08:00

Politicians make comments every day about which gas line is the right one to ensure Alaska’s future. They throw their support for one project over another based on what they believe will bring the greatest value to the state in the short term and the long term. Some may actually hold positions because they believe it is what the people want to hear, and holding that position may actually help to get them elected or reelected. Some have more experience than others in dealing with oil and gas issues and with gas pipeline issues specifically, but none of them have spent their careers focused on those issues.

The pipeline builders and the shippers, on the other hand, have spent their entire careers on oil and gas issues and have substantial experience in modeling the economics of various pipeline scenarios and in building gas pipelines. They don’t waste their time debating the politicians about which proposal is best. They are not engaged in a popularity vote, and they are not attempting to get reelected. They are focused on what they currently believe is the most economic way to bring North Slope gas to market. Sometimes different companies with differing asset bases come to different conclusions about the best way to bring North Slope gas to market.

The Alaska Pipeline Project, is proposed by TransCanada and ExxonMobil. Denali, the Alaska Gas Pipeline, is proposed by ConocoPhillips and BP. Both projects propose to transport gas from the North Slope of Alaska to Alberta, Canada with the potential of eventually transporting gas throughout North America. In addition the Alaska Pipeline Project proposes an alternative that would transport gas from the North Slope of Alaska to Valdez where it will be liquefied and potentially transported to markets in North America and the rest of the world.

Both projects will propose open seasons this summer. Both will provide tariff terms they hope will entice shippers to bid on their pipeline project. Both open seasons will help the pipeline companies and the state understand what the shippers currently believe is the most economic way to transport their gas to market. The conditional nature of these bids may also give the state perspective on what the shippers believe is required to make the project economic.

Eventually the three major producers will have to reconcile their differences for a project of this magnitude to move forward. Once the three majors reconcile their differences, TransCanada will be added to the equation if TransCanada can show they can bring added value to the table. What is noticeably absent from this discussion is AGIA. It can be considered an impediment to the above discussion, but it brings nothing to the table to assist the producers in reconciling their differences.

One thing AGIA may bring to the table is the ability to continue to move the project forward while the producers negotiate with each other. The state’s $500 million will be used by the Alaska Pipeline Project to continue to perform the tasks necessary to obtain a FERC certificate. In essence this gives TransCanada some additional clout in negotiating ownership and operatorship with the producers. By bringing TransCanada into the project they may increase the timing of completion of the project slightly or at least prevent additional delay.

So where does that put the state. For now the only thing the state can do is wait and watch. I still believe that a fair tax and fiscal stability are two of the issues that will eventually need to be addressed, but the open season will help all of us understand the perspective of the shippers.

I could suggest that we all need to keep our powder dry for a while. But this is an election year, and politicians and the public will need to argue the merits of the various proposals. It may help to get some elected over others, but it won’t change the outcome or success of the Alaska Natural Gas Pipeline.

Geology is King

2010-02-23T20:03:00.000-08:00

Recently there have been several proposals from the legislature and others suggesting the State of Alaska should get in the oil and gas exploration business in Cook Inlet and possibly other areas of the State.

Although the idea has a good sounding ring to it, there are some basic assumptions behind the idea that are flawed. The most important assumption is that if the state gets in the exploration business it will find economic reserves of oil and gas for its dollars. The problem is that the most common sounding ring from an exploration well is hollow – a dry hole. The people of the State of Alaska are not prepared to spend millions of dollars exploring for gas merely to find out the state drilled a dry hole.

The reason companies are not spending money on exploration in Cook Inlet is the area is a mature basin from an exploration standpoint. Most of the major structures have already been explored. Normally this is the time when smaller independent companies come into a basin and explore the smaller structures. The difficulty in Alaska is that the cost of drilling the smaller structures is still too expensive for most independents. So Cook Inlet is caught in a position that the structures that are left aren’t worth the time for the large companies and they are still too expensive for the smaller companies.

The legislature has tried credits, lower taxes, and other incentives to encourage exploration in Cook Inlet, but no amount of incentives, short of providing actual cash, (not recommended) will encourage a company to do something that is not economically and geologically logical. Maybe someday, if an explorer can get a better price for their gas or if additional markets open up, we might see an active exploration program in Cook Inlet, but not before.

A response should do more than just throw water on someone else’s idea. A response should also provide guidance and direction, an alternative to the ideas it believes won’t work. So here is my recommended alternative.

1) Work with state regulatory agencies to approve contracts that allow gas to be sold to the utilities at a more economic (higher) price. Higher gas sales prices might stimulate additional exploration in the Cook Inlet basin.

2) Make sure Cook Inlet is prepared to participate in the large gas line open seasons. Fund ANGDA to hold an open season on a spur line so that Cook Inlet gas purchasers can participate in the large gas line open season. If Cook Inlet gas users do not participate in the large gas line open season, then Cook Inlet will still not get gas from the North Slope even if the large gas line is successful.

3) Encourage the legislature to deal with the two remaining issues that stand in the way of a successful large gas line open season: review the current gas tax and make appropriate changes if necessary and provide fiscal stability through developing a rational long term fiscal plan and budget process. I have addressed both of these issues in previous blogs.

4) Solve the Point Thomson issue so that Point Thomson development can move forward. I have talked about this in previous blogs as well.

5) The administration should meet with the North Slope Borough and the Alaska Eskimo Whaling Commission to understand and address their concerns regarding offshore development. If consensus can be reached, approach Congress for Alaska’s fair share of OCS revenue. If consensus can’t be reached, keep trying. Alaska should only approach Congress for Alaska’s fair share as a unified voice that both supports offshore development and requests Alaska share of that revenue.

6) Ditto Bristol Bay. Sit down with the commercial fishermen, native leaders, and other interested residents and understand their concerns. See if there are options available that would lead to offshore development with their support.

7) Review the economics of heavy oil on the North Slope to make sure the current tax structure is not stifling development.

8) Review exploration on the North Slope to see if exploration is properly incentivized. Oil exploration on state lands has the same problem on the North Slope as it does in Cook Inlet. It is a mature basin from an oil exploration standpoint and exploration will gradually shift to the independents. NPRA and the state and federal offshore are a different matter. They still hold great potential, and given the right incentives and support the state could see more exploration in these areas.

9) Dream big but plan rationally. Always leave the door open for discovery of new large deposits of economically recoverable oil and gas reserves, but don’t plan your budgets around that success.

The alternatives I recommend will not change the viability of Alaska's natural resource development overnight, but they will increase the likelihood of a strong oil and gas exploration and development industry in the future.

Resource Potential of the Alaska North Slope

2010-02-21T22:55:00.000-08:00

The Department of Energy, National Energy Technology Laboratory published a report titled “Alaska North Slope Oil and Gas A Promising Future or an Area in Decline in August 2007. The NETL recently published an Addendum to the Report. The report has often been quoted and used as a basis for projections of future oil and gas potential of Alaska’s North Slope.

The report is helpful in evaluating the prospectivity of certain areas of the North Slope as compared with other areas. For example, onshore state lands between the Colville and the Canning rivers and State Beaufort Sea, (basically all state lands on the North Slope) represent only ten percent (10%) of the future economically recoverable oil potential on the North Slope. Ninety percent (90%) of all future economically recoverable oil potential will be discovered on lands not owned by the state: twenty-one percent (21%) will be discovered in NPRA where the state will receive a production tax but no royalty; forty-seven percent (47%) will be discovered on the federal OCS lands where the state receives no royalty or production tax; and twenty-two percent (22%) will be discovered in ANWR where it is unknown what the state’s revenue percentage will be.

The state fares slightly better in the future economically recoverable gas potential. State onshore lands between the Colville and the Canning rivers and State Beaufort Sea represents almost twenty-five percent (25%) of all future economically recoverable gas potential on the North Slope. Seventy-five percent (75%) of all future economically recoverable gas potential will be discovered on lands not owned by the state: Twenty-two percent (22%) will be discovered in NPRA where the state will receive a production tax but no royalty; fifty-one percent (51%) will be discovered on federal OCS lands where the state receives no royalty or production tax; and a small percentage of gas may be found in ANWR where it is unknown what the state’s revenue percentage will be.

While the relative prospectivity of each area may be important to understand, the reality of what may be found in each area will be quite different. The NETL has modeled the potential for each area, not what they project will be discovered in each area. Figure 3-55 on page 3-107 of the report illustrates the production forecast for oil if the NETL’s “optimistic assumptions” (their term) are accurate. What the chart shows is current production will remain relatively flat for the next 10 years followed by a substantial increase in production until production peaks in 2042 at 3,000,000 barrels per day. This would mean the current oil pipeline would be at peak capacity and the state would have built a second pipeline to accommodate the additional production. This is based on NETL’s projection of the discovery of 35 to 36 billion barrels of oil. Obviously there is a very low chance of this occurring.

Figure 3-56 on page 3-108 of the report illustrates the production forecast for gas if NETL's "optimistic assumptions" are accurate. These optimistic assumptions of the discovery of 137 tcf of gas would have the state producing 11 bcf of gas per day by 2032 which would require all expansions by compression of the proposed 4.5 bcf per day gas pipline and then looping of that line. This too is a virtual pipe dream.

Many believe that the 137 tcf referred to in the NETL report will be discovered and produced over the next 50 years. In fact, they believe the potential is much greater. The only way to ground that belief in reality is to examine what they must also believe about the oil potential that was referred to in the same report. If they believe the 137 tcf will be produced, then they must also believe the 35-36 billion barrels of oil will be produced and that the existing TAPS pipeline will once again be at full capacity and an additional oil pipeline will be build to transport the surplus oil that has been discovered. The absurdity of such a position becomes apparent once it is understood in context.

Hopefully the above perspective will bring a bit of reality and understanding to the discussion of the oil and gas potential on the North Slope. The state should be an advocate for the oil and gas potential on the North Slope, but it should base its economic and business decisions on a more realistic analysis of North Slope potential. It is one thing to dream about winning the lottery, it is another thing to base your current business decisions on that assumption.

DNR Point Thomson Study Evaluated by Feds

2010-02-20T13:38:00.000-08:00

Recently the National Energy Technology Laboratory (NETL) published an addendum to its August 2007 report titled “Alaska North Slope Oil and Gas, A Promising Future or an Area in Decline?” This report is often referred to by the State of Alaska and others for support in identifying the potential undiscovered reserves on the Alaska North Slope.

The April 2009 addendum made few changes to the original April 2007 Report, but one significant addition was the inclusion of a couple of paragraphs referring to Point Thomson. I have included the additional paragraphs below. The quote is from page 2-30 of the report and can be found at http://www.netl.doe.gov/technologies/oil-gas/publications/AEO/ANS_Potential.pdf.

The statement is significant because it evaluates a study commissioned by the Alaska Department of Natural Resources (ADNR) estimating the original oil and gas in place at Point Thomson and, I assume, is at least part of the reason for ADNR’s position arguing that Point Thomson oil is economic and should be produced first, prior to gas development. The federal report states that the DNR study was optimistic and that a more realistic reserve estimate would be approximately one-fifth the size stated in the DNR study.

Quote at Page 2-30

“Point Thomson is a large field, with a long and troublesome history. A study, recently commissioned by the ADNR (ADNR, 2008), provided an original gas in place (OGIP) estimate of 8.5 to 10.4 TCF, with original condensate in place of 490 to 600 million barrels of condensate (MMBC), and OOIP of 580 to 950 MMBO in the oil rim. The study suggests that under ideal conditions, with gas cycling and extended production of condensate and oil prior to gas blowdown (30 years with 22 producing wells and 8 injection wells), the field could produce as much as 420 to 515 MMBCF and 290 to 475 MMBO. The technically recoverable gas reserves produced under a scenario similar to the one above would be about 5.9 to 7.3 TCF. If blowdown were to occur early in the history of the field development, the models suggest that recovery of condensate and oil could be as low as 127 to 156 MMBC and 30 to 150 MMBO, but gas recovery would be in the 6 to 7 TCF range over a period of 12 to 15 years (ADNR, 2008). Additional scenarios were run with varying numbers of producing and injection wells, for periods of 10 and 20 years before blowdown, and results shown production ranges of: (1) 10 years of cycling – 300 to 370 MMBC, 225 to 370 MMBO, and 4.8 to 5.9 TCF, and (2) 20 years of cycling – 370 to 450 MMBC, 250 to 400 MMBO, and 4.8 to 5.9 TCF.

The findings appear to be optimistic and open to question, especially with respect to the recovery predicted for oil from the oil rim. The summary of findings (ADNR, 2008) cites the oil having American Petroleum Institution (API) gravity as high as 18°. This is the same range of API gravity as the heavy oil being produced from the West Sak and Schrader Bluff reservoirs, and recoveries are not projected to be more than 5 to 10%. The API gravity at the Kuparuk West Sak pool ranges from 22° to 10°, increasing with depth (temperature) and at the Milne Point Schrader Bluff pool it ranges from 22° to 16°. Thus a more realistic value for the oil rim at the Point Thomson field may be 58 to 95 MMBO, not the 290 to 495 MMBO theorized in the PetroTel study performed for ADNR. The Point Thomson owners “don’t believe the recovery of this heavy oil will be more than 5% --- nowhere near 50” (PN, 2008). They further state that “the oil rim is thin, discontinuous, and heavy oil --- molasses.””

The above bolding was mine and not in the original report. Additional discussion consistent with the above can be found at pages 3-98,99 where the NETL calls the ADNR study "overly optimistic."

Two Important Pipeline Variables

2010-01-27T23:24:00.000-08:00

Debt/Equity Ratio and Return on Equity

When analyzing a specific proposal, and especially when comparing two alternative proposals, the proposed debt/equity ratio and the return on equity are two of the most important factors in comparing the projects.

Some might say that the cost of the pipeline is an important factor, but what one company estimates for the cost of the project versus what another company may estimate for the cost of the project is not really material unless it can be determined why one estimate is more than the other. For example, a forty-eight inch pipeline made out of the same grade of steel from the North Slope to Alberta should cost roughly the same whether it is constructed by Denali or TransCanada. Any substantial differences in costs should be able to be identified by some unique benefit one company brings to the table over the other.

But debt/equity ratios and returns on equity create substantial financial impacts to the tariff and to the amount of revenue received by the State of Alaska from a proposed pipeline.

The 2007 State of Alaska presentation to the Senate Finance Committee shows the impact the debt/equity ratio has on reducing the tariff and on the present value in $billions to the State of Alaska. As the graph on page 4 shows, a debt/equity ratio of 80/20 provides a much greater value to the shippers and to the State of Alaska than a 75/25, 70/30, or especially a 60/40 debt/equity ratio. The reason for this is that debt carries a much lower interest rate than the normal return on equity.

The State’s 2007 presentation can be found at http://www.dog.dnr.state.ak.us/agia/pdf/agia_docs/derate_assumptions_sf.pdf

The greater the equity position the pipeline company proposes, generally the higher the tariff. This can be exacerbated when the pipeline company also proposes a higher than normal rate of return on its equity. For example, TransCanada, in its AGIA application proposed a higher than normal rate for its return on equity. In fact, Exxon, in its initial comments to TransCanada’s AGIA Application stated, “… after shifting risk to its customers through “negotiated rate” terms, TransCanada proposes a return on equity (ROE) at the high end of ROEs previously approved by the FERC, and well above ROEs typically approved by the NEB.” Since Exxon is now a partner to TransCanada, perhaps TransCanada’s proposed ROE will be more reasonable.

Exxon’s comments are on DNR’s website at http://www.dog.dnr.state.ak.us/agiacomments/Uploads/030608153830.pdf

All other comments regarding TransCanada’s application can be found at
http://www.dog.dnr.state.ak.us/agiacomments/Comments.aspx

If the State decides to bid its royalty gas at one of the open seasons, it should examine the proposed debt/equity ratio and return on equity proposed by each of the projects prior to making its decision.

Do Oil Taxes Need Revision

2010-01-19T21:51:00.000-08:00

The debate over oil taxes has recently resurfaced as an issue of importance: some saying that oil taxes need to be rolled back to what Governor Palin initially proposed. Others saying the industry should justify any changes.

The current tax was modeled on the Prudhoe Bay oil field and to a certain extent on Prudhoe Bay satellites, Kuparuk, and Alpine. When the tax was passed, there was a some level of uncertainty regarding what the long-term impact would be on exploration, marginal oil fields, and difficult to produce heavy oil. It was acknowledged that if negative impacts were identified, the tax could be reexamined as to the negatively impacted activities.

The industry has expressed concerns regarding the impact of the current oil tax on their operations. If it is determined that industry investment is being reduced in all areas of oil field development, then a broader review and analysis of the oil tax would be appropriate. But a wholesale revision of the oil tax is not necessary unless it can be shown that major oil fields, satellites, difficult to produce oil fields, and exploration are all being impacted by the tax.

If the industry is concerned about the impact on exploration, then the focus of the review should be on the economic impact of the tax on exploration.

Exploration could be slowing in Alaska for a number of reasons. One is that Alaska onshore is a mature province. Most of the large identified structures have been explored. The industry could be making a reasonable economic decision moving their exploration dollars offshore based on geologic potential and using that as a political opportunity to make a point about the high cost of doing business onshore. My guess is that both are true. The greater geologic potential is offshore and the value of those prospects, if taken to development, will yield a much greater value than a comparable prospect onshore.

The question for the legislature is, "Can a change in one or more variables under the legislature's control change corporate decision-making regarding where they spend their exploration dollars?" A review of the issues surrounding that question would be appropriate for legislative debate.

If the reason for the move offshore is because of the lack of exploration prospectivity onshore, then the state may still need to examine exploration credits and incentives to encourage the major oil companies and independents to explore for the remaining smaller prospects onshore.

If it can be shown that the production tax is having a substantial impact on exploration project economics, then it is appropriate to examine the level of tax as it relates to that negatively impacted activity.

Point Thomson - Where to From Here?

2010-01-13T03:17:00.000-08:00

In order to understand the Court’s January 11, 2010 decision, a review of what the court told DNR and the Point Thomson Unit (PTU) Owners in the December 26, 2007 decision is necessary.

In the December 26th opinion the court addressed two issues: (1) the Department’s rejection of the Lessees’ proposed modified 22nd Plan of Development (POD) for the PTU, and (2) the Department’s termination of the PTU.

Regarding the Department’s rejection of the 22nd POD the Court determined that DNR had the authority to administratively decide whether a proposed plan of development should be accepted or rejected and cited Section 10 of the PTUA which states that the POD “shall be as complete and adequate as the Director may determine to be necessary for timely development and proper conservation of the oil and gas resources of the unitized area…” As to the standard of review the Court would apply to DNR’s decision, the court stated that the court’s “review of those determinations ‘would need to be appropriately deferential’ such that the reasonable basis test would apply.”

“Under the reasonable basis standard of review for administrative decisions involving complex issues involving agency expertise, the court is to give deference to the agency’s determination so long as it is reasonable, supported by evidence in the record as a whole, and there is no abuse of discretion.”

What this meant to the PTU Owners is that DNR had broad discretion to accept or reject a POD and if the PTU Owners wanted to have an approved POD they would have to listen to what DNR requested and respond accordingly.

Regarding the Department’s termination of the PTU, the PTU Owners argued that the termination could only occur by bringing action in State Court. The court disagreed and stated that termination could occur through administrative action, but the court then went on to state that Unit termination was just one of the remedies for rejection of a POD and that DNR did not provide the Unit Owners with an opportunity for a hearing on the appropriate remedy to the State upon DNR’s rejection of the proposed 22nd Plan of Development. The Court remanded the matter to DNR to conduct a hearing on the appropriate remedy.

The court provided DNR with two statements of guidance regarding its review of the appropriate remedy for rejection of the POD. The first came in footnote 7 on page 24 of the opinion. There the court stated:

“But see Section 21, second paragraph, of the PTUA as modified in 1985. [R. 794] That revision specifies that the Department may not require any increase in the rate of production or development “in excess of that required under good and diligent oil and gas engineering and production practices.” This section may well have applicability when determining the appropriate remedy when DNR rejects a proposed plan of development. See discussion, infra.”

The second came near the end of the opinion at page 42:

“Accordingly, this matter is remanded to the DNR for the purpose of according to the Appellants a hearing on the appropriate remedy to the State upon DNR’s rejection of the proposed 22nd Plan of Development. On remand, the agency should also consider the import of Section 21 of the PTUA, as amended in 1985, in determining the appropriate remedy.”

A statement like this is comparable to telling DNR they have the right to determine the remedy for a rejection of a POD, and Unit termination is one of those options, but the DNR should apply the standards in Section 21 to make that determination.

Subsequent to the issuance of the above opinion, recognizing what the court said about DNR’s authority to reject a POD and possibly terminating the Unit, the PTU Owners submitted a 23rd POD substantially committing to everything DNR had previously requested: an unequivocal commitment to bring the unit into production.

DNR granted the PTU Owners a hearing and considered Section 21 as the court requested but determined that Section 21 did not apply to its analysis of remedies. DNR then rejected the PTU Owners proposed 23rd POD and terminated the Point Thomson Unit without applying the standards set out in Section 21 of the PTUA.

With the above as background this document will now analyze the January 11, 2010 Superior Court Decision.

The second sentence in the first paragraph provides a concise statement of the next 30 pages of analysis, “…the contractual agreement between DNR and the Appellants precludes termination of the Point Thomson Unit in these circumstances without consideration of good and diligent oil and gas engineering and production practices, …” .i.e., the DNR did not consider the standards set out in the second paragraph of Section 21 as the court told them to do; therefore, DNR may not terminate the Point Thomson Unit.

In its analysis the court found that the interpretation of Section 21 is “dispositive of this appeal.” The PTU Owners argued that DNR was required to comply with the provisions of Section 21 and DNR argued that Section 21 did not apply to its remand proceedings.

If Section 21 does not apply to DNR’s POD decision, then the burden for coming up with an acceptable POD lies with the PTU Owners and DNR is not obligated to propose or identify conditions that would lead to an acceptable POD. If Section 21 applies to DNR’s review of remedies for a rejected POD, then DNR has a burden to identify conditions that would lead to an acceptable POD.

DNR proposed five reasons why Section 21 should not apply to its remand decision and the court systematically disposed of each. The crux of the Court’s decision came with its response to DNR’s fifth reason: an impermissible shift of burden to DNR to determine the appropriate rate of production. The DNR argued that if it were required to comply with the standards set out in Section 21, the agency would be inappropriately “saddled with the burden of designing an adequate POD.” The Court recognized that burden but considered it a reasonable contractual obligation for DNR to meet and in a footnote implied that DNR was not in as bad a position as it supposed and that DNR could probably require the Unit to go into production or be terminated.

The Court then determined that the PTU Owners did not receive a Section 21 hearing and that further proceedings were necessary.

The next issue the Court addressed was a due process concern. The PTU Owners argued that the dispute should be referred to an independent hearing officer or, in the alternative, the Court should grant a trial de novo. DNR argued that the due process concern should be addressed first before the trial de novo decision was made.

The court stated that “An impartial tribunal is basic to a guarantee of due process” and found a due process violation in DNR's process because the attorneys advising the Commissioner were the same attorneys that represented the agency on the first appeal and because Ms. Nan Thomson served as both the hearing officer at the remand proceeding and previously as DNR’s representative when the agency was defending its first decision in the 2007 appeal before the Court.

Once the Court made a finding of a due process violation the only remaining issue was whether the court should remand the matter to DNR for an administrative proceeding in accordance with this decision or retain jurisdiction and conduct a de novo trial. The court then gave both parties 30 days to submit additional briefing on this issue.

This places DNR in the interesting position of arguing to the Court that it should be granted the right to conduct a Section 21 hearing and that it can effectively apply the Section 21 standards to the issues before it when it had previously argued so vehemently that Section 21 standards should not apply. It will be interesting to see if the Court grants DNR the right to hold the hearing or if the Court has lost so much trust in the agency that the court retains jurisdiction and makes the determination itself.

In summary, the Court determined that the Section 21 standards applied to DNR’s decision requiring DNR to identify for the PTU Owners those conditions that the DNR considers necessary for approval of an acceptable POD, and if DNR is granted the right to conduct a Section 21 hearing, it must be conducted by an impartial hearing officer.

PFD - To Enshrine or Not To Enshrine

2010-01-06T11:43:00.000-08:00

Debates about the Permanent Fund Dividend and the Permanent Fund tend to arise like a phoenix during election years. They are often used to arouse and enflame the public into voting for or against a particular candidate based on whether they want to protect the "Holy Grail." How the Permanent Fund is managed and whether or not the Permanent Fund Dividend should be enshrined in the Constitution are not good candidates for election year debates because legislators, during those debates, seem to be more focused on garnering votes and influencing the ballot box than they are in the financial future of the State.

That said, if the debate occurs, attempting to enshrine the dividend into the constitution without simultaneously dealing with the rest of the budget is like making a decision to take the family on a vacation to Disneyland every year regardless of the cost or impact to the family budget and also deciding not to plan for that expense through a rational budgeting process.

If enshrining the dividend into the constitution is on the table during this legislative session, the same bill should evaluate the rest of the Permanent Fund and how it will be managed into the future. A rational approach to a long-term financial plan that includes the Permanent Fund and addresses the Permanent Fund Dividend is an appropriate discussion for the legislature to have, but all three issues should be addressed at the same time.

And if enshrining the dividend is on the table, the legislature certainly wouldn't want to enshrine the current dividend formula into the Constitution. If anything the current formula brings instability and uncertainty to the program. There have been some years when there was concern, due to the poor performance of the Permanent Fund, that no dividend would be issued. And in the best year of the Fund, the payout was almost $2,000.00.

A much better dividend program would be to decide what a reasonable dividend would be in the first year, e.g., $1,000 and inflate it in future years based on the Consumer Price Index or other inflation factor. This would be a much more dependable and rational approach to issuing a dividend to the people of Alaska. The only problem with this approach is that it does away with the "Lottery Effect." People, often to their detriment, are willing to risk some level of certainty and security to obtain some additional benefit. The Alaska public, generally, may be more willing to give up a sum certain and the risk of a certain amount of loss for the potential benefit of a larger dividend.

In addition, any dividend program should be based on an "up to" amount. In certain situations, it may not be rational or reasonable to issue dividends to the Alaska public in the amount the formula allows. The legislature should always have the discretion to authorize a lesser amount. Generally their fear of being ousted by the public at the next election will protect the dividend from the legislature reducing it unless it is absolutely required.

Bob Swensen - Instate Gas Czar

2010-01-05T10:47:00.000-08:00

Governor Parnell recently appointed Bob Swenson to lead the effort to review the viability of an in-state natural gas pipeline. Bob is an excellent choice. He is level-headed and rational in his approach to problems. I am not as optimistic about the prospects of an in-state line. What I expect Bob to find is a lot of energy and desire to bring North Slope gas to Fairbanks and the Cook Inlet without regard to the short-term or long-term costs of the project.

Several studies have been done in the past comparing a small in-state line to other alternatives, and although those studies have been completed a number of years ago the economics of the alternative proposals haven't changed significantly since those studies were completed.

Along the way Bob will discover a group of Alaskans that believe that "It's Alaska's gas, and we should use it to benefit Alaskans." By that they mean that cheap Alaska North Slope gas should be transported to Fairbanks and Cook Inlet and used to reduce the cost of energy to local users.

This is a nice thought, but economics don't follow their dream. Alaska North Slope gas is not cheap either to purchase or to transport. Bob will find out that it is cheaper to import LNG and store gas in Cook Inlet than it is to build a small gas line from the North Slope to Cook Inlet. If an Alaska Natrual Gas Pipeline is never built, it will be cheaper for Cook Inlet residents to pay for imported LNG than to pay for gas shipped through a small gas line from the North Slope. Those that want "Alaska's gas for Alaskans" are going to have to argue that they would rather pay more for their gas than use that cheaper imported gas. Their new mantra should be "Buy local, pay more." They will probably get a few die hard followers to support them, but most Alaskans follow their pocket books not emotions when making economic decisions.

Assuming an eventual success for an Alaska Natural Gas Pipeline, it will be cheaper to transport gas in the "big line" to Delta and build small spur lines to Fairbanks and the Cook Inlet than it is to build a small line from the North Slope to service those communities. If the State or its contractor builds a small line to Cook Inlet, the buyers of that gas will pay a greater price for that gas than the gas that is shipped down through the big line. The benefit of a small line is Cook Inlet gets gas a few years earlier and pays a premium for that gas. Those that agree to purchase that gas will pay that premium for up to 20 years. Those that decide to wait a few years will purchase the cheaper gas the flows from the "big line."

To recap, the following are the results I expect Bob to find once he completes his review and analysis.

It is cheaper to import LNG than it is to transport gas from the North Slope to Cook Inlet in a small gas pipeline.

It is cheaper to transport gas in the Alaska Natural Gas Pipeline with spur lines to Fairbanks and Cook Inlet than it is to build a small line from the North Slope.

For those that believe "Alaska's gas should be used to benefit Alaskans," their mantra will only earn them the right to pay more for their gas than any of the other viable alternatives.

Restructure Alaska’s Revenue System

2010-01-02T16:08:00.000-08:00

If one considers all the options that could occur in the future for the State of Alaska, all of them lead to a similar conclusion. Alaska’s revenue system needs to be restructured.

There are two basic alternative scenarios that could occur in Alaska’s future. Alaska could get an Alaska Gas Pipeline, and additional revenue could either trickle or flow into the state general fund based on the profitability of the gas pipeline. Or Alaska’s gas could still be sitting in the ground on the North Slope because other forms of gas development in the lower-48 and the rest of the world were more economic than Alaska gas to produce. In that case no additional revenue would flow into the state’s general fund, and Alaska would be dependent on the existing oil revenue to balance its budget. Either alternative points to the need for a long term fiscal plan that takes into consideration the two above possible scenarios and all the variations in between.

The state’s worst case scenario would be for no gas pipeline to be built and for no major additional oil reserves to be found on the North Slope and the oil pipeline to eventually be reduced to a trickle. At that point the state’s major revenue stream would have dried up. We must be prepared for that as a viable alternative.

On the other extreme the state could be overflowing with additional revenue. The new exploration brought about by the building of the Alaska Gas Pipeline could bring on new discoveries in both oil and gas. The Department of Energy has stated that there are up to 35 billion barrels of oil and 137 trillion cubic feet of natural gas to be discovered on the North Slope of Alaska. If a substantial part of that is discovered by the oil and gas industry, then the oil pipeline will be full once again and the gas pipeline will be built and expanded to provide the space necessary for all the additional reserves that have been found.

A friend reminded me that there is one additional viable alternative that should not be discounted. That is GTL's. The GTL (gas to liquid) technology could take North Slope gas, convert it to a liquid, e.g., diesel, and ship it down the oil pipeline, extending the life of the pipeline and monitizing the natural gas on the north slope. If natural gas prices stay low for the long-term, this process could provide the greatest economic benefit to Alaska of all of the other viable alternatives. The benefit of the GTL process is that it can be brought on in phases. The cost of each phase would be substantially less that the greater cost of building a natural gas pipeline from the North Slope through Canada or to Valdez.

Prior to any of the above alternative scenarios occurring the state needs to develop a rational method for managing those funds, or lack thereof, instead of attempting to make decisions in the midst of “winning the lottery” or ending up in the poor house. A rational approach to managing funds is difficult when thousands of constituents are proposing great ideas on how to protect their interests.

The time has come for the State of Alaska to revisit the way it manages its money. If gas is not our future, then we need to make decisions now on how we are going to manage the oil wealth we have left. If gas is in our future, we need to decide now how we want to structure the state finances to manage that wealth into the future. If we decide now, we have up to 10 years to provide for a reasonable transition opportunity. If we wait until the last minute to decide, we limit our options and probably experience some level of pain, possibly a substantial amount of pain, in attempting a short transition.

The legislature is responsible to develop and maintain a budget that accounts for the needs of both the present and future generations. The funds received today, next week, or next year need to be handled responsibly. Extravagant projects today lead to maintenance burdens tomorrow. Funds should be expended or saved with an eye to their value and burden on the future.

If the state were to base its budget on what it could afford long term, then this would give the industry comfort that there would not be pressure on the legislature to increase taxes to bridge short term budget gaps.

If the oil and gas tax revenue were not immediately available to balance the State’s budget, then there would be less pressure to change oil and gas taxes to meet the State’s current needs.

If the State developed a rational long-term plan that accounted for the various scenarios that are possible in its future, then the producers would be less concerned about future changes in the tax structure.

If the State were able create a rational long-term fiscal plan and a reasonable oil and gas tax structure, then the producers would have fiscal stability, the open seasons would be given the chance they need for success, and the State would have a strong and viable oil and gas exploration and development industry in the State.

Timing of the Legislative Debate

2010-01-02T12:06:00.000-08:00

Some have said that the State needs to have a better estimate of what the pipeline is going to cost before the legislature evaluates the gas tax, but the legislature doesn’t need to know the cost of the pipeline or the future price of gas in order to make good decisions about the gas tax. The tax cannot be based on what someone thinks the cost of the pipeline will be or on their estimate of the future price of gas. If history has taught us anything, it is that we are not good predictors of the future, and we will surely fail if we pass a tax based on a specific value for the pipeline or some expert’s projection of the future price of gas.

Over the past couple of years the estimated cost of the pipeline has fluctuated wildly based on the estimates on the price of steel and the cost of labor. Those estimates will probably continue to fluctuate until contracts are executed and the pipeline is built. And the experts’ predictions of the price of gas have not even been close to what has actually happened in the short term let alone the long term. Projections are an inexact science and they should not be depended upon for determining Alaska’s future. The legislature must assume a broad range of variables when it determines what a fair tax would be. The tax should be fair if the price of the pipeline costs $25 billion or if it costs $50 billion. The tax should be fair when the price of gas is at $2.50 and when it is at $12.00. The legislature does not have to wait for more information. If they wait, the information will only be marginally better than what they have today. If the legislature passes a fair tax prior to the open season, it will have provided additional needed information to enable the producers to effectively participate in that open season. They will have contributed to the potential success of the open season instead of waiting to participate in a finger pointing exercise afterword.

The highest chance for a successful open season is to address the critical issues ahead of time, not wait until after an open season has failed.

Fiscal Certainty and a Stable Tax Enviornment

2009-12-30T21:04:00.000-08:00

When most people think of a stable and durable tax environment, they think the producers are asking for a lock on gas taxes for a substantial number of years. Some have suggested 35 years as a reasonable timeframe. But there are alternatives that haven’t been considered that can provide the producers with just as much stability without a contractual lock on the gas tax they are requesting.

In order to understand the effectiveness of an alternative to the producers’ proposed contractual lock, the producers’ issues of concern needs to be identified and understood. Why do the producers believe the Alaska tax structure is not stable or durable?

The producers are concerned that, even if the tax is fair, the legislature may ultimately decide to increase the tax to balance the State budget during hard economic times, especially after the producers have committed billions of dollars to an Alaska Gas Pipeline. This is part of the reason why the producers say that there is no fiscal stability in the State tax structure, and they are correct. The producers have seen this “pressure to increase taxes” occur every time there is pressure on the State to find additional tax revenue to balance its budget. If this concern were addressed effectively, then the concern about legislative freedom to change the tax would not be as important.

There are two aspects of producer concern: first the legislature’s willingness to change the law whenever it serves the interests of a majority of the legislature to do so, and second the legislature’s need to find additional tax revenue to balance the state budget when times are tough.

Regarding the first issue, the legislature is generally reticent to take on controversial issues unless it is absolutely necessary. Gas taxes is one of those issues. Unless the oil and gas industry is receiving a strongly disproportionate share of the revenue, e.g., oil taxes under the economic limit factor (ELF), the legislature will not take up the tax issue during the legislative session. If the legislature does an effective job when it revises the current gas tax and creates a fair tax, then it will not be necessary to take up the issue for purposes of a fair allocation of revenue between the State and the producers. The first part of the tax stability issue will have been resolved. So long as there is a fair allocation of revenue between the State and the producers the political incentive to change the tax is gone.

The next problem the producers have with our current system is that the State’s budget is based on projected annual revenue in the general fund. Oil taxes are placed directly into the general fund for legislative appropriation. If the state is having difficulty balancing its budget, the industry believes that increased oil and gas taxes will be the first place the legislature looks to balance the budget. Personal income taxes and any other taxes that burden the Alaska public come only after taxing the oil and gas industry. Historically fiscal restraint and increased taxes on the oil and gas industry have allowed the state to balance its budget without burdening the rest of Alaska with additional taxes. Serving as the backstop for the legislature to balance its budget is not a business friendly environment in which to operate for the oil and gas industry.

So long as the state’s budget is based on oil and gas revenue in the general fund the state will not have a predictable and durable tax structure. So long as the State can increase oil and gas taxes to balance its budget, the state will not be a stable fiscal environment in which to do business. What the State needs to do is to alter the way funds are received and spent. A method needs to be devised whereby an increase in oil and gas taxes does not “fix” the state’s current budget problem. If new taxes could not be used to balance the state’s budget; then there would be less incentive to raise taxes on the oil and gas industry.

If the legislature were to be able to change its tax structure to create a fair tax and change the budget process to address the stability concern prior to the Alaska Gas Pipeline open season, then the legislature will have effectively addressed the producers’ desires for a stable and durable fiscal regime.

Fiscal Certainty and a Fair Gas Tax

2009-12-30T20:44:00.000-08:00

When the producers say fiscal certainty, it means different things to different people. To some it means lowering taxes. To others it means locking in certain taxes for a long period of time. But the real question is what does it mean to the producers. The producers have stated on several occasions that they require something more than is currently on the books to provide them with the certainty necessary to participate in the open season of the Alaska Gas Pipeline project. They have asked for durable and predictable financial terms. They have asked for a predictable fiscal regime. They are concerned about managing the risks of a sovereign that can change tax laws any time the majority of legislators believes it is necessary and appropriate to do so. Durable and predictable financial terms? Fiscal regime? What do the producers really want? What do they really need?

The common belief is that the producers are asking for tax concessions when they use indistinct terms like fiscal regime and financial terms. They may certainly want tax concessions, but that is not what they really need to move the project forward. There are two issues that need to be addressed in order to encourage the producers to participate in a binding open season: fair gas taxes and a stable fiscal environment.

First, fair gas taxes. The goal of any tax should be create a tax structure that shares value fairly between the sovereign and the taxpayer. When profits are high, the state should receive a greater share of the wealth. When profits are low, the tax payer should be allowed to pay less. The goal of a fair gas tax should be to create a tax that is fair at all gas price ranges and for a broad range of pipeline costs.

If the tax is not seen as fair by either the taxpayer or the sovereign, it is not stable. There is a higher likelihood of the tax changing than if the tax was seen as fair or at least acceptable by both sides. If the taxpayer sees the tax as unfair, then the taxpayer, if it has the option to do so, will spend its development dollars in other jurisdictions, and the sovereign will lose the value of the taxpayer’s participation in the State. There will be fewer jobs and less tax revenue.

If the tax is seen as unfair by the sovereign, the people or the governing body, then there will be pressure on the legislature to change the tax. The greater the disparity in fairness, the greater the pressure to change the tax. The oil tax under the economic limit factor (ELF) is a good example of this occurring. The problem encountered in the ELF was that a portion of the production was not tied to the price of oil, and it led to an inequitable result. Ultimately the oil tax was revised under the new Production Profit Tax (PPT) and the problem discrepancy was resolved.

The oil tax that was passed included a progressivity element that allowed the state to have a lower share of the profits at low oil prices and higher share of the profits at high oil prices. The tax was primarily focused on the reserves at Prudhoe Bay. It was hoped that the tax would not negatively impact heavy oil development or exploration in the state. If it was determined that the tax was affecting the future development of oil in the state then the tax could be changed based on that new information.

Some say that the state went too far when it passed the PPT, especially as it relates to exploration and heavy oil. If that is the case, the legislature can reexamine that portion of the tax and determine if adjustments to the tax need to be made. Part of the reason not to lock in a tax for a fixed number of years is so that the legislature can modify the tax as the need arises. But some would argue that having the ability to change the tax is the very risk the producers are concerned about. If the tax is fair to both the taxpayer and to the sovereign, then there will not be the political will to change the tax, and it will be stable. If the tax is not fair, either to the taxpayer or to the sovereign, then there will be pressure to change the tax, and the tax will need to change to take care of the disparity. That is a risk that should be acceptable to the taxpayer and to the sovereign. The state needs to continue to have the right to adopt a taxing structure that responds to the ever changing economic environment of oil and gas development in the state.

There is a similar problem with the current gas tax as there was in the ELF oil tax. The problem with the gas tax is that the tax is based on a fixed value ratio between oil and gas. When gas prices are low and oil prices are high, as they are now, the industry gets an extra tax break that wasn’t intended in the original legislation. Such a fairness disparity will make the tax unstable in the future if not fixed, and ultimately there will be pressure to change the tax to fix the disparity. This issue should be resolved before the open season because there is at least some chance that gas shippers will bid at the open season and have the right to the current gas tax fixed by statute for at least 10 years after first production. The first ten years of production may be the most productive years of the field. It may also be the years where the greatest impact is seen from the flaw in the current gas tax that allows for an unintentional credit from gas production to those who are also producing and selling oil.

The state needs to take the same approach to developing a fair gas tax as it did with the oil tax. It needs to begin with a review of the economics of gas development in Alaska, taking into account the existing reserves already found at Prudhoe Bay and Point Thomson and the risk and cost of exploring for gas in the most remote regions of our state. It needs to make sure there is a fair allocation of revenue between the producers and the state for all costs and gas price structures.

This review needs to happen now. If the legislature were able to pass a new gas tax prior to the first binding open season, then the producers could calculate the cost of development of their reserves and be prepared to participate effectively in the open season process. To delay this debate will only lead to more debate later if there is a failed open season. Some will say the industry was merely using the failed open season as an excuse for not participating in a project they wanted to fail anyway. Others will blame the administration for being so adversarial to the industry that they would rather see the project fail than the see the industry economically benefit from the project moving forward. They see the Administration as more interested in hurting the industry than in helping the State.

The industry will blame the state for not addressing the fiscal certainty issues. The state and public will blame the industry for wanting to kill the project. Finger pointing and assigning blame for a failed open season will not be helpful in moving a gas pipeline project forward. The state needs to take the issue off the table by addressing it during this next legislative session.

The Sovereign's Responsibility

2009-12-30T20:05:00.000-08:00

Much has been said about the State of Alaska's responsibility to get a pipeline project moving. Alaska's governors (present and past), legislators, candidates, and advocates for various alternatives have all weighed in on the issue. Most of the comments and positions have centered on when and how to negotiate with the producers and how that will affect the upcoming elections in 2010. The most popular position seems to be waiting to negotiate with the pruducers until after the open season when the State will know more about the cost of the pipeline and the conditions under which the producers will ship gas. This might seem like a logical position at first blush, but not all seemingly logical positions are right. The State does have a responsibility toward the pipeline and toward the producers, but negotiations is not a part of that responsibility.

The State has a right to negotiate contracts when granted that right by law. The Stranded Gas Development Act (SGDA) granted the State the right to negotiate a contract with anyone interested in building a gas pipeline. Included in the SGDA was the right to negotiate taxes and other incentives in order to encourage the building of the Alaska Gas Pipeline. This course of action resulted in a contract with the producers that was ultimately rejected by the people of Alaska.

Another form of contract negotiations is through the competitive bid process. The Alaska Gasline Inducement Act (AGIA) utilized this process when it granted TransCanada a license under the conditions stated in the statute. Once the license was awarded, it became a binding contract on the State. The State agreed to provide TransCanada with a State matching contribution of up to $500 million in support of their project and a commitment not to extend preferential tax treatment or state money to competing projects. In exchange TransCanada agreed to the conditions under which the license was granted, including certain timelines and commitments regarding expansion of the pipeline. TransCanada is currently pursuing building a pipeline under that license. The license does not provide for the State to negotiate with the producers in order to make the TransCanada project successful.

There are no other methods of negotiations provided for in statute except those found in the SGDA and AGIA. If the producers require certainty or changes to the tax structure beyond that which is currently granted in the law in order to make the Alaska Gas Pipeline project economic, then they have the right just like every other resident of the State of Alaska to take their petitions to the legislature. If they can convince a majority of the legislators in an open public process of their recommendations, the legislature will change the laws and address those concerns. If they cannot, the producers will move forward or not move forward with the project based on the laws as they now stand. When determining if a law needs to be changed, the sovereign does not negotiate with anyone, no matter how strong, rich or powerful they may be. If someone wants to convince the governor of their requests, the governor may submit proposed legislation to the legislature for their consideration, but it is the legislature's responsibility to determine if the requests are justified.