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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.
Wednesday, January 27, 2010
Tuesday, January 19, 2010
Do Oil Taxes Need Revision
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.
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.
Wednesday, January 13, 2010
Point Thomson - Where to From Here?
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.
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.
Wednesday, January 6, 2010
PFD - To Enshrine or Not To Enshrine
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.
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.
Tuesday, January 5, 2010
Bob Swensen - Instate Gas Czar
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.
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.
Saturday, January 2, 2010
Restructure Alaska’s Revenue System
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.
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
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.
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.
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