Saturday, May 16, 2015

Educators misled by the NEA and the Partnership for Public Education

Kara Moriarty

Alaskans deserve facts on all major public policy issues. Sadly, misrepresentations about Alaska’s oil and gas tax credits threaten to turn a situation that requires a thoughtful and fact-based approach into a political skirmish complete with slogans and accusations.

It is impossible for anyone to track every issue, so we tend to rely on media outlets, unions, trade groups, etc., to provide us accurate information that enables us to learn about and take positions on public policies. Unfortunately, in this case, the union representing teachers has let its members down by continuing to spread inaccurate information for the last month -- even after hearing the facts.

The NEA commissioned a poll this spring, in conjunction with the members of the Partnership for Public Education, which include: AFL-CIO; Alaska PTA; Anchorage Polynesian Lions Club; Citizens for the Advancement of Alaska’s Children; NAACP; Polynesian Association of Alaska; and School Business Partnerships. One of the questions asked Alaskans how they felt about oil tax credits, and if the Legislature should revisit oil taxation. Fair question. However, the question as worded was blatantly incorrect. This could have been an honest mistake, but professional standards dictate that when an error is identified, the responsible party is obligated to correct it. To date, the NEA and the Partnership for Public Education refuse to take ownership of their error, which is especially regrettable when you consider this is the union that represents teachers who, more than any other professional, strive for truth in information as they educate the next generation of Alaskans.

More than a month ago, I respectfully presented the correct information from the Department of Revenue to the NEA and the PTA. I asked that they provide the facts to those that received the poll and put a disclaimer on the public results. Several emails and many weeks later, I have been ignored and nothing has been done. The pollster for this organization, Hays Research Group, is also unwilling to correct the record despite what appears to be a clear violation of the ethical guidelines outlined by that profession’s trade organization. As the head of a professional association whose mission is to provide Alaskans with factual, third-party referenced information, this kind of casual attitude toward the truth is unsettling. My professional training is in education; I used to be an elementary school teacher, and an NEA member, and I would be horrified to know my union was consciously choosing to misrepresent an issue that was proven to be false.

The inaccurate statement contained within the poll question posed to Alaskans read like this:

"The state revised its oil tax law in 2013, and Alaskans voted by a narrow margin in August not to repeal the new tax system. At current oil prices, the state gives out more in oil tax credits to the oil industry than it receives in revenue from the oil industry. Would you support the Legislature revisiting the issue of oil credits and taxes in light of the current deficit?"

Who wouldn’t respond with a “yes” to this question as worded? The trouble is, it’s just flat wrong.

In fact, its entire premise is wrong. It is an indisputable fact that the State of Alaska receives billions more in revenues than it pays out to oil companies when you look at all oil revenue sources: royalties (the state’s share as an owner), production taxes, income taxes, property taxes and other fees paid to the state.

Alaskans deserve an honest conversation based on facts as we tackle our fiscal challenges, not half-truths or political spin. No one is served when individuals or organizations throw out inflammatory accusations that are clearly either false or taken out of broader context.

The NEA has every right -- and even the responsibility -- to lobby rigorously for policies that benefit public education and teachers. But it should do so in a way that informs Alaskans with accurate information, not misleads them by spreading false information.

My organization has set up a special page on our website for readers who want more information on oil revenues and tax credits from objective, third-party sources. Visit and learn about it for yourself.


Kara Moriarty is executive director of the Alaska Oil and Gas Association, a nonprofit trade association whose mission is to foster the long-term viability of the oil and gas industry in Alaska.

Thursday, May 7, 2015

Pentex purchase could cut ratepayers’ bills immediately

Fairbanks Natural Gas customers could see their heating bills drop immediately if the utility is sold to the Alaska Industrial Development and Export Authority.

“We do believe through the financing tools that AIDEA has, we could reduce the (gas) rate in Fairbanks right away by approximately 14 percent,” former AIDEA director Ted Leonard said at the authority’s April 30 board meeting.

“Rationalizing” the two gas distribution systems being developed by Fairbanks Natural Gas and the Interior Gas Utility and forming one system could provide significant capital and operating cost savings, he said.

Leonard retired as AIDEA executive director earlier this year but has continued to work on the Interior Energy Project because of his extensive experience with the earlier North Slope work.

Further savings to ratepayers would come from the different business models — moving away from the inherent cost and return requirements in a privately-owned utility structure.

Mark Gardiner, a financial consultant who is working closely with AIDEA on the proposed deal, said that the current rate of $23.35 per thousand cubic feet, or mcf, of gas FNG customers are paying could be $20 next year if the sale goes through. The savings would be even greater if FNG’s pending rate case before the Regulatory Commission of $24.96 per mcf is accepted.

The potential cost savings from the purchase are separate from whether or not the Interior Energy Project moves forward. However, an early projection of $16.80 per mcf in 2020 for all customers of a blended utility was presented to the board.

That estimate assumes liquefied natural gas can be delivered to Fairbanks for the equivalent of $11 per mcf, a midstream price the Interior Energy Project will have to come close to in order to meet the stated goal of the project.

Leonard said North Slope gas trucking project models came in with a comparable price in the $13 to $13.50 per mcf range.

AIDEA projects full buildout of a consolidated Fairbanks gas utility to cost $223 million. To date, the authority has issued $52.8 million in loans for gas distribution from the $332.5 million Interior Energy Project state financing package.

AIDEA announced a preliminary agreement to purchase the parent company to Fairbanks Natural Gas, Pentex Alaska Natural Gas Co., in late January.

That announcement was met with resistance from some Alaska legislators who questioned the premise of the state purchasing outright a private business and how the AIDEA-Pentex sale would affect an earlier agreement for a Hilcorp subsidiary to purchase Titan Alaska LNG — Pentex’s LNG trucks and small Southcentral liquefaction facility.

The 10-year LNG supply agreement Harvest has with Pentex, as part of the Titan sale would remain as well. That agreement is to fuel existing gas customers and does not expand Interior’s natural gas supply.

It’s currently believed the two deals can coexist; AIDEA would purchase Pentex for $54 million and then sell Titan to Harvest Alaska (Hilcorp) for $15.1 million, which is the price Pentex and Harvest originally agreed to.

The AIDEA deal is set to close July 31. The Titan sale is being reviewed by the RCA and Attorney General Craig Richards and has a Sept. 31 financial close date.

If the Titan sale is denied or otherwise fails AIDEA would retain those assets.

Leonard and Gardiner said it is the authority’s intent to sell or otherwise transfer control of Fairbanks Natural Gas within two years to a local entity, most likely IGU, which is owned by the Fairbanks North Star Borough.

Fairbanks Natural Gas President and CEO Dan Britton, who is also a minority shareholder in Pentex, said in an interview that IGU leaders have generally been kept abreast of the negotiations with AIDEA and are supportive of the overall plan.

Fairbanks Natural Gas petitioned the RCA for IGU’s service area and Britton has said two operating gas utilities makes little sense for the small customer base that is the greater Fairbanks area.

IEP gets moving

Now that a bill has passed allowing Cook Inlet gas to be used as a possible supply, it’s full steam ahead for the Interior Energy Project, its manager Bob Shefchik said April 30.

The project team had meetings scheduled the week of May 4 with 15 to 18 parties that have expressed interest in partnering on the Interior Energy Project, Shefchik said.

“Because it’s been such a long process we want to bring them in, talk to them about where we’re headed, what we expect to be in the solicitation and get some feedback,” he told the AIDEA board.

A request for proposal, or RFP, for a private partner to expand Southcentral gas liquefaction capacity should be issued by AIDEA by mid-May and stay open for 30 days, according to Shefchik. Proposals for a small gas pipeline and propane solutions will also be accepted.

He said the board could expect the results of the RFP at its June 25 meeting.

Concurrently, the state Commerce Department along with the Revenue and Natural Resource departments are working on a gas supply solicitation.

Shefchik, a former Interior Gas Utility chair, said the Fairbanks utilities have agreed to participate in the RFP selection process and a range of acceptable gas prices will be worked out earlier than it was during the North Slope supply efforts to keep the utilities on board.

“The thing that has to be avoided is (price) being the last thing decided,” he said.

Sunday, April 5, 2015

State estimates $150B to treasury if ANWR ever opened

Alaska Contract Staffing
Tim Bradner
Alaska Journal of Commerce

Alaskans have long believed oil discovered in the coastal plain of the Arctic National Wildlife Refuge could help keep the Trans-Alaska Pipeline System operating and also replenish the state treasury.

It may be a pipe dream because the federal government shows no sign of opening the coastal plain to further exploration and Congressional approval is required for any exploratory drilling or leasing.

Interior Secretary Sally Jewell, who denied the State of Alaska’s proposal for new seismic exploration of the ANWR coastal plain and is awaiting the outcome of a court case challenging that decision, wants to make it wilderness, a permanent lockup.

But what if? What if there were exploration, and discoveries? How much oil could there be? State officials told legislators in February the revenue to the state treasury could total more than $150 billion over 50 years.

ANWR’s coastal plain, in the eastern North Slope, is thought by geologists to have the best potential for major discoveries of any unexplored onshore area of the U.S.

Major oil fields have been discovered in the central North Slope, including the very large Prudhoe Bay and Kuparuk River fields. There is potential for further discoveries in this area but they are expected to be smaller.

The southern North Slope, and the huge 23-million-acre National Petroleum Reserve–Alaska on the western Slope, are generally thought by geologists to be prone to natural gas discoveries although some oil will almost certainly also be found.

The most informed estimate on ANWR’s coastal plain area came from the U.S. Geological Survey in 1998, which made a “mean” estimate of 7.7 billion barrels of recoverable oil that could be discovered. “Mean” is basically mid-way between high and low estimates.

Whether oil is really there isn’t known for sure. The USGS worked with data from 1,180 miles of two-dimensional seismic program conducted between 1983 and 1985, plus what is known about the regional geology.

The only exploration well drilled in ANWR, in a 91,000-acre in-holding of private lands owned by Kakovik Inupiat Corp. and Arctic Slope Regional Corp., was drilled in the early 1980s by BP and Chevron Corp., and the results are still secret.

No matter what the drilling showed, development of even these private lands are blocked unless Congress decides to open the rest of the costal refuge.

Still, state legislators in Juneau want to know what Alaskans may be missing out on.

In mid-February, the House Resources Committee asked the state departments of Natural Resources and Revenue to develop the most plausible oil discovery and production scenarios based on that is known, and to derive state revenue estimates from those.

The two agencies presented their results to the committee on Feb. 12.

Paul Decker, acting director of DNR’s Division of Oil and Gas, described ANWR’s regional geology in the so-called “1002” area, a coastal plain area named for the section of the law in which Congress designated for additional study of petroleum resources in the Alaska National Interest Lands and Conservation Act of 1980, the federal law that created the refuge.

Decker said the best prospects for discovery are in the western third of the coastal plain, which state geologists believe to hold the most oil potential. Of the 7.7 billion barrels of resources estimated to be in the 1002 area, 6.4 billion barrels are expected to be in the western third.

That is about five times the oil potential of the eastern two-thirds of the coastal plain.

“The northwestern one-third of the coastal plain is geologically simpler and more favorable to hosting oil accumulations,” Decker told the committee.

The area is also adjacent to state lands across the Canning River where companies have made discoveries at Point Thomson (gas, liquid condensate, and oil), and Sourdough (oil). Oil has also been discovered offshore the 1002 area, with the Kuvlum well in 1993 and “Hammerhead” (where Shell is exploring) in 1985.

Geologists in the division did further analysis, predicting that most of the accumulations that might be discovered would be in the 32 million-barrel range to 256-million-barrel range, but accumulations of 1 billion barrels were also possible.

Based on that analysis, the Department of Revenue developed possible production and oil royalty and tax estimates. Ken Alper, director of the Tax Division, presented the conclusions, assisted by Dan Stickel, assistant chief economist.

The scenario presented by Alper and Stickel would have permission granted by Congress to explore in 2016 and leases issues between 2017 and 2019. Exploration would begin in 2019, with the first field located in 2022, and with its development beginning that same year.

First production would be in 2026. From that point on, the scenario foresees one new field discovered and brought into production every two years so that there would be 25 fields in total developed by 2074. The assumed size of discoveries vary along the lines of the estimates by the Division of Oil and Gas but most of the new fields would be between 64 million barrels and 512 million barrels of recoverable resources.

All prices and costs in the modeling assumed 2015 constant dollars and an oil price of $110 per barrel along the lines of the Revenue Department’s very long-range price forecast (a $90 per barrel case was also considered, however).

The modeling assumes no gas being developed, although surely there would be gas discovered also.

Given these assumptions in the modeling, a “base case” of 7.1 billion barrels of oil developed and produced until 2075 would bring $150.9 billion to the state treasury, although the number could be higher, or lower, depending on the amount of oil found.

The production profile in the base case was about 560,000 barrels per day, with a high case, with more oil discovered, of 760,000 barrels per day and a low case, with less oil discovered, or 350,000 barrels per day.

The required investment by industry would reach $5.75 billion per year in the development, pre-production phase, with continuing investment all through the operating lives of the fields.

Because of tax credits in the current state production tax the state treasury would not begin to experience income net of the tax credits until 2030 or 2031, but revenues would then increase rapidly to a peak of about $4.9 billion per year in 2045.

Revenues would the taper off gradually, but even by 2075, the end of the period modeled, there would still be $3.3 billion per year net to the state treasury.

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Saturday, March 7, 2015

Beechey’s fate unclear; State termination proceedings began last year; BRPC wants to consolidate prospects

Eric Lidji
For Petroleum News

The state is considering the fate of the Beechey Point unit.

The Alaska Department of Natural Resources started termination proceedings for the North Slope unit last September, although it agreed to reconsider after operator Brooks Range Petroleum Corp. made a case for maintaining the unit in the Gwydyr Bay region.

Then-Commissioner of Natural Resources Joe Balash initiated the termination proceedings in September 2014, saying the Alaska-based company had failed to meet certain work commitments in its initial five-year plan of development and failed to meet any of the conditions for justifying an extension. In addition to obvious conditions like sustained oil or gas production or ongoing exploration activities, those conditions include having a well certified as capable of producing hydrocarbons in commercial quantities.

With no such certified well at the unit, Balash believed termination was justified.

The company disagreed. In a late September 2014 letter, Vice President for Exploration Larry Vendl named two certified wells within the unit boundaries. He asked for a chance to negotiate a plan of development that would allow the company to continue exploration and development activities. The company could start as early as 2015, Vendl wrote.

Wells on leases

The leases included in the Beechey Point unit undeniably include two wells certified as capable of producing hydrocarbons in commercial quantities: Gwydyr Bay South No. 1 from 1974 and North Shore No. 1 from 2008. Both wells, though, were drilled before the state approved the Beechey Point unit in mid-2009. To the state, that made them irrelevant for extending the terms of the unit. To the company, it made no difference.

Of particular interest is North Shore No. 1, which was the first well Brooks Range Petroleum drilled in Alaska. The state certified the well in July 2008, approved the Beechey Point unit in August 2009 and asked the company to apply for a recertification by August 2010. To Brooks Range Petroleum, this “redetermination requirement” represented a changing standard. No other operator had been asked to perform a similar task, according to the company, which asked the state, in July 2010, to reconsider.

The state never responded, according to the company. The debate may be more than merely an administrative debate, though. In his September 2014 letter, Balash wrote, “It is my understanding that the well is physically incapable of producing hydrocarbons.”

New plan wanted

Brooks Range Petroleum now wants to negotiate a new plan of development, citing its commitment to the project thus far. The company said it had spent more than $85.5 million exploring the region to date and had begun permitting for a proposed North Shore Development Project. The company also applied to form an initial participating area. The state had yet to rule on the application when the termination proceedings began.

What the company failed to do was drill all the exploration wells required by the unit agreement. The agreement required Brooks Range Petroleum to drill at least one well in two different exploration blocks by December 2010 and December 2012, respectively.

The company only met the first work commitment. The state subsequently extended the deadline for the second commitment until 2014, which the company also missed.

In October 2014, Balash agreed to reconsider the termination. His decision came shortly before the election of Gov. Bill Walker, which prompted a turnover of many cabinet-level positions, including the Department of Natural Resources. The new commissioner, Mike Myers, inherited the matter and had yet to issue a decision by early March.

A decade of work

Although recently sold to a multiparty joint venture, Brooks Range Petroleum Corp. started its life as the operating arm of the Alaska Venture Capital Group, which came to Alaska in 1999 to pursue sizeable oil fields passed over by the major oil companies.

The Gwydyr Bay region north of Prudhoe Bay fit the bill.

The company acquired leases through a 2001 land swap with Phillips Petroleum and arranged an exploration program. The program collapsed under the weight of various logistical problems. Still intrigued, the company acquired the acreage again in 2005.

Brooks Range Petroleum commissioned a two-well exploration program in early 2007.

North Shore targeted Ivishak

The 10,319-foot North Shore No. 1 well targeted an oil accumulation in the Ivishak formation first tested by Mobil Oil with the Gwydyr Bay South No. 1 well in 1974. The well encountered “approximately 70 feet of oil-charged Ivishak sandstone formation.”

The 11,348-foot Sak River No. 1 followed up on a prospect previously included in the BP-operated Sak River unit. The well proved to be a dry hole, although the results were intriguing enough for the joint venture to consider returning to drill a sidetrack.

That winter, the company also commissioned a 130-square-mile 3-D seismic survey, which “identified two small satellite prospects to North Shore No. 1 that can be reached from the North Shore No. 1 drilling pad,” according to a former partner on the project.

Combining small prospects

The results of that initial season started the company along its current path - finding a way to string together several marginally economic prospects into a single, profitable development. An early partner described the strategy as “establishing a threshold” for development. Potential solutions included two production pads or extended reach drilling.

Brooks Range Petroleum re-entered North Shore No. 1 in early 2008 to test the Ivishak and the shallower Sag River formations. The Ivishak flowed at 2,092 barrels of oil per day. A mechanical problem down hole compromised the Sag River test, although the partner estimated that an unencumbered test could have flowed at 1,000 barrels per day.

That summer, the joint venture acquired the nearby Pete’s Wicked prospect from Pioneer Natural Resources Inc. BP discovered the prospect in 1997 and Pioneer acquired it in a 2003 lease sale. The acquisition provided an additional opportunity for bundling several prospects together.

A legal dispute among partners prevented drilling in early 2009. The following winter, Brooks Range Petroleum drilled the Sak River No. 1A sidetrack and the North Shore No. 3 delineation well. The company suspended both wells at the end of the drilling season.

Sak River 1A wet

“Sak River No. 1A was truly an exploration project with a pre-drill risk factor of 1 in 5, unfortunately the well encountered mainly water from the Kuparuk formation,” Brooks Range Petroleum Chief Operating Officer Bart Armfield wrote in a completion report for the season, which was published after a mandatory two-year delay. Although the company had plugged and abandoned the original Sak River No. 1 well, it suspended the sidetrack, which would allow it to be used for providing pressure maintenance for future wells in the Sag River formation. The company said it was considering plans for a second sidetrack, which would aim for an “up-dip target of the Kuparuk,” Armfield wrote.

North Shore No. 3 “identified a common oil/water contact between the Sag and Ivishak formations and presents a reduced reserve base for the North Shore development,” Armfield wrote, adding that the company had now discovered reserves at North Shore No. 1, North Shore No. 3 and Pete’s Wicked, which would guide future activities.

With its attentions increasingly devoted to the Mustang development, just west of the Kuparuk River unit, Brooks Range Petroleum has yet to return to the Beechey Point unit.

The original unit covered some 52,876 acres north of Prudhoe Bay. The unit contained five exploration blocks. In September 2012, the company relinquished some 42,119 acres on the western side of the unit, leaving a seven-lease unit covering some 10,757 acres.

‘Close proximity’

The challenge at Beechey Point remains the same, according to Vendl.

“The potential for successful exploration and development in this area requires the compilation of several prospects with known reservoir reserves in close proximity to one another,” Vendl wrote in his letter. “The smaller prospects need to be a part of a larger program; each independent prospect does not support an economic development model.”

The current strategy involves combining the prospects of various operators in the region, including the East Shore prospect at Beechey Point, the ConocoPhillips-operated Kup Delta lease and the UltraStar Exploration-operated Dewline unit, all of which are located on adjacent leases (see map). At the time of the letter, in September 2014, Brooks Range Petroleum was involved in discussions with both ConocoPhillips and UltraStar, according to Vendl.

Another option, Vendl noted, would be to expand the 3-D seismic survey BP Exploration (Alaska) Inc. is commissioning for the northern end of Prudhoe Bay, including Beechey Point. “We continue to pursue the availability of the contractor to include the (Beechey Point unit) leases so that we can determine the full potential of the Kup Delta and (Beechey Point unit) eastern area, including the Dewline unit,” Vendl wrote in his letter.

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