Wednesday, January 30, 2013

The greatest economic threat to Alaska: Decline in TAPS throughput and increasing budgets

The decisions made this session will impact my children, my grandchildren and future generations of Alaskans

Deborh Brollini
Public Testimony: Alaska Special Committee on TAPS Throughput
January 29, 2013

Thank you for the opportunity to testify this evening. My name is Deborah Brollini. I am a 37-year Alaskan and I am testifying on behalf of myself, and my children Lyndsey and Van. I first would like to thank Senate leadership, and those of you on this committee for putting your lives on hold to take on the monumental task of making difficult decisions this legislative session. The decisions made this session will impact my children, my grandchildren and future generations of Alaskans.

I am personally not married to the governor’s oil tax reform bill. I think it is a starting point, and an opportunity for the bill to be vetted by the public, and improved upon to move Alaska forward. I would request that you do your due diligence and do what is best for Alaska. 710,000 Alaskans livelihoods are at stake, and the time is now to act. I am survivor of the Alaska economic crash of 1986 where I was laid off from ARCO, spent five years foreclosing on homes and watched half my friends leave the state.

I believe Alaska’s future is bright, the opportunities are vast, and we can achieve it all if we think long-term, work together, and put Alaska first. Thank you.

Reasons why we need to look at Alaska's oil tax code revisions

Steve Pratt
CEA Ak Testimony
Special Senate Committee on TAPS Throughput
January 29, 2013

Thank you, Chairmen for allowing public comment on tax reform. My name is Steve Pratt, Executive Director of Consumer Energy Alaska, a regional chapter affiliated with the national Consumer Energy Alliance. We believe there are several reasons why we need to look at tax code revisions:

Business and residential consumers of energy have a direct interest in consuming competitively priced energy supplied from domestic sources, and also have a direct interest in robust overall economic activity to maintain livelihoods.

30% of Alaskans are dependent upon oil and gas exploration and development for employment.

Oil production has declined from a peak of over 2 million barrels a day to a little over 500 thousand barrels a day and is in freefall at the rate of 5 - 7% per year during times of increasing oil prices.

Alaska is capable of providing a great deal more of total domestic oil production in the United States.

Alaska’s abundant natural resources and oil production are vital to the energy security of the entire nation as well as the state.

New exploratory and development drilling is both a risky enterprise and necessary to stem the decline in Alaska oil production.

New oil exploration and development in Alaska needs to compete globally for investment dollars.

The rates and progressivity structure of Alaska’s current tax regime provide a disincentive to attracting risk capital to the state as evidenced by declining production during times of high oil prices. Increased prices have resulted in substantial increases in oil production in other locations around the United States, but not in Alaska, and not because more oil is not available.

Increased investment through increased global competitiveness will enhance Alaska’s ability to fulfill its constitutional mandate to develop natural resources for the maximum benefit of the people.

Alaska’s remoteness from the markets, Arctic climate, high labor and logistical costs argue for a more competitive tax and regulatory structure.

Consumer Energy Alliance – Alaska is in favor of the Alaska State Legislature reviewing and approving revisions to the Alaska Tax Code that would improve the investment climate in Alaska.

Something is terribly wrong and I thank you for taking on the task, with the Governor, of coming up with useful changes.

Tuesday, January 29, 2013

A question of price; Economist argues for commodity pricing focus in Fairbanks energy options

Alan Bailey
Petroleum News

In a multi-year debate over how to enable residents of the city of Fairbanks in Alaska’s Interior to obtain affordable energy supplies, there is at least one point of general agreement: The city is hurting from the impact of high energy prices, thanks to a dependence on the use of expensive liquid fuels for the heating of buildings and for some power generation. But with various people and organizations exploring several future Fairbanks energy supply possibilities, there is a diversity of views on how to tackle the Fairbanks energy problem.

In the interests of clearing some of the ice fog surrounding the Fairbanks energy debate, Antony Scott, senior economist and policy advisor at the University of Alaska Fairbanks, has been working with the Alaska Center for Energy and Power on a study into the economics of Fairbanks energy options. And on Jan. 16 Scott presented some of the results of that study to the Alaska Senate Resources Committee.

Scott told the committee that the study results demonstrate the critical importance of the sales terms for fuel commodities, including pricing and the duration of pricing terms, in determining the cost of energy in Fairbanks. And, if Fairbanks is going to rely on natural gas as a primary energy source in the future, it will be particularly important to clarify from the outset the price terms for that gas, especially if people are looking for any price discounts for Alaska communities, he said.

“It’s critically important, I would urge, that those considerations get nailed down as soon as possible,” Scott told the committee. “There is nothing keeping people from negotiating gas sales contracts, for example, today.”

Energy options

The study has used publicly available information from projects targeting future Fairbanks energy supplies, and Scott thanked people involved in these projects for the time they had spent in helping the university with its work. The study evaluated the following options:

• trucking liquefied natural gas from the North Slope to Fairbanks;

• the construction of a small-diameter gas pipeline for the delivery of natural gas to Fairbanks from the North Slope;

• offloading Fairbanks gas from a gas pipeline from the North Slope to Southcentral Alaska, with three potential daily throughput capacities for that line: 250 million cubic feet, 500 million cubic feet and one billion cubic feet;

• obtaining Fairbanks gas through a spur line off a major gas sales line from the North Slope, with that sales line assumed to be delivering gas for export as liquefied natural gas to Asia through a port in Southcentral Alaska;

• shipping gas to Fairbanks through an in-state pipeline north from Beluga on the west side of the Cook Inlet;

• the manufacture of liquids fuels in the Alaska interior using a coal-to-liquids plant; and

• the use of electrical power for both heating and lighting in Fairbanks, with the power coming from a planned hydropower plant at Watana on the Susitna River.

• the use of electrical power generated on the North Slope and delivered to Fairbanks through a high voltage direct current transmission line.

Delivered cost

Scott said that the study compared these options on the basis of the potential delivered cost of energy to Fairbanks energy consumers, without considering other factors such as the resulting cash flow to the state. And the study included the two electrical power options for the purposes of comparison, while accepting that a full evaluation of the complexities of electricity supplies was beyond the study’s scope.

To ensure meaningful comparisons, the study used a consistent set of assumptions for project financing for all projects while applying the same sensitivity analysis to each project when assessing project uncertainties. For projects involving the use of North Slope natural gas the study assumed the purchase of untreated gas on the Slope, with the cost of removing impurities from the gas being part of the overall project costs.

For each energy option, the study derived potential energy costs in Fairbanks in 2023, a year that would post-date the completion of any of the projects under review.

Commodity pricing

While recognizing the importance of the cost of energy transportation, such as the shipping of gas through a pipeline, the study particularly focused on commodity pricing as a key driver for the cost of energy in Fairbanks, Scott said. And the study found that for the most part it is possible to index the commodity prices back to the price of North Slope crude oil, as sold in U.S. West Coast markets.

For example, much North Slope gas currently sold for use on the North Slope is priced using a formula agreed in the early 1990s between the state and the North Slope producers for the state’s royalty gas. That price formula sets the price per million British thermal units of untreated gas at about 4.6 percent of the oil price per barrel. And, although it may be possible to negotiate a better price than this, North Slope gas pricing is currently indexed to oil pricing in this way, Scott said.

The price of liquefied natural gas on the Asian market is also currently indexed to oil: Historically the per-million-Btu price in this market has been approximately 14.5 percent of the Alaska oil price, plus about 90 cents per Btu, he said. And although people have speculated about Asian prices softening in the future, any significant price softening would jeopardize the prospects for a major Alaska gas sales line.

The price of heating oil in Fairbanks, by comparison, has worked out on a Btu basis to be 22.5 percent of the oil price plus $4.20 per Btu.

One interesting outcome of the oil price indexing is the way in which the multipliers involved in the indexes can magnify the commodity price volatility as the oil price changes — that effect can lead to greatly different risk profiles for projects involving the use of energy resources from different places, Scott pointed out.

Range of prices

Plugging the commodity price models into financial models for each energy option enabled the plotting of potential Fairbanks energy prices for each option across a wide range of North Slope oil prices. One set of energy prices is based on an assumption that the projects would be entirely funded by private capital, and another set of energy prices is based on an assumption that the state would fully fund the projects. An energy option would show promise if its projected price for energy in Fairbanks appears lower that the projected price of heating oil.

The analysis assumed that the North Slope producers would sell gas at the most advantageous price, depending on market access for the gas, with no home-town discount for Alaska residents. And this assumption led to some intriguing outcomes for the 500 million cubic feet and 1 billion cubic feet options for an in-state gas pipeline, on the assumption that the scale of these pipelines would require the sale of at least some gas into the highly priced Asian liquefied natural gas market. At oil prices above about $70 per barrel that linkage to the Asian market could push the price of gas in Fairbanks higher than the price from a smaller scale pipeline, with the relatively high commodity price overwhelming any economies of scale to be gleaned from a relatively high pipeline throughput, Scott said.

Oil price uncertainty

Another intriguing result of the analysis indicates that if future oil prices turn out to be relatively low, the major gas sales line would be the only option to beat the cost of heating oil in Fairbanks, Scott said. And there is major uncertainty about future oil prices, given possible scenarios such as the worldwide implementation of shale oil technologies, he cautioned.

The analysis suggested that both options involving the use of electrical power for the heating of buildings in Fairbanks would prove substantially more expensive than any other energy option, including the use of heating oil.

Comparisons between the estimated cost of Fairbanks energy for privately funded versus state funded projects shows that state funding would substantially reduce the energy cost. That effect mainly results from the fact that all options tend to be highly capital intensive, with the state funding reducing the cost of the capital, Scott said. Under the assumption of state funding, all options start looking preferable to the use of heating oil. Those options involving the dedicated shipment of gas from the North Slope to Fairbanks have energy pricing estimates that are statistically indistinguishable, while options involving a linkage to the sale of liquefied natural gas in Asia have pricing that rapidly escalates with the oil price.

Ramp-up risk

An important issue that people would need to address when implementing a new energy source for Fairbanks is what Scott referred to as “ramp-up risk,” the risk associated with the timeframe involved in building the necessary new energy infrastructure. While there is no ramp-up risk for heating oil, a commodity that Fairbanks residents already widely use, an expansion of the natural gas distribution network, for example, might take a couple of years or so to accomplish. The cost of providing energy to consumers during, say, the first year of infrastructure construction would be much higher than after the customer base is fully subscribed, Scott said. And, high initial prices, perhaps above the cost of heating oil, coupled with conversion costs that customers would face, could deter customers from switching to the new fuel.

One particular problem in assessing the ramp-up risk associated with a Fairbanks project is a general lack of knowledge of just how much energy Fairbanks consumers use, Scott said. Whereas in a city like Anchorage it is possible to obtain data about how much gas people are consuming for the heating of buildings, there is no means of obtaining similar data for Fairbanks, where many people heat their houses using heating oil or firewood obtained from multiple sources.

Other complexities facing energy decision makers include the wide range of investment required for the different energy options, and the range of timeframes required for option implementation.

Coal-to-liquids technology presents some intriguing challenges. Because this technology involves fuel that is very similar to heating oil, coal-to-liquids would present no start-up risk. On the other hand, the fuel produced from coal would compete directly in the market with heating oil, thus making it is almost impossible to conceive of a state-sponsored project in which the artificial fuel would bring cost relief to fuel oil users, Scott said. Essentially, any undercutting of fuel oil prices by a state subsidized project would likely result in people buying the subsidized fuel and then reselling it at market rates, he said.

Read more:

Monday, January 28, 2013

Feige managing House Resources oil work; Committee co-chair working closely with Senate Resources chair to coordinate, avoid duplication in work on governor’s oil tax bill

Steve Quinn
For Petroleum News

House Rep. Eric Feige is among the handful of lawmakers who didn’t need to switch offices. That’s because he’s back at the helm as co-chair for the House Resources Committee. The major issues haven’t changed, just the numbers assigned to the bills.

House Bill 110 oil tax reform bill is now HB 72 and went directly to Feige’s committee. HB 9 in-state gas line bill is now HB 4 and also will go to Feige’s committee.

References to each remain strong, looking back and looking ahead.

One thing has changed. Rep. Dan Saddler will sit on the committee alongside Feige as co-chair.

He replaces Rep. Paul Seaton, who will remain on the committee.

Feige sat down with Petroleum News to share his thoughts on pending debates with the Legislature already two weeks under way.

Petroleum News: You’ve done this for two years. What have you learned first about the job and second about Alaska’s resources?

Feige: As far as the job, before I came down here, I thought there were some secret squirrel rules that you had to figure out when you got here. It’s not rocket science. It just takes a willingness to talk to people and listen to what other people have to say, then try to incorporate everyone’s needs, wants and desires into something that has the proper balance. We did that with coastal zone management during the last session, and I expect we’ll do that again on oil taxes and all the other issues that come forward. A couple of other pieces of legislation were actually created using that philosophy. We did it with HB 276, which we called the middle earth exploration bill, which got incorporated on the last night of the session into SB 23, which were the tax credits for six different zones throughout the state that had high potential and were also close to population centers. So we’re trying to help as many folks in the state as we can. The one good thing about me getting this particular seat right from the start, is that as a commercial pilot in Alaska, I’ve been all over the state and worked for most of the industries, be it oil on the North Slope, or be it places like Donlin Creek and other mines and exploration activities over the course of my flying career. A lot of these folks I see in committees I’ve had in my plane. The job gives me the opportunity to get my foot in the door on places I’ve previously flown over, but I’ve been inside them now. It gives you the opportunity to get into places and hear from more people in the industry. I’ve certainly got a pretty good appreciation for what it takes to make money in the resource business and what kind of statutes need to either be changed or be created to help further the resources industry.

Petroleum News: Now looking ahead, what are your legislative priorities?

Feige: Between myself and Dan Saddler, I’ll handle oil and gas issues. As the other bills come before us we’ll decide on a case-by-case basis who gets what bill. My biggest priority is the oil and gas bill introduced by the governor. I’m working pretty closely with the Senate Resources chair, Sen. Giessel, to coordinate our efforts so there is not a lot of duplication and we can run this thing in a well organized manner. There’s been a lot of talk and conversations between myself, the Senate chair and the administration. We are all working together on this to move the bill forward. I spent a lot of time talking to the industry going as far back as August, saying “guys we’ve had this debate now for the last two years, do you have any new ideas? What do you want to see in a tax bill?” HB 110 when it first came out, the critics were very quick to point out that the governor put this bill together with the help of the oil industry. Well they are the major entity who is going to be affected by it. Why the hell wouldn’t you talk to them? I don’t profess to know everything there is to know, but I am willing to hear what you have to say and if it can be worked into a bill, and if it’s fair to everybody and if it’s a wise move to the state of Alaska, then we certainly would be willing to consider it.

Petroleum News: One of the criticisms early on is there is a fear a bill will be rubber-stamped and pushed through.

Feige: Sure that’s a fear that anybody might have, but the way I look at is we’ve got a three-quarters majority in each body and it’s a Republican controlled majority in each body. I am operating under the assumption that we will pass an oil tax bill. My job is to make sure the oil tax bill is the best that it can be, that it does what we want it to do, that it’s a stable structure that is going to last a long time and be adaptable to changing conditions down the road. I’m certainly not looking to give away our resources. That’s not being fair to the people of the state. On the other hand, I’m going to be fair to the companies and let them make a reasonable profit. People have complained about a lack of a guarantee in HB 110. When we write the bill, the structure of the bill and the fact that you have to do something before you get a tax break, is the guarantee that people are looking for.

Petroleum News: What are your thoughts on HB 72?

Feige: I was involved in the development for it. There is nothing new that has been mentioned in any the statements of the governor or his people. It’s pretty much in line with what we put together the last three or four months. There is a lot better intellectual underpinning on this bill than perhaps there was on HB 110. I’ve seen a lot of the analysis that the consultant, Econ One, has generated. Some of the justifications they are using are certainly solid justifications for the statute changes they are looking to make.

Petroleum News: The other criticism was stripping progressivity outright. What are your thoughts on that?

Feige: One of the main problems of ACES (current tax structure), as the price of oil went up, the profit margin didn’t necessarily go up, either. It was taking away the upside from the industry as a whole. OK, you can say we are still allowing them to make a profit, but the problem is other oil provinces that we’re competing with for investment don’t have that limitation, so it puts us at a terrible competitive disadvantage to those other regions of the world that we compete with for investment dollars. You’re taking away progressivity, but let’s not forget that we’re also taking out capital credits. It’s roughly a wash. You’re cutting back a little more revenue than you are cutting back on expenses.

One of the things brought out in the analysis with the current tax system was that if everything we want to happen — Point Thomson, Brooks Range moving forward, Pioneer moving forward, Great Bear especially moving forward — all those projects that we want to happen so we get more oil in the pipeline, those all come at a cost up front to the state with those capital credits.

So the state was having to give away a lot right up front. The time to get that money back, well, we were looking at a pretty significant financial hit to the state. With the new bill not being as generous up front, but we’re also being more generous on the backside by taking away progressivity. The other advantage of taking away progressivity is that you completely eliminate the whole decoupling issue between oil and gas. That was another significant characteristic of ACES. If we did go to a major gas sale for export pipe, the state would take another hit on the treasury, just because of the way our tax law was structured. So, getting rid of progressivity is an advantage to the state and beneficial to the Alaskan economy.

Petroleum News: You also have HB 4 before you at some point. You were not in favor of HB 9 last year. Will you be handling this bill?

Feige: Dan Saddler will be handling this HB 4.

Petroleum News: What are your thoughts on the gas pipeline situation right now, be it the in-state line or the export project?

Feige: You’ve got two projects that are trying to move forward. On the one hand, the bullet line is there and it spurs on the producers to say we better get going on this export line if we are going to do it, or the bullet line is going to go forward and take away the economic advantages of the bigger line. On the other hand, the folks who want to build the big line specifically the folks from Asia — the Koreans and the Japanese who have already approached us about building, definitely have interest in our gas. They are in favor of a bigger line. I understand they are pretty much looking at Valdez as the terminus for that export line. Certainly that would make the folks in my district pretty happy. It’s deepwater; it’s ice-free; you’ve got the maritime surveillance infrastructure already in place.

There are a lot of advantages to it. The depth of the water is particularly critical. Parts of Cook Inlet, around Nikiski, is only 40 feet deep, if you look at the chart. Looking at the depth sounders around Valdez arm this summer, 750 feet. Plenty of room. The bigger the LNG tanker you can bring in to export, the better the economics of the project are going to be because you are going to lower the unit cost for transportation. I’m hopeful the companies will eventually end up running that big line to Valdez.

Petroleum News: There are also permitting issues you’ll be addressing this session. What do you feel needs to be done? Feige: This is something that’s been looked at for two years over at DNR. They are looking to the future of certain activities. They are looking at how things are done presently. A lot of the regulations go back many years. I think the changes are going to acknowledge how at this point we do certain things in a pretty standard way.

It’s a combination of acknowledging the current reality and the current practices and also looking forward to the future, but also saying if we change our tax rates, we are going to get a whole bunch of new activity. That means we are going to get a whole bunch of new permit applications flooding our offices.

We need to look at how can we get ahead of that so that we don’t need to increase the number of people processing all of this and do it so we don’t increase our operating budget. It all wraps around keeping government at a level that still fills its responsibilities to its people and stewardship to the state’s resources.

It’s a matter of being out front of the changes we foresee coming and making sure we don’t get behind. Petroleum News: Getting back to HB 72 for a final question, who between you and the Senate Resources will move forward first?

Feige: Right now the Senate has sent the bill to the TAPS Throughput Committee. For them, it’s essentially a third committee of referral. When it comes out of TAPS Throughput, it’s going to go to Senate Resources. At that time we’ll drop it in House Resources. The Senate and House (Resource) committees will run that bill parallel. At some point, we may diverge, I don’t know. We’ll have to see how it goes, but our intent is to start hearings on that bill on the same day.

Keep in mind, it’s not like the House is sitting idle on this bill. At this point we are analyzing it. We need to figure out what we need to ask the consultants. We are using the time the Senate has the bill to prepare for our own hearings on the bill. We’ve got a fairly experienced committee on House Resources.

We’ve got Paul Seaton, Craig Johnson, Mike Hawker, Kurt Olson and Peggy Wilson from the majority. In the minority, you’ve got Chris Tuck and Geran Tarr. Johnson, Hawker, Olson and Seaton, those guys have been with the Legislature a significant amount of time. Rep. Wilson has an awful lot of experience on the Resources committee. Seaton and Johnson have been chairs on the Resource Committee. Hawker has been chair of the Finance Committee.

A lot of these guys were here for PPT, ACES, for AGIA — all the debates that we’ve had in the Legislature for the past six to eight years. They bring a lot to the table. I don’t need to explain to them what DNR does as a department. We are going to be able to address the issues. They know the history. They know what happened with previous legislative fights. With that expertise, we’ve got the best shot to come up with a bill that’s going to serve Alaska very well.

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About Alaska Contract Staffing

Timeline clarified for Susitna-Watana project studies

Elwood Brehmer
Alaska Journal of Commerce

The Alaska Energy Authority and the Federal Energy Regulatory Commission may have cleared a once muddied near-term timeline for the Susitna-Watana hydropower project. At the same time, the cost of the project has risen by a half-billion dollars.

A Jan. 17 letter from the commission to AEA agrees to a compromise with the Energy Authority and moves up determination on 13 of the 58 studies detailed in AEA’s revised study plan to April 1. AEA filed its revised, 58-study plan with FERC on Dec. 14.

On Dec. 31 FERC sent a letter to AEA stating the 13 studies in question would not be ruled upon until May 14, putting summer work in jeopardy.

The latest letter is a response to a Jan. 7 appeal by AEA Lead Project Manager Wayne Dyok to make a final determination on all studies by Feb. 1. While the Commission rejected Dyok’s request in part, it is expected to give its determination on 45 of the study proposals on Feb. 1 and wrote that it understands AEA’s concern over work delays, thus agreeing to the April 1 deadline.

State Republican leaders lauded FERC for the decision in a Jan. 21 press release:

“This revised study plan provides a balance between the need for power and environmental resources and will provide sufficient information to file for a FERC license in 2015 and to bring the project online in 2024. Alaska, and especially Fairbanks, needs long-term and stable sources of energy. Susitna-Watana Hydro is a long-term power solution for the state,” Sen. John Coghill, R-North Pole, said in the release.

The current project timeline has construction beginning in 2017 and the project completed in 2024.

AEA revealed at its January board meeting the latest cost estimate for the Susitna-Watana Hydro project at nearly $5.2 billion, up from an August 2012 estimate of $4.7 billion.

At the meeting, Dyok said the key issues with the 13 studies are not with studies themselves but with some of the detailed biological aspects of the fisheries studies. If the work is done without approval it could mean redundancy in work over the coming years, he said.

“If we can’t do the summer fieldwork then you could be looking at as much as a year’s delay. That’s why it’s important to have a decision by the first of April,” Dyok said.

While there is no outward concern over study approval, work can move ahead as planned only if FERC approves all 58 studies.

AEA has until March 1 to file additional information requested by FERC on the 13 studies in question.

The revised study plan included not only study proposals, but public comment letters and responses to the letters as well. Dyok called the approximately 3,500-page plan “unprecedented” in its detail.

“I have done this work in 25 different states and this is the most formidable study plan I have ever been associated with,” Dyok said. “It’s a pretty voluminous document.”

Nick Szymoniak, a project economist for AEA, said roughly a third of the increased cost projection is simply due to inflation.

“Just going from a 2012 dollar estimate to a 2013 dollar estimate added $143 million to it,” Szymoniak said.

In his presentation, Szymoniak broke down the rest of the cost increase. He said additional costs in project licensing and power transmission added a total of $112 million and new construction costs added $73 million.

Szymoniak said the new estimate tacked on $102 million to the projected cost because it provides a more accurate project assessment. The August estimate settled on $4.7 billion as likely figure, but gave an estimate range from $3.3 billion to $7.1 billion. The recent estimate narrowed the range to $3.7 to $6.4 billion; with a 90 percent probability the final cost would fall between $4.4 and $5.8 billion.

If constructed, the dam would form a roughly 40-mile-long reservoir on the upper Susitna River beginning 87 miles upstream from Talkeetna and 22 miles upstream from Devils Canyon, which AEA calls a “natural fish barrier.”

The dam would generate 2.8 million megawatts of electricity — about half of Alaska’s Railbelt power — and prevent about 1.3 million tons of carbon dioxide from entering the atmosphere versus fossil fuel power generation annually, according to AEA figures.

AEA estimates around 1,000 jobs would be generated during construction.

AEA is working on the project as if its studies can all begin in spring. Agreements with the Department of Fish and Game are being finalized for summer study work and contracts with consultants are being worked out, Dyok said.

Studies on ice conditions and winter recreation near the reservoir area are being done now, he said.

After adding information gathered in 2012 on the site, Dyok said the 750-foot dam proposed in August has been reduced to 735 feet because testers hit bedrock 15 feet sooner than expected. Also, a preliminary quarry site near the project was found to be suitable for drawing material during construction.

Dyok said seismic studies are ongoing but 2012 work confirmed no faults on site. A resource procurement plan for design and construction is expected in a few months and AEA hopes to complete a design feasibility report in 2013.

Read more:

About Alaska Contract Staffing

Monday, January 21, 2013

Conoco: $1B in 2013; Budget reflects spending on Alpine satellite and Chukchi, not on legacy fields

Eric Lidji
For Petroleum News

ConocoPhillips plans to spend “about 1 billion” in Alaska this year, ConocoPhillips Alaska President Trond-Erik Johansen told an audience in Anchorage recently.

The projection is a slight increase over the 2012 budget, but Johansen warned against viewing the bump as sign ConocoPhillips suddenly approves of the investment climate in Alaska, after years of complaining about its tax burden. “When you look at the base development speed and pace in the legacy fields, it’s the same (budget) as 2006,” he said Jan. 11 at the Alaska Support Industry Alliance’s annual conference, Meet Alaska.

The date is not an arbitrary one, Johansen noted. In 2006, the state passed the Petroleum Profits Tax, which it revised in 2007 with Alaska’s Clear and Equitable Share. The major oil companies have been pushing lawmakers for years to change the current system.

The increase, according to Johansen, will primarily accommodate construction of the CD-5 satellite of the Alpine field and preparations for Chukchi Sea drilling 2014.

Although ConocoPhillips’ budget estimates are often higher or lower than its actual spending, the figures provide a sense of what the company expects from the year ahead.

Fluctuation in spending

ConocoPhillips’ spending in Alaska has fluctuated greatly from year to year: $746 million in 2005, $820 million in 2006, $666 million in 2007, $1.4 billion in 2008, $810 million in 2009, $730 million in 2010 and $775 million in 2011. The company budgeted $900 million for Alaska in 2012, but its actual spending figures are not yet available.

Because ConocoPhillips does not break down spending by exploration and development, it is difficult to gauge the “base development speed and pace in the legacy fields.” The peak in 2008 came largely from ConocoPhillips’ bids in a record breaking federal lease sale in the Chukchi Sea, while the decline in 2010 and 2011 is likely the result of ConocoPhillips taking a break from exploration drilling after years of high activity.

Johansen did not say whether the budget included money for two wells in the National Petroleum Reserve-Alaska that ConocoPhillips recently asked for permission to drill.

In December, the U.S. Bureau of Land Management gave the company permits to drill the Cassin No. 1 and Cassin No. 6 wells in the Bear Tooth unit. While the permits are valid until December 2014 and January 2015, respectively, ConocoPhillips must drill at least one well in the unit by this June to meet its work commitments or get an extension.

Pushing the legacy fields

What is irrefutable is the declining throughput volume on the trans-Alaska oil pipeline, and while Johansen said the days of 2 million barrels per day are “probably gone,” he believes legacy fields are the only way to stem the decline. “If we want more oil coming through the pipeline, we need to work more on Prudhoe Bay, Kuparuk and Alpine.”

To get the estimated 4.5 billion barrels remaining in those fields, though, requires technology, which requires investment, which requires a better fiscal system, he said.

To highlight his point that North Slope oil is increasingly elusive, Johansen pointed to Alpine. When a ConocoPhillips predecessor brought CD-1 online in 2000, it spent $1 billion in return for 80,000 barrels per day, he said. Now ConocoPhillips plans to spend $1 billion on CD-5 in return for 18,000 bpd. “If you go back to 2000, when we did Alpine, guess what? The tax system was much more favorable than it is today, and you got five times the production for the investment you spent. So let’s get real,” he said.

While ConocoPhillips may have gotten five times the oil for its money in 2000 that it expects to get in 2013 — and the actual figure is closer to four and a half times — the oil is worth much more today. The delivered price for Alaska oil hovered between $20 and $30 per barrel in 2000, but the state expects it to be around $108 in the coming year.

Of course, oil prices are highly internationally.

Lure of the Lower 48

“The bizarre thing in Alaska is: the higher to oil price gets, the less we get. So, of course, when the prices go up we’d rather invest somewhere else,” Johansen said. And right now, “somewhere else” is the Lower 48, particularly the Bakken and Eagle Ford plays.

In two years, ConocoPhillips went from producing nothing at the two plays to some 125,000 bpd, according to Johansen. “That’s a revolution. It’s fantastic news for the United States of America,” he said. “Not so good news for Alaska.” While the growth of unconventional oil is often seen as a technological advancement, Johansen said the plays, which are largely on private land, also have better fiscal terms than Alaska.

With the Alaska Legislature gaveling in for its regular session on Jan. 15, the investment climate is sure to be a primary debate among lawmakers once again, especially given that Gov. Sean Parnell recently released a new proposal for revising the tax code and that ConocoPhillips will release its annual earnings figures at the end of January. As it has said in the past, ConocoPhillips believes it can increase production under different terms.

“We are really committed to Alaska, and we would like to do more here,” Johansen said.

Saturday, January 19, 2013

Friday, January 18, 2013

Hilcorp acquisition of Marathon’s Cook Inlet properties cleared by state judge

Tim Bradner
Alaska Journal of Commerce

An Alaska superior court judge in Anchorage approved a Consent Decree Jan. 17 negotiated by state attorneys with Hilcorp Energy LLC, clearing the last hurdle for Hilcorp to acquire Marathon Oil's Cook Inlet producing assets.

Judge Erin Marston gave his approval from the bench following a hearing, state Assistant Attorney General Ed Sniffen said.

Hilcorp had agreed to purchase Marathon's properties, most gas producing, earlier this year for $375 million, but a Federal Trade Commission anti-trust investigation and parallel state investigation put the final transfer on hold. The FTC and state attorneys were concerned because Hilcorp would own 70 percent of the gas supplied to regional utilities, between the former Chevron properties Hilcorp now owns and the Marathon properties

After a lengthy investigation the FTC ultimately turned the matter over to the state, which then negotiated the Consent Decree with Hilcorp in early November. The agreement requires Hilcorp to cap prices for gas sold to utilities and industrial customers at $6.60 per thousand cubic feet, with a 4 percent annual escalator allowed, for five years. The escalator from a $6.60 base price in early 2013 would have the gas cap set at $7.72 per mcf after five years, in 2017, Sniffen said in a November interview.

Hilcorp is also not allowed to sell gas for export, as liquefied natural gas, unless the state attorney general gives an approval. That would not come unless regional needs are met, Sniffen said. The requirement for local needs to be met includes utilities and industrial customers as well as utilities outside Southcentral Alaska who may purchase Cook Inlet gas, he said.

The approval by the court means the acquisition can now go through and the state expects that to happen quickly. "They're anxious to get this wrapped up as quickly as possible,” Sniffen said. “We hope this clears the way for Hilcorp to do the things they have promised to do," in terms of new investments in Cook Inlet's aging oil and gas fields, he said.

In a November interview Sniffen said negotiating the Consent Decree was “a very difficult balancing act for us because we want to protect the local consumers and at the same time give Hilcorp enough of a price incentive to explore for gas,” Sniffen said. The provision prohibiting Hilcorp from selling gas for export as LNG until local utility needs are met also applies to sales to companies “who intend to resell the gas for LNG export,” Sniffen said.

Read more:

Production focus; Governor proposes end of progressivity, changes in capital, exploration credits

Kristen Nelson
Petroleum News

As expected, Alaska Gov. Sean Parnell has submitted a production tax bill to the Alaska Legislature. The proposal, focused on increasing production on the North Slope, eliminates progressivity to encourage investment and makes substantial changes in the credits currently offered — eliminating some and making others redeemable only against production.

Department of Revenue scenarios in the fiscal note accompanying the bill indicate that at currently forecast production rates and at oil prices of $100 a barrel and above the state would see reduced revenues from the elimination of progressivity, which gives the state an increasingly larger portion of the net value of oil as oil prices rise.

Revenue’s fall forecast is based on $108.67 per barrel for fiscal year 2013, and $109.61 per barrel for FY 2014, with prices above $100 a barrel forecast through 2022.

The results from the tax changes would be different at lower oil prices.

At $90 a barrel state general fund revenues would increase from fiscal years 2014 through 2018 and be flat in FY 2019.

Revenue ran scenarios with increased production and the state does better at $90 a barrel with more production; potential revenue losses at increased volumes and at higher oil prices vary.

While at currently forecast production state revenues drop with the elimination of progressivity, the result from limitation of credits for qualified capital expenditures on the North Slope is positive to the state, ranging from a low of $300 million in the state’s favor in FY 2014 to a high of $700 million in the state’s favor in FY 2015.

At prices and production in Revenue’s fall 2012 fall forecast, the total fiscal impact to the state is negative, ranging from a low of $550 million in FY 2015 to a high of $1.025 billion in FY 2017.

Downside protection for Alaska

ACES, Alaska’s Clear and Equitable Share, the state’s current production tax, was enacted in 2007; it raised taxes compared to the previous tax increase, the Petroleum Profits Tax, passed in 2006.

Credits offered under ACES were intended to encourage investment in the state, while the progressivity feature was intended to give the state a larger share of profits when oil prices were high. The “high” prices evaluated when ACES was discussed in 2007 were lower than prices have been in recent years.

Parnell summarized the new proposal in his Jan. 16 State of the State address, citing dropping production and remaining oil on Alaska’s North Slope and telling legislators: “Our problem is not below the ground. Our problem is above the ground. One recent analysis shows a company will make substantially more, at today’s oil prices, by investing in the Lower 48 rather than in Alaska.”

The bill proposes “eliminating progressivity, and rebalancing capital tax credit payments” to create “a simpler 25 percent tax,” he said.

New production encouraged

In his transmittal letter Parnell told legislators tax changes are needed because of declining production.

The current tax system does not “attract new investment for more production,” the governor said, but takes more profit from investors at high oil prices than competing jurisdictions. Its “generous tax credits for capital expenditures support company spending now, but on spending not necessarily targeted for new production,” exposing the state to “the short-term risk of writing large checks from the treasury for those credits with no corresponding increase in production.”

The governor said his proposal maintains a 25 percent base tax rate with a 20 percent gross revenue exclusion for new oil while eliminating progressivity and qualified capital expenditure credits for the North Slope.

The governor said the bill “targets new Alaska production rather than just company spending, thus unlocking more of Alaskans’ oil for more Alaskan private sector and public sector opportunities.”

The current 20 percent tax credit for qualified capital expenditures on the North Slope is eliminated effective Dec. 31, 2013.

The 25 percent tax credit for a carried-forward annual loss would be amended by “limiting the transferability and monetization of the tax credit,” encouraging “investment aimed at production by requiring a producer or explorer to carry the credit forward to offset future tax liabilities.” Currently this credit can be redeemed through the state or sold to companies with production tax bills.

Gross revenue exclusion

Revenue’s fiscal note says the bill includes a gross revenue exclusion for new production — from leases or properties on the North Slope that were not within a unit on Jan. 1, 2003, or from participating areas established after Dec. 31, 2011, for properties in a unit formed before Jan. 1, 2003.

Revenue said that because the provision is intended to incentivize future production, the revenue impact on the current production forecast is minimal.

The current small producer tax credit, which is nontransferable, is extended from 2016 to the later of 2022 or the ninth calendar year after first commercial production.

The Department of Natural Resources said in a fiscal note that with increased production there would be an increase in royalty revenues, calling the fiscal impact on royalty revenue “an indeterminate positive.”

Changes do not apply to Cook Inlet or Interior production.

The legislation was assigned to committees Jan. 16: House Bill 72 to the Resources and Finance committees; Senate Bill 21 to the newly formed Senate Special Committee on TAPS Throughput and to the Resource and Finance committees.

Read more:

Thursday, January 17, 2013

Southcentral utilities leaning toward the use of diesel fuel

—Alan Bailey

The Southcentral Alaska utilities are considering the use of diesel fuel for some power generation, in the event of a predicted utility natural gas supply shortage around 2014-15, Robert Gibb, associate director of Navigant Consulting, told the Mayor’s Energy Task Force in Anchorage on Jan. 9. Gibb is helping the utilities and the planned Donlin Creek gold mine evaluate the options for dealing with the pending Southcentral gas supply crisis.

The utilities have been investigating the potential import of liquefied natural gas or compressed natural gas into Southcentral to cover the gas shortfall. But with some significant uncertainties associated with these options, the utilities now tend to favor the diesel fuel option as a safe means of dealing with the problem in the short term, despite the fuel’s high cost. The utilities will also seek a cost-effective long-term solution, Gibb said.

Short- and long-term

“What we’ve done on this project very recently is we’ve broken it into two pieces and we’ve said there’s a short-term … and then there’s a long-term shortage, and we’ve recognized that they don’t need to both have the same solution,” Gibb said. A reliable and certain solution is necessary for the short term, even although that solution may not be the cheapest option.

The use of diesel fuel for power generation would seem a low-risk means of ensuring that the lights stay on and buildings stay heated, as gas supplies from the Cook Inlet basin decline below demand levels.

“From a technology standpoint it’s not very challenging. From a sourcing standpoint it’s pretty realistic. And from a cost standpoint it’s fairly well known,” Gibb said in commenting that diesel is becoming the leading short-term contender.

And, although on an energy equivalent basis diesel may cost five times as much as gas, diesel power generation would, at least initially, represent a relatively small proportion of total generation, the diesel cost being diluted by the lower cost of power generated from gas.

Work to do

However, quite a bit of work remains to be done to clarify all the issues involved in diesel usage.

Lee Thibert, senior vice president of Chugach Electric Association, told Petroleum News that neither the Beluga power station on the west side of Cook Inlet nor the new gas-fired power station being completed in south Anchorage can currently run on liquid fuel. If the utilities move ahead with the diesel fuel option, one of the power plants in the new south Anchorage facility would probably be converted for liquid fuel use. Municipal Light & Power can already use diesel in its Anchorage power station. Golden Valley Electric Association in Fairbanks also has diesel generation capacity, with the possibility of shipping electrical power south on an electricity intertie that connects with Anchorage.

All options open

Looking into the longer term, which Gibb characterized as 15 years into the future, the utilities are still considering all possible options, including the import of LNG or CNG by ship from out of state. The longer-term arrangements would take over from the short-term solution, once those longer-term arrangements are in place. And in evaluating the long-term solutions, the utilities are assuming that the gas shortage will level out after 2020 as new Cook Inlet gas fields come on line following the resurgence of interest in Cook Inlet exploration.

Asked whether the implementation of a short-term solution to the gas shortage could provide a couple of years of breathing space, to see whether new gas fields in the Cook Inlet basin would bring on line sufficient gas to avert a long-term gas supply shortage, Gibb said that unfortunately an early decision will be needed for an option to import gas.

Any import option will require a commitment to the building of the necessary ships, with a two-year window involved in the ship construction, he said. And, with production decline rates from the basin at about 20 percent per year, drilling out of the supply shortage would be tough.

“The (gas production) declines that we’re seeing here … there’s a serious question … as to whether you can run fast enough,” Gibb said. “If you don’t find that mother-lode field that is all of a sudden just an heroic solution, it’s very, very difficult to look at a means whereby you can drill your way out of this problem.”

North Slope gas

The possibility of trucking LNG from the North Slope is on the table, but this option would require hundreds of LNG trucks to travel down the Haul Road from the Slope every day, with gas supplies coming to a halt if for some reason the road had to be closed, and with the possibility of weather causing delays in truck movements. “Logistically, it may be very, very challenging,” Gibb said.

Gibb also addressed the question of an in-state gas line from the North Slope as a long-term gas supply solution for Southcentral, saying that at the moment the pipeline option is uncertain. If the pipeline is built, it would be necessary to look at the comparative economics of obtaining gas by this means, with the possibility of incurring the cost of backing out of the gas import arrangements, or extending the costly short-term power generation solution until the pipeline is completed.

Western Canada

And, whether in the form of LNG or CNG, imported gas would likely come from western Canada, with a purchase price linked to North American gas markets rather than to the price of LNG in, say, Japan. At present there is no practical source for the LNG or CNG from the West Coast of the United States, and shipping the product from a U.S. port would involve complications around the Jones Act, the statute that requires the use of U.S. ships for freighting between U.S. ports.

The utilities had been veering towards the import of CNG as an apparently simpler and more cost effective solution than LNG, although both of these long-term import solutions require dedicated ships. In fact, the utilities are close to determining the best shipping arrangement for the CNG option, Gibb said.


But the utilities have realized that they need to take a closer look at LNG — one LNG provider has what appears to be almost a custom fit to what is needed, he said. In fact there is an LNG option that presents the possibility of a short-term solution, he said. And there are technical challenges with CNG, including the construction of some necessary equipment.

“We do have a CNG answer, but there’s not a reason to move forward with it yet,” Gibb. “LNG is beginning to look more and more like, at least, a competitive solution.”

The facilities for importing the CNG or LNG would probably be located at the port of Nikiski on the Kenai Peninsula, to take advantage of the existing dock infrastructure there. But, unlike the use of diesel fuel for power generation, there would be a significant permitting requirement. And either import option, because it would involve the movement of gas across the U.S. border, would require a presidential permit, a source of some project uncertainty, Gibb said.

Read more:

Wednesday, January 16, 2013

Alaskans we are all in this together

Deborah Brollini
Alaskan Energy Dudes and Divas

I was so excited to watch the pomp and circumstance of the gaveling in of the Alaska State Legislature yesterday. I was beaming with pride watching my friends take their oaths of office, and their willingness to take on the monumental task of moving our state forward. The decisions made these 90 days will not be easy, the decisions will be tough, and hard to swallow. But, during both House and Senate floor speeches and during press availability there was a consistent message of “we are all in this together.” I believe these lawmakers to be great Alaskans who will look at Alaska as a whole, and will work for solutions rather than being right for the sake of party, or ideology. I do want to stress that policy is a public process and that all Alaskans are invited to help make these tough policy decisions.

I do follow public policy, and my issues are finding solutions to my high energy costs, oil tax reform, Alaska Native people, and Covenant House. I have learned a lot over the years regarding public policy and the process of passing legislation. I was fortunate to have a legislative staffer sit me down for a reality check conversation. I learned that I must think of the end result of my policy wants, and to not to get married to legislation. No matter how bad I want legislation, the legislation passed will be imperfect, and I will never get everything I want, and being married to legislation is not healthy for me because politics is fickle.

A lot of lessons learned that have helped me understand that dragging the Governor, and legislators kicking and screaming to my policy wants is not in the best interest of the state. Alaska’s future is bright, and there is so much opportunity within our reach if we think long-term, balance all of the state's needs, and unite behind the goal of putting Alaska first.

It is possible to move our state forward this legislative session so all Alaskans win, and we can do this together as an all-Alaskan family.

Tuesday, January 15, 2013

GUEST COMMENTARY: Balance must be restored to Alaska’s oil tax system

Bryan Butcher, DOR Commissioner
Dan Sullivan, DNR Commissioner
Alaska Journal of Commerce

Oil production is the cornerstone of Alaska’s economic foundation and an engine of opportunity for Alaskans. As Commissioners of the Departments of Natural Resources and Revenue, we are charged with managing Alaska’s resources, finances and oil wealth for the maximum benefit of current and future Alaskans.

When it comes to reforming Alaska’s oil tax system, we are guided by Alaska’s Constitution and directed by Gov. Sean Parnell’s guiding principles, which he has recently underscored: Oil taxes must be fair to Alaskans, must encourage new production, must be simple so they restore balance to the system, and must be durable for the long term.

With these core principles in mind, our departments have extensively reviewed the current oil and gas tax system — taking into account the analysis we received from a broad range of experts.

Alaska is blessed with world-class resources on the North Slope. We have billions of barrels of conventional resources that remain undiscovered, and billions more in unconventional resources that can sustain our economy for generations.

Unfortunately, we are not the only resource opportunity available. There is great competition for investment dollars to develop resources around the globe, and while oil provinces are booming in North America and elsewhere, Alaska has been needlessly losing out.

As we look toward new oil development in Alaska, we see that the current system creates a dilemma for the State. Since the State receives oil tax revenue from production, but awards tax credits based on a company’s spending, we incur significant costs to the treasury as projects are developed.

Basically, the more companies spend, the more taxpayers must foot the bill. It seems counterintuitive, but in the near-term, significant new developments could lead to budget deficits depending on the price of oil.

Under current law, in the next fiscal year, the state will pay out more than $1 billion in credits to either reduce a tax liability or to directly pay companies that are not producing oil. These payments negate two-thirds of the $1.54 billion the state will receive through the current oil and gas production tax’s “progressivity” rate.

Meanwhile, companies that commit to producing new oil reserves in Alaska can expect to make a little more than $4 per barrel. At the same time, they can go to our competitors and make $7 to $9 per barrel.

This is a key reason Alaska is considered to be in extreme harvest mode. We are not seeing the investment and development activity that we need to produce greater volumes of oil and greater economic opportunity. The International Energy Administration recently predicted the United States will be the world’s largest oil producer by 2020. Alaska should be leading this domestic energy production boom, given its world-class hydrocarbon basin, but instead we are falling behind North Dakota, Texas, and soon, California.

Clearly, our complex tax system and uncompetitive tax rate is a major disincentive. The portion of the tax rate called “progressivity” is calculated monthly and varies significantly, making it difficult for any company to plan around or predict. Progressivity is primarily based on the price of oil. If oil prices drop, the revenue from progressivity declines but the taxpayer bill for credits remains the same. We can foresee a potential scenario, under our current fiscal system, where we seriously deplete the State treasury in the near term, while maintaining our downward production spiral.

These elements of our current tax system create an imbalance that exposes the State to excessive financial risks. Our current system rewards private spending rather than new production.

Does that mean that we should give up on exploration tax incentives? No. But we must restore balance — reducing the risks to our treasury and refocusing on effective incentives that secure new production.

We also must enact tax reform that focuses on growing oil production, economic activity and jobs.

With targeted reforms to the current system based on identified problems, we are confident that Alaska can increase its revenue stream and revitalize our oil and gas industry to create lasting opportunity for generations to come.

Read more: Alaska Journal of Commerce

Sunday, January 13, 2013

Change of plans; ‘Sour gas’ forces ExxonMobil to modify well array in Point Thomson field

Wesley Loy
For Petroleum News

ExxonMobil is making a significant change to its planned Point Thomson project due to an unexpected “sour gas” problem involving the two wells already drilled at the remote Alaska North Slope field.

In 2010, the company finished drilling two wells on Point Thomson’s central pad, the PTU-15 and the PTU-16. One well was to be a producer and the other an injector for the natural gas condensate project.

But during well testing, ExxonMobil encountered higher levels of hydrogen sulfide than expected.

Hydrogen sulfide, or H2S, is a sour or acidic gas that can be very damaging.

The PTU-15 and PTU-16 well materials were not designed for “sour service” and will need casing mitigation, ExxonMobil has told state oil and gas industry regulators.

Ultimately, both wells will be used as injectors, and a third well will be drilled as the initial Point Thomson producer, the company said.

Schedule remains intact

Kim Jordan, an ExxonMobil spokeswoman in Houston, told Petroleum News on Jan. 9 that the sour gas issue “does not impact the overall schedule” for the Point Thomson development.

Likewise, state Natural Resources Commissioner Dan Sullivan said work appears to be proceeding according to plan.

Under a legal settlement with the state, ExxonMobil has pledged to commence initial production at Point Thomson by the winter of 2015-16, or no later than May 1, 2016.

“In none of our briefings with Exxon has there been even the hint of that important date not being abided by,” Sullivan said in a Jan. 9 interview.

ExxonMobil detailed the sour gas problem during a recent briefing of officials with the Alaska Oil and Gas Conservation Commission and the Department of Natural Resources.

DNR provided a copy of ExxonMobil’s PowerPoint presentation from the Oct. 30 briefing to Petroleum News. The sour gas issue previously was not known publicly.

Long struggle

The Point Thomson unit is on state-owned acreage along the Beaufort Sea coastline, about 60 miles east of Prudhoe Bay and just west of the Arctic National Wildlife Refuge.

The field is believed to contain hugely valuable reserves of natural gas, estimated at 8 trillion cubic feet. ExxonMobil says it also contains an estimated 200 million barrels of condensate, a light liquid hydrocarbon associated with natural gas.

Despite its riches, the field has yet to produce any gas or oil since its discovery in the 1970s. ExxonMobil and its partners in the field have cited the lack of a North Slope natural gas pipeline, as well as the field’s remote location and technical challenges, as reasons for the lack of development.

Beginning in 2005, state officials began to take increasingly aggressive steps to try to force ExxonMobil to produce at Point Thomson. A court conflict soon developed as the oil companies sought to block the state’s attempts to dissolve the unit and invalidate the underlying leases.

Under pressure, ExxonMobil drilled a pair of wells at Point Thomson. Finally, on March 29, 2012, the state and the oil companies reached a settlement agreement that resolved all the legal issues and laid out a schedule for the gradual development of the field.

While the settlement does not guarantee production, ExxonMobil and its partners will lose acreage if they don’t move forward with development, state officials say.

The other major stakeholders in Point Thomson are BP and ConocoPhillips.

How project will work

The first development phase, known as the “initial production system,” will be designed to produce 10,000 barrels per day of condensate to start.

Major field construction has not yet occurred at Point Thomson, but is expected to begin ramping up this winter. The project will involve establishing central, west and east pads; infield roads and gathering lines; worker housing and a barge dock; and a 22-mile export pipeline to tie Point Thomson production into the existing North Slope oil transportation network.

ExxonMobil has acquired the major authorizations, including a federal wetlands permit and a state certificate of public convenience and necessity for the pipeline.

The condensate production involves producer and injector wells “cycling” gas in tandem. The producer well brings wet gas to the surface. The gas goes into processing facilities for collection of the condensate. The injector well then shoots the residual dry gas back underground.

At the Oct. 30 briefing, ExxonMobil told state officials the potential consequences of the high H2S levels in the PTU-15 and PTU-16 wells. The company said testing determined that “under a shut-in condition with a well tubing failure, the well casing could experience rapid corrosion.”

The wells are “suspended in a safe condition,” and were inspected in July 2012, ExxonMobil said.

Going forward, the company plans to use both wells as injectors after installation of liners.

Jordan, the ExxonMobil spokeswoman, further explained in an email: “The liners, with reduced internal diameters, required the use of smaller production tubing which reduced the flow capability of both wells. For this reason, both the PTU-15 and PTU-16 will be used as injectors.”

ExxonMobil has told state officials it intends to accelerate the planned drilling of another well at the west pad. This well will be the producer, able to provide “the required flow rate to achieve the design rate level agreed in the Settlement Agreement,” Jordan’s email said.

The agreement calls for cycling 200 million cubic feet per day of gas.

The west pad well will be tied into the central pad, where the gas processing and compression facilities will be located. The west and central pads are about four miles apart.

Saturday, January 12, 2013

Alaska is destined for greatness

Deborah Brollini
Alaska Energy Dudes and Divas

It has been years since I’ve been excited for a legislative session. In the past I’ve been cautionary and reluctant to be optimistic because of dysfunctional past legislatures. However, today I have a skip in my step and I’m ready for the future. It was a painful journey, and it took a lot of hard work, and biting my tongue to get here. Alaskans have so much to look forward to and I cannot wait until the legislature gavels in.

Alaska has been stagnant long enough, and it looks promising that both legislative bodies are ready to get to work. I’m excited that the Senate has organized with an “Alaska first” agenda that has a long-term focus, and focused on oil tax reform, monetizing our natural gas, and a sustainable budget. All three Senate priorities are key to moving Alaska forward, and all three will receive the attention they deserve with a whole new set of eyes, with a long-term perspective in mind. But, as Alaskans we need to understand that legislation is a process.

Alaskans, there is no such thing as a perfect bill. The Governor will be delivering his oil tax reform bill next week to the legislature. I know I’m going to love parts of the bill, and I’m going to hate parts of it. My concern will continue to be whether the tax cuts go far enough to entice oil company investment in Alaska in the short-term, as well as to firm up what the long-term plan is in regards to extracting unconventional oil (viscous, heavy) from existing fields. It will be a 90-day juggling act as to how do we prioritize our hits today for a promising tomorrow. I encourage all to watch and participate in the dialogue, because the decisions regarding oil taxes today will impact you, and your family, and future generations of Alaskans.

One of the big questions this legislative session will be whether or not it is feasible and economical to monetize our natural gas. I personally have not been engaged in the issue. I come from the premise that if the state gets involved it is probably not economical. The oil producers were clear in their October letter to the Governor that our oil tax structure must be addressed first prior to looking into any pipeline project moving forward. I am personally not married to any pipeline project. The only thing I care about, and the majority of Alaskans care about is keeping the heat and lights on in our homes TODAY. High energy costs have hit my bottom line, and all Alaskans are hurting.

The elephant in the room will be our state operating and capital budgets, and as stakeholders we need to be engaged in the debate. We as citizens need to decide what our priorities are, and what Alaska we plan on leaving our children and grandchildren. Some would like to make it about a number, and that number is the end all, be all. I do believe that to be a consideration but not an answer. Relying on a number does not address the systemic problem we created, oversimplifies the issue, and is misleading to the public. I personally do not have the answers. I want all decisions to be balanced, and well thought out as to not harm our citizens or communities. All of our state's stakeholders need to be at the decision table, and not just a select few who seem to believe they have all the answers. Alaska has never had a strategic plan and presently there is no roadmap to the future. Alaska is destined for greatness with the right vision, leadership, and a strategic plan for the future. Our state legislature is committed to our state's future regardless of party, and we are on the road to greatness this legislative session.

My friends in the legislature are ready to jump in and roll up their sleeves and make hard decisions today, and we should all be excited about that. I’m not interested in losing the legislative game and uprooting my family, and moving outside of Alaska. Alaska has been my home of 36 years, and my children deserve the same opportunities my friends and I rolled around in growing up, and we all need to be good stewards of our natural resources, and our dollars to insure that my children's future is bright

Please join me in my enthusiasm for this upcoming legislative session, and supporting our Governor and legislators for the next 90 days.

Let’s bring on Alaska’s future.

Friday, January 11, 2013

Fresh faces, energy in Juneau as session opens

Tim Bradner
Alaska Journal of Commerce

A new Legislature convenes in Juneau Jan. 15 bringing fresh faces and energy to tackle old problems, nagging issues like oil taxes and, with oil production declining, restraining the growth of spending.

Republicans are firmly in control of both the House and Senate, with 13 Republicans and 7 Democrats in the 20-member Senate, and 25 Republicans and 15 Democrats in the 40-member House.

Rep. Mike Chenault, R-Nikiski, was chosen to once again be Speaker of the House, while Sen. Charlie Huggins, R-Mat-Su, will lead the Senate as president.

Revenues seem sufficient to cover expenses for the upcoming 2014 fiscal year, which begins July 1. The latest estimate is that the state will receive $11.36 billion in total revenues in the 2013 fiscal year. Gov. Sean Parnell has proposed a spending plan of $10.86 billion, which includes a proposed capital budget of $1.8 billion. If the Legislature adds $500 million in capital appropriations, which is quite possible, the expenditures will match expected income.

A possible $2.35 billion capital budget is healthy, but will be down from the $2.88 billion capital budget approved for the current 2013 fiscal year.

Lawmakers will meanwhile be watching oil production levels and oil prices and will make final budget decisions based on an updated revenue forecast that will be made in the spring.

Oil production is declining at rates of about 6 percent per year, a matter of concern to legislators.

Energy problems in the state will be at the forefront in 2013.

House Speaker Chenault and Rep. Mike Hawker, R-Anchorage, have reintroduced their bill to expedite an in-state gas pipeline from the North Slope; Parnell has included $95 million in his proposed budget for continued work on licensing a $4.6 billion hydro dam on the upper Susitna River; and Fairbanks legislators will be at work to get a natural gas trucking project under way from the North Slope to relieve high space heating and power costs.

The 2013 version of the Chenault-Hawker bill to facilitate the in-state gas pipeline is HB 4, among the prefiled bills. The measure is similar to last year’s HB 9 which established new confidentiality powers and made changes on regulatory issues, and also would allow the state Alaska Gasline Development Corp. to have access to $200 million set aside in a fund to finance engineering and development.

Parnell is expected to unveil a new proposal to adjust the state’s oil and gas production tax, which the governor says is too high and inhibits investment in new oil development.

A similar proposal by Parnell in 2011, continuing through the 2012 session, resulted in deadlock. The House passed the governor’s bill, HB 110, but the Senate refused to approve it both years and was unable to get a majority of its coalition leadership to approve an alternate proposal it developed.

Republicans have a clear majority in 2013, up to 13 from the previous 10, and Democrats’ numbers have dropped from 10 to 7, so there may be a better political environment for the oil tax issue this year.

“May” is the operative word. Passage won’t be a slum dunk for this controversial, complex issue. The three Fairbanks senators, all Republicans, were pressured in their campaigns to demand that tax reductions for industry be linked to increased investment and improved production, a good idea in theory but complicated to actually write in the tax code.

Legislators also hope to see progress on the large natural gas pipeline and LNG export project being planned by the three major North Slope producers and TransCanada, a pipeline company. The governor is hoping to see the companies commit to pre-Front End Engineering and Design, which would involve the first substantial financial commitment to the project.

Lawmakers will also be watching to see if that happens. The producers have made it clear that progress on adjusting the oil tax is needed for the gas pipeline because a healthy oil producing industry is needed over the long term to pay for the infrastructure that will also support gas production.

On other issues, it is clear that with both the incoming Senate President Huggins and Speaker Chenault representing Southcentral Alaska, issues affecting that region will have a priority this year that was absent in 2012.

In a talk to the Resources Development Council Jan. 3 Huggins mentioned legislation to expedite the long-planned Knik Arm crossing project, a road down Cook Inlet’s west side to boost resource development in that area, and upgrades to electrical distribution grids, a priority for Southcentral electric utilities.

On the Knik crossing, Rep. Mark Neuman has introduced HB 23, relating to bonds and reserve funds needed for the Knik Arm Bridge and Toll Authority that was formed to build the crossing.

Huggins and Chenault, who was also at the RDC meeting, both mentioned support for the Watana hydro project and the in-state gas line.

It’s noteworthy also that the two Finance co-chairs in charge of the capital budget are both from Southcentral, Rep. Bill Stoltze, R-Chugiak, on the House Finance Committee and Sen. Kevin Meyer, R-Anchorage, on the Senate Finance Committee.

The House and Senate co-chairs for the operating budget are Rep. Alan Austerman, R-Kodiak, and Sen. Pete Kelly, R-Fairbanks.

Given the positions they are in, Huggins and Stoltze are also expected to give a priority to sports fisheries and particularly efforts to enhance and protect the diminished king salmon fisheries in Cook Inlet. The first batches of pre-filed bills by House and Senate members are available, 46 bills in the House and 10 bills in the Senate. The measures aren’t formally introduced until the Legislature gavels in on Jan. 15, however.

Many of the proposals have been in the Legislature before and many are relatively routine changes to statutes. Many are of interest to businesses, among them HB 6 in the House and SB 8 in the Senate relating to audits of pharmacy records; a House proposal making changes in the Uniform Commercial Code, in HB 9; bills relating to commercial motor vehicles, in HB 15 and commercial vehicle registration in HB 19; a bill allowing issuance of one business license for multiple lines of business in HB 32; a Senate bill requiring reporting and analysis of tax credits in SB 5; a bill dealing with computation of tax on the state corporate income tax in SB 7; and a bill requiring more information on oil and gas expenditures related to petroleum investment tax credits, in SB 10.

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Saturday, January 5, 2013

1st Nations wield clout; Stage protests across Canada, serve notice money no longer overcomes opposition

by Gary Park
For Petroleum News

Acting under a common rallying cry of Idle No More, thousands of aboriginals have participated in rolling protests across Canada over the past month, staging flash mobs, a hunger strike by an Ontario chief, a rail blockade and sustained social media campaigns.

It’s the culmination of a year in which First Nations drew strength from 170 court victories that give them a decisive say in how natural resources are accessed and developed in every region of the country and points to even more pivotal action in 2013 that could, among other issues, determine the future of plans by Enbridge and Kinder Morgan to export oil sands bitumen to Asia.

The message was delivered in early December by Ellis Ross, chief councilor of the Haisla First Nation in northwestern British Columbia, to a business-First Nations symposium in Vancouver.

The session was a joint undertaking by the B.C. Business Council and the B.C. Aboriginal and Investment Council — itself a clear signal of a rapidly-changing environment — as a prelude to the release in March of case studies involving First Nations and the business community.

Perhaps as much as any Native leader, Ross is described as occupying the crossroads of some of Canada’s biggest energy and international commerce ambitions.

If the projects, estimated to cost tens of billions of dollars, get regulatory approval and corporate sanctioning they will far surpass any investment British Columbia has seen in the mining, lumber and fishing industries.

And the Haisla have control over a large chunk of the land that about 20 of those projects will need.

Roger Harris, a Vancouver consultant, told the Globe and Mail that how Ross “decides to address these projects and the guidance he provides and the leadership on that front, will dictate (Canada’s) national energy policy for 30 years.”

In a quiet, measured fashion, Ross has emerged as one of Canada’s most influential voices, whether he speaks for First Nations or industry.

Bottom line not money

His fundamental message is that the business aspirations of First Nations embrace environmental, social and cultural issues. The bottom line is not money.

“If you address First Nations on their level, it does lead to a successful project,” he told the Vancouver Sun. “There are ways to talk to First Nations, to interact with them and negotiate with them and that’s what we want to highlight.”

Ross said that 10 years ago the only voice First Nations had was in the courts and “nobody wins in the courts.”

“There is an economic component to economic development that’s covered off in aboriginal rights and title case law, but that’s not really the approach at all that First Nations take.

“The Haisla, for example, want to see the environmental question answered first and foremost before you even discuss other issues.

“And that’s where some companies make a mistake in thinking all we are looking for is a pay check,” he said, in a blunt reference to Enbridge’s offer of revenues from Northern Gateway to First Nations, along with setting a rigid deadline for accepting the offer.

Ross makes a point of including his telephone number in speeches to business groups to demonstrate that he is ready to do business through joint ventures, partnerships and other means, so long as the Haisla’s fundamental concerns are addressed.

Territory surrounds Kitimat

The Haisla territory surrounds Kitimat, the tanker terminal and deepwater port that holds the ultimate key to exporting bitumen and LNG.

Today, the Haisla collect C$4 million a year from the partnership of Kitimat LNG, once made up of Apache as operator, with Encana and EOG Resources as minority partners, and now headed for a 50-50 joint venture by Chevron as the new operator and Apache.

If the new ownership can move the project from neutral to full-speed ahead and start shipping LNG by late this decade, the Haisla could qualify for C$15 million to C$20 million a year, having already sold a land ownership option to Kitimat for C$58 million.

The Haisla also have a 50 percent stake in the smaller BC LNG Export Co-operative, which along with Kitimat hold the only two LNG export permits issued so far by the National Energy Board.

They also anticipate returns from the Canada LNG project, which has Royal Dutch Shell as 40 percent operator with three Asian firms sharing the balance.

In addition, the Haisla have a land deal with Rio Tinto Alcan for a smelter in the Kitimat area and have a legal say in what happens to land along the Douglas Channel out of Kitimat.

Although he has little post-high school training, Ross is viewed as having expertise in First Nations’ rights to match any in the legal community and is demonstrating skill in negotiating business deals which he hopes will allow the Haisla to regain ownership of their land that was sacrificed after white settlers moved into the area.

December rift

But within British Columbia’s often fractious aboriginal communities, not everyone shares the Haisla approach, resulting in a December rift when the Haisla broke away from Coastal First Nations, an advocacy group representing a dozen communities that has opposed some of the LNG plants in the works for Kitimat.

“What we’re working on is a way to create C$40 million worth of revenue coming out of these projects that could be shared among the northwest First Nations,” said Ross. “We thought we were on the same page.”

However, the Haisla were caught off guard when the Coastal coalition, without any previous discussion, raised concerns about air pollution from the Kitimat and BC LNG plants and accused the Haisla of “buddying” with Canada’s Natural Resources Minister Joe Oliver.

Bill Gallagher, a former Canadian government regulator, oil and gas lawyer and Native treaty negotiator, has no doubt that before mining, forestry and pipeline projects can move ahead an accommodation must be found with First Nations.

“The current situation in terms of access to resources, with the overarching tensions, has become unsustainable,” he told the Financial Post. “This is the key to the whole thing, Recognizing that Plan A has not worked; let’s put a Plan B together.

“As long as industry keeps pushing projects in the regulatory process and lawyers are doing all of the speaking, the element of trust never gels,” Gallagher said. “The process is seen as stacked in favor of industry and you have these constant challenges.”

He credits oil sands giants Suncor Energy and Syncrude Canada with taking the right path and now employing thousands of aboriginals and supporting aboriginal enterprises.

Gallagher said the high-profile national debates over oil sands expansion and export pipelines could result in new approaches, given that the proposed pipelines are “running directly into powerful legal precedents.”

He said too many of the proponents “may have got the geology right, the geography right and even the marine patterns to some extent right, but they have missed the Native empowerment landscape.”

Gallagher warned that the alternative will see projects scuttled, confrontation dominate the debate and billions of dollars wasted in real and missed opportunity costs.

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Friday, January 4, 2013

Amid pressure of ‘fiscal cliff,’ Senate moves Alaska gas line bill

—Wesley Loy

In the wee hours of New Year’s Day, the U.S. Senate approved a hard-fought deal to stave off the dreaded “fiscal cliff.”

But that wasn’t the only order of business for the bleary-eyed senators.

They also passed, by unanimous consent, a bill that someday could prove an important piece of a plan to bring energy security to Southcentral Alaska.

The bill (S. 302) would allow for construction of a natural gas pipeline through Denali National Park and Preserve.

The planned pipeline would run 737 miles overall, from the rich gas fields of the North Slope to the area of Anchorage and Cook Inlet. S. 302 would authorize the Interior Department secretary to issue a right-of-way permit for a short section of the pipe to pass through nonwilderness areas within the Denali Park boundary.

Specifically, a seven-mile segment of the line could be laid along the George Parks Highway, which runs through the park.

The idea has drawn support from the state, the National Park Service and environmental groups as likely the least disruptive route for the gas line.

‘Clear legal path’

U.S. Sen. Lisa Murkowski, R-Alaska, sponsored S. 302, introducing it on Feb. 8, 2011. Her Democratic colleague, Mark Begich of Alaska, was co-sponsor. Murkowski, the ranking member on the Senate Energy and Natural Resources Committee, welcomed the bill’s last-minute passage. It otherwise would have died on Jan. 3, when the 112th Congress ended.

“It is important for Alaskans that our North Slope natural gas has a clear legal path to market,” Murkowski said in a Jan. 2 press release. “This bill clears a key hurdle to constructing a pipeline along the Parks Highway and allows decisions on the best route to be based on economic and commercial grounds, rather than out of fear of lengthy permitting delays to win access rights across federal lands. Getting our gas to market is vital for the future of Southcentral, the state’s economy, and all Alaskans.”

After the Senate’s passage, the bill went over for consideration in the House of Representatives.

In-state gas needs

An Energy Committee report accompanying S. 302 explained that Cook Inlet gas fields, long the major energy source for Southcentral Alaska, are declining, and that Alaska is considering a pipeline to carry North Slope gas to the region to meet local needs. This would be a different, smaller pipeline from large-diameter export gas line long under consideration by the state and oil companies. That line would run into Canada, or to a liquefied natural gas export facility at Valdez, terminus of the trans-Alaska oil pipeline.

The worry is that construction of the big line is too many years away to help supply local gas to Southcentral. And so a state agency, the Alaska Gasline Development Corp., has been working toward the smaller line, sometimes referred to as a “stand-alone” or “bullet” line, to shoot gas from the Slope to the Anchorage area, with a lateral line to Fairbanks in the state’s Interior.

Though much smaller than the export line, the stand-alone line nevertheless would be a megaproject costing billions of dollars. And so there’s no guarantee it will ever be developed.

The U.S. Army Corps of Engineers in October issued a final environmental impact statement for the Alaska Gasline Development Corp. project.

The EIS considered route alternatives, including one that would allow a short segment of the pipe to pass through the huge Denali Park.

Gas pipelines may be permitted through a national park only if authorized by an act of Congress.

Stephen Whitesell, a National Park Service official, provided testimony at a May 11, 2011, congressional hearing on S. 302, saying the Interior Department had “no objection to the bill as written.”

He noted that the bill not only would allow for granting a Parks Highway right of way, but “provides authority for the Secretary to permit distribution lines and related equipment within the park for the purpose of providing a natural gas supply to the park.”

A coalition of environmental groups including the National Parks Conservation Association sent a Jan. 30, 2009, letter to Enstar Natural Gas Co., the major gas utility for Southcentral Alaska, saying it seemed logical to route the pipeline through Denali.

“This would seem to make the most sense from both an engineering and an environmental perspective as going around the park would necessitate construction in currently undeveloped lands,” the letter said. “While the signers of this letter agree that bringing the gas pipeline along the Parks Highway through Denali seems to be the environmentally preferable alternative, we reserve final judgment until completion of the environmental review.”

A gas supply could allow the park and local transportation providers to reduce their use of diesel.

Bill provisions S. 302 would permit a natural gas pipeline to be buried in the shoulder of the Parks Highway for the seven miles that the highway runs through Denali Park. According to Murkowski’s press release, the legislation would:

• Allow any high-pressure pipeline to run through the existing utility corridor at the entrance of Denali Park, provided that no compression stations are placed inside park boundaries.

• Allow distribution and transmission pipelines to be placed inside the park at the request of the National Park Service to provide natural gas to park facilities.

• Require the Interior secretary to issue a permit for a line if it clears a required National Environmental Policy Act review.

“A natural gas pipeline route through the park would not only be less expensive to build, but could also take advantage of the existing utility corridor, preventing disturbances to wildlife and environmental impacts on undisturbed lands further to the east or west of the park boundary,” Murkowski said.

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MEA worries Chugach/GVEA deal might strain Cook Inlet supplies

—Eric Lidji

Matanuska Electric Association is worried a proposed gas sales agreement meant to lower Interior fuel costs might “imprudently hasten” the decline of Southcentral supplies.

In late November, Chugach Electric Association announced plans to purchase up to 8.8 billion cubic feet of natural gas from Hilcorp Alaska LLC between April 2013 and October 2015. Chugach plans to use the additional gas supplies to produce electricity for Golden Valley Electric Association, an electric cooperative serving the Interior region.

While Chugach described the contract as a “win-win-win” because it would lower electricity rates in Fairbanks, increase storage volumes in Southcentral and provide a market for a local producer, MEA is skeptical about its benefits for Southcentral.

“These Southcentral utilities have no reasonable alternative fuel sources by which to satisfy their basic requirements to provide service to the public,” MEA General Manager Joe Griffith wrote in recent comments to the Regulatory Commission of Alaska. “GVEA, on the other hand does have viable alternatives for fuel supply and has not historically been dependent on Cook Inlet natural gas for its base load generation requirements.”

Because the contract includes sales through October 2015, MEA is also worried it may jeopardize its ability to find fuel supplies once it becomes self-sufficient in January 2015.

“The Commission should not allow the gas required to serve MEA’s base load starting January 1, 2015 to be committed to another utility, in this case GVEA,” Griffith added.

MEA currently purchases power from Chugach.

Because of these concerns, Griffith asked the RCA to launch a “formal investigation” to “provide a forum to hear directly from Chugach how the proposed agreement creates a ‘win-win-win scenario’ for the rate payers of Southcentral Alaska, and for the Commission to explore options for ensuring that, in this time of likely fuel shortages, the collective public interest is not compromised by the actions of the individual utilities.”

MEA has also asked to become a party to the proceedings.

While the contract provides for gas to produce power for the Interior, it also includes a clause allowing Chugach to curtail deliveries in the event of a Southcentral fuel shortage.

The RCA does not regulate producers, but it must approve all utility gas purchases.

GVEA and HEA on board

Golden Valley Electric Association believes the contract serves a public interest. Because of its dependence on oil-fired generation, GVEA rates are among the highest for any urban area in the state. With Cook Inlet gas supplies dwindling, the amount of load requirements generated by oil increased by 40 percent in 2012, according to the utility.

By providing lower-cost gas-fired generation, the proposed contract would create savings that GVEA could “immediately” pass on to its customers, GVEA Vice President of Administrative Services Thomas K. Hartnell wrote in comments on Dec. 26.

“This is the proper statewide use of an Alaskan natural resource,” he wrote.

Homer Electric Association also blessed the contract.

While noting its benefits to the Interior and Southcentral, HEA General Manager Brad Janorschke called the proposed pricing mechanisms “reasonable and consistent with the gas costs of other recently approved gas agreements that the Commission has approved.”

But Enstar Natural Gas Co. wonders if the contract could exacerbate potential supply shortfalls in the future, and has therefore also asked to be a party in the proceedings.

While not opposing the sales, Enstar said it wants to help “build a full and accurate record of this (contract) may relate to the ongoing supply issues facing Cook Inlet.”