Sunday, December 29, 2013

Oil tax reform legislation the top story of 2013

The state Legislature action to revamp the state’s oil production tax in its 2013 session ranks as the top Alaska news story for the year. Senate Bill 21 will replace the current oil tax, called ACES, on Jan. 1.

The bill overhauls what had become an obsolete tax. There was wide agreement that ACES was “broken” but sharp disagreements in the Legislature over how to repair it. Generally, Gov. Sean Parnell and Republicans in the Legislature wanted a complete makeover, while Democrats leaned toward minor band-aids at most.

The makeover, in SB 21, involved major structural changes, however, and the Democrats and other critics howled.

After SB 21 passed and legislators went home last April critics organized a referendum drive to repeal the tax change. Sufficient signatures were gathered and the question will now appear on the August 2014 primary election ballot.

Basically, SB 21 makes two important changes and a number of smaller ones. Most important, it eliminates a “progressivity” formula in the ACES tax that ratchets up the tax rate as oil prices rise to high levels when prices reach $110 per barrel or above.

In those price ranges the effective oil tax rates in Alaska were some of the highest in the world. Alaska’s high costs, distance from markets and harsh climate conditions were challenges enough for industry, but the high tax rate made most new Alaska oil investments uneconomic under ACES.

Industry investment in new oil projects lagged, while it boomed in other U.S. states. Meanwhile, the decline in North Slope production continued at rates of 6 percent to 8 percent yearly.

SB 21 changed that structure. At the higher price ranges it would constitute a tax reduction for companies (at lower prices it works in reverse, raising taxes higher than ACES), but what’s most important is that SB 21 is simpler than ACES, which was so complicated companies could not predict its results in their planning for projects, which is very important.

Since last April, when the law change was made, the companies have stepped up with substantial new investments on the North Slope. About $4.5 billion in new projects are planned, and possibly more, which are expected to result in about 55,000 barrels of new oil production by 2018.

— Tim Bradner, Alaska Journal of Commerce

Friday, December 27, 2013

Wednesday, December 18, 2013

Conoco’s budget up; Worldwide $16.7 billion capital budget for 2014, $1.7 billion for Alaska

Eric Lidji
For Petroleum News

ConocoPhillips expects to spend much more in Alaska this coming year.

The largest oil and gas company in the state is budgeting $1.7 billion for Alaska projects in 2014, up 54 percent from the $1.1 billion it budgeted for 2013 and more than double the $828 million it actually spent in 2012, according to figures provided by the company.

The budget includes construction of the CD-5 satellite, a share of efforts to market North Slope gas and the regular array of maintenance work, but ConocoPhillips is attributing the increase to a slate of North Slope projects announced since the state changed its fiscal terms in the More Alaska Production Act, also known as Senate Bill 21. Those include additional Kuparuk River unit drilling, early work on the Kuparuk Drill Site 2S pad and drilling in the National Petroleum Reserve-Alaska. The NPR-A work includes the GMT-1 development well and two exploration wells in the Greater Mooses Tooth unit.

The budget proves the revised fiscal system is working, according to Gov. Sean Parnell, who released a statement saying, “Billions of dollars in new investment have been announced since I signed the MAP Act into law, and it’s helping to keep Alaska’s businesses and workers busy as they go after new oil production. Alaska is on track for more oil in the pipeline and more opportunities for future generations.”

Whether voters agree with his conclusions will be determined during the primaries next year. That is when the people will vote on a ballot referendum aimed at repealing the law.

Heavy Lower 48 spending

The spending comes as part of a $16.7 billion capital budget for 2014. The budget provides only a general breakdown of spending. A more-detailed breakdown often accompanies the annual report, which ConocoPhillips usually releases in February.

The budget dedicates some 39 percent, or $6.5 billion, for “high-margin development drilling,” of which two-thirds ($4.3 billion) will go to the Lower 48 and the remaining third, ($2.1 billion) will go to Alaska, Canada, Norway and western Australia.

The 2014 capital budget is aimed toward ConocoPhillips’ goal of producing some 1.6 million barrels of oil equivalent from its continuing operations in 2014, but those efforts are primarily focused on the Lower 48, Canada, Europe and the Asia-Pacific regions.

The budget allocates some 35 percent, or $5.8 billion, for “major projects,” starting with the APLNG project in Australia and including the Surmont Phase 2 project in Canada, the Eldfisk II project in the Norwegian North Sea, the Britannia Long-term Compression and Clair Ridge in the United Kingdom, as well as offshore developments in Malaysia.

The Lower 48 spending include work in the Eagle Ford, Permian and Bakken plays.

The budget also includes some 13 percent, or $2.1 billion, for “maintenance of the company’s high-quality legacy base portfolio, including 2014 planned turnarounds,” and another 13 percent on exploration and appraisal work in the Gulf of Mexico, the U.K. and Australia, as well as unconventional exploration in liquids-rich shale plays across the Lower 48 and Canada, and unconventional exploration in Colombia, Poland and China.

Read more:

Sunday, December 15, 2013

ConocooPhillips Slope budget up $600M

Tim Bradner
Alaska Journal of Commerce

ConocoPhillips is ramping up its Alaska investments sharply.

The company increased its 2014 Alaska capital budget by more than 50 percent, to $1.7 billion, and will drill two new exploration wells this winter in the National Petroleum Reserve–Alaska, company spokeswoman Natalie Loman said Dec. 9.

Spending next year will be in projects that are expected to add about 54,000 barrels per day in new North Slope production by late 2017.

About 38,000 barrels per day would be produced by projects approved since the Legislature amended the state’s oil production tax last April. Loman said one development in the 2014 budget that is now under construction, the CD-5 project in the National Petroleum Reserve-Alaska, was approved by the company before state lawmakers made the tax change in Senate Bill 21.

“Alaska projects will get about $600 million more than in 2013, when our capital budget was about $1.1 billion, ConocoPhillips spokeswoman Natalie Lowman said. “Our capital spending next year will be more than double the $828 million spent on projects in 2012.”

The company’s 2014 capital budget was approved by its board and announced Dec. 6.

ConocoPhillips credited the state’s new oil production tax law, which goes into effect Jan. 1, for stimulating overall new investment.

“Higher allocation of capital to Alaska compared to 2013 reflected improved fiscal terms from passage of the More Alaska Production Act (SB 21),” the company said in a Dec. 6 press release.

While much of the 2014 budget is allocated to the CD-5 project, preparations on several other new projects are also underway, Lowman said.

The company has also authorized two new drill rigs to drill additional development wells in the Kuparuk River field since the passage of SB 21. One rig started work last May and the second is set to begin drilling in February.

CD-5 is expected to begin producing in late 2015 and is expected to produce about 16,000 barrels per day, or b/d. The project will cost about $1 billion and includes a bridge across a channel of the Colville River and new roads, pipelines and a production site on the west side of the river. CD-5 will be also the first commercial oil production project in the NPR-A.

ConocoPhillips is also laying gravel and making other preparations for a planned new drill-site in the Kuparuk River field, Drill Site 2S. Formal approval for that is expected in late 2014. Production is estimated at 8,000 b/d, starting in late 2015.

Permitting and other preparations are also continuing on GMT-1, a $900 million project in the NPR-A. It is expected to be producing 30,000 barrels per day by late 2017, Lowman said.

Overall, the new projects planned by ConocoPhillips are expected to add 54,000 barrels a day of new production by late 2017 but only part of this is net to ConocoPhillips because some of the new production will be shared with partners in the new projects.

ConocoPhillips owns 55 percent of Kuparuk, with BP, ExxonMobil owning most of the remainder, as well as 78 percent of CD-5 and GMT-1 with Anadarko Petroleum owning the remainder.

The two new NPR-A exploration wells are planned to be drilled in ConocoPhillips’ Greater Moose’s Tooth Unit in which the GMT-1 project is located, Lowman said. The drilling is aimed at establishing new resources in the unit. The company is planning a second NPR-A production project in the unit, GMT-2, sometime in the future, ConocoPhillips officials have said.

Overall, six exploration wells are now planned for the North Slope this winter. Two will be drilled by ConocoPhilllips; three by Repsol in the Colville River delta region and one by Linc Energy at Umiat, in the southeast NPR-A where a small oil field was discovered decades ago but not developed.

ConocoPhillips Alaska president Trond-Erik Johansen told the Resource Development Council annual conference in Anchorage in November that his company plans about $1.5 billion in new capital investments over the next few years.

Separately, BP has announced about $3 billion in new projects in the Prudhoe Bay field along with plans to put two new drill rigs to work in the field.

Read more:

Friday, November 22, 2013

New study recommends state consider equity investment in LNG project

Tim Bradner
Alaska Journal of Commerce

State officials are mulling a plan to take an equity stake in a large Alaska gas pipeline and natural gas liquefaction project.

Such a move could ease fiscal issues that the project sponsors, North Slope producers BP, ConocoPhillips, ExxonMobil, and pipeline company TransCanada have cited. That’s a conclusion of a major study of state royalty issues released Monday.

The state contracted earlier this year with Kansas-based Black & Veatch to do the study. State investment in the project a one major recommendation.

“Having a direct stake could solve a lot of problems for us and the project sponsors,” said state Natural Resources Commissioner Joe Balash in an interview.

“Direct state equity participation in the (gas) project can provide key benefits to the state including alignment of interests (among the parties), transparency through the midstream portion of the supply chain, facilitation of third-party access to the midstream and potentially improved state cash flows along with improved producer economics,” the report said in its conclusions.

Black & Veatch outlined options for the state in improving fiscal terms in its study and said that without changes in the terms, a large LNG project may not be viable.

Balash said one of the biggest problems the companies have with the state’s current terms is the one-eighth royalty share and the state’s ability, under leases held by producers, to switch taking its royalty from in value, or cash payment, to in-kind, or in the form of gas, and to switch back and forth at six month’s notice.

“The sponsors have complained that the present structure has them obligated to finance 100 percent of the project but get only 7/8 of the benefits,” because they have the obligation to ship the state’s one-eighth royalty gas share through a portion of the pipeline they would have to fund.

If the state were to invest in and own a share of the project equal to its one-eighth share, or perhaps as much as 25 percent if the tax obligation was included, it could better align the interests of the parties, Balash said.

The producers and the state would each finance a share of the project sufficient to ship gas each party owns, he said. It would also spread risks, like cost overruns, more equitably.

Black & Veatch said the improved profitability of the overall investments could make the difference in making the project attractive enough for the producers to back it, Balash said.

If the state having a stake in the project solves a problem for the companies, it helps the state with other difficulties, Balash said. As an owner the state would have access to the inner workings of the project finances, which would help ensure the state’s tax and royalty collections wouldn’t be disadvantaged, he said.

Ensuring fair payment for tax and royalty assumed even more importance after the project switched from the original plan for an all-land pipeline to the continental U.S. to a pipeline and a large natural gas liquefaction project serving an export market.

Much of the state’s previous work on royalty terms became obsolete when the plan switched to include LNG, Balash said.

The gas treatment plant and pipeline will be regulated by the U.S. Federal Energy Regulatory Commission as far as tariffs and rates, but not so the LNG plant.

“FERC gives us a transparent process as far as it goes, but the LNG part of the project is more opaque,” Balash said. “The project sponsors are likely to operate this as an integrated venture, so we see opportunities for shifting profits in ways that could not be in our interest.”

Having a seat at the table helps the state solve this, he said.

One problem the arrangement would present, however, is it leaves Alaska with the obligation to market its royalty gas as LNG. That could be more than 1 billion cubic feet a day of gas per day if the state takes a one-fourth share.

Arrangements could always be made with one or more of the producers to market the state’s gas under contract but there would likely be fees associated with this, Balash said. Alternatively the state could set up its own LNG marketing organization, but such a group would always be at a disadvantage in competing for sales with others in the project, like BP and ExxonMobil with long experience in LNG.

Balash said one possible solution could be in working with TransCanada, which is now part of the project group but which does not have its own gas to ship, unlike other parties.

“We could become TransCanada’s customer,” Balash said.

Sunday, November 17, 2013

The water problem; Alyeska Pipeline, North Slope producers work to reduce TAPS freeze-up threat

Wesley Loy
For Petroleum News

With the onset of winter, the operator of the trans-Alaska pipeline system enters another season of challenges to prevent catastrophe due to potential freezing in the line.

Alyeska Pipeline Service Co. is using a range of tactics to avoid a freeze-up, including operations to add heat to the crude oil as it makes the 800-mile journey south from the North Slope.

Another tactic is minimizing the amount of water that’s mixed in with the oil.

In fact, Alyeska “appears to be concentrating on the option of water removal,” said the newly released 2013 annual report from the State Pipeline Coordinator’s Office.

Potential for calamity

In recent years, Alyeska has faced a mounting problem — the decline in the volume of oil moving daily on the trans-Alaska pipeline system, or TAPS.

The pipeline is oversized, having been designed to ship three or even four times the current throughput of around 550,000 barrels per day.

The low flow means the oil moves slower to the pipeline terminus in Valdez.

This means the warm oil is exposed longer to arctic weather conditions in winter. About half the line is above ground.

If for some reason the pipeline must shut down for an extended period, and the oil chills too much, freezing and other problems could develop. Restarting the pipeline could become difficult, if not impossible.

To date, Alyeska has always managed to restart the line promptly after winter shutdowns. But multiday outages following a January 2011 spill at Pump Station 1 caused serious worry about potential freezing and wax buildup severe enough to idle the pipeline until the summer thaw.

Obviously, a shutdown of that duration would be an economic calamity for the state, and a technical nightmare for Alyeska and the North Slope oil producers.

Declining water content

It’s the small amount of water mixed in with the oil that poses much of the freeze-up threat.

Water and natural gas are found naturally with the oil in North Slope reservoirs. Companies also inject water underground to enhance oil recovery.

“Processing plants remove the majority of produced water,” the pipeline coordinator’s annual report said. However, a significant fraction remains. And a bit of sediment, too.

By policy, the TAPS owners aim to limit water and sediment content to no more than 0.35 percent of the crude oil delivered to Pump Station 1.

“However, in recent years the North Slope oil fields have averaged water contents below this limit,” the annual report said. “Reports indicate that the average ... is typically in the range of 0.10 to 0.21 percent.”

In addition, operators have cut the magnitude and number of water pulses, up to 2.5 percent, than can sometimes occur, the report said.

Still, water remains a concern when coupled with the low oil throughput.

As flow decreases and becomes laminar, or less turbulent, water can drop out as the oil and water separate. This can increase internal corrosion, especially at the bottom of the pipe.

Free or fixed ice has potential to cause myriad problems: disabled instrumentation, plugged pump screens, frozen valves and so forth.

Getting it out

So, how can the troublesome water be wrung out of the oil?

“This could involve something as simple as a large tank at PS 1 that allows water to settle to the bottom, where it can be drained,” the pipeline coordinator’s report said. “Reduction of water and sediment content below the current standard might reduce problems caused by ice formation.”

Alyeska spokeswoman Katie Pesznecker told Petroleum News that several technologies for removing water from crude oil are being considered.

“We have conducted tests with static separation in tanks and expect to do so again next summer,” she said.

Pesznecker defined static separation as letting the crude oil “rest” in a tank so separation of oil and water occurs, with the water falling to the tank bottom.

The testing was conducted in existing tanks at Pump Station 1, she said.

The state pipeline coordinator’s annual report said Alyeska would conduct ice studies at the University of Oklahoma.

“Very few facilities have the capability of performing flowing ice studies of hydrocarbon mixtures,” the report said. “The primary focus of this set of investigations is to characterize the rate and volume of ice formation at various water concentrations and the conditions under which ice forms.”

Tuesday, November 12, 2013

Shell files plan; Exploration plan for 2014 drilling in Chukchi goes to BOEM for review

Alan Bailey
Petroleum News

Shell has filed a revised plan for exploration drilling in Alaska’s Chukchi Sea, the company announced Nov. 6. The plan, which the company says “is required to keep the company’s 2014 exploration options viable” and which apparently details the drilling of multiple Chukchi Sea wells, has gone to the Bureau of Ocean Energy Management for review. Shell has no near-term plans for Beaufort Sea drilling.

The company has already contracted the use of Transocean’s Polar Pioneer semi-submersible drilling rig to replace the damaged Kulluk floating drilling platform so that, together with the drill ship Noble Discoverer, the company will have two drilling vessels available for use in the Arctic.

However, the company faces some significant challenges if it is to drill in 2014, given the need to permit all of the vessels in the company’s substantial Arctic drilling fleet before the drilling operations can begin. And, presumably, decisions over mobilizing the fleet will need to be taken long before the drilling season starts.

New rules

Meantime, the Bureau of Safety and Environmental Enforcement, or BSEE, is in the process of preparing a new set of safety rules for drilling on the Arctic outer continental shelf. BSEE spokesman Nicholas Pardi confirmed to Petroleum News in a Nov. 4 email that, despite the recent government shutdown, the agency is still on target for issuing a draft version of the new rules by the end of the year for public review. Issue of the rules in final form will depend on completion of the subsequent public review period and revision of the rules in the light of public comments.

And environmental organizations are busy lining up their opposition to Shell’s plans.

“The specter of Shell planning to move forward in the Chukchi Sea is the scariest Halloween trick yet,” said Susan Murray, deputy vice president, Pacific, for Oceana. “Instead of continuing to ignore risks and pushing to drill, Shell ought to scrap its plans for the Arctic along with the Kulluk … there is no proven technology that would allow companies to drill safely in Arctic Ocean conditions, and the risks far outweigh any potential benefits.”

“Before Shell starts boasting about its new plans for the drilling in the Arctic Ocean, the company should explain why it couldn’t safely conduct its operations under last year’s plans,” said Earthjustice attorney Holly Harris. “Drilling in the Arctic Ocean is just too risky and no company has figured out how to respond to an oil spill in icy waters.”

Read more:

Friday, November 8, 2013

C-P may add 55K barrels/day by 2018

Tim Bradner
Alaska Journal of Commerce

Two ConocoPhillips employees overlook pipelines on the West Sak oil field on Alaska’s North Slope. Projects now in development for ConocoPhillips on the Slope could add 55,000 barrels of production per day by 2018, according to company estimates.

ConocoPhillips is pushing ahead with projects that could add about 55,000 barrels per day of new North Slope oil production by 2018, the company said. This will help dent the current decline in production, which averages about 6 percent yearly, from existing North Slope fields.

The 55,000 barrels per day estimate includes 16,000 barrels per day expected from the new CD-5 project; 8,000 barrels per day from a new drill site in the Kuparuk River field, and 30,000 barrels per day anticipated from a new production site in the National Petroleum Reserve-Alaska.

In addition, a new drill rig put into service in the Kuparuk River field earlier this year has resulted in about 1,800 barrels per day of new production, ConocoPhillips said.

The CD-5 project has been long-planned but work on the other projects was accelerated after the Legislature approved Senate Bill 21, which modified state oil production taxes, ConocoPhillips has said.

BP Exploration, which operates the large Prudhoe Bay field, is also planning new projects in that field.

Construction will begin this winter on the CD-5 project, with Anadarko Petroleum Corp. is a minority owner. Preliminary placement of gravel will also be done this winter for the new drill-site Kuparuk 2-S in the Kuparuk field, ConocoPhillips spokeswoman Natalie Lowman said.

The CD5 construction will span two years, with ice road building, hauling of gravel and bridge construction this winter and completion of the bridge and construction of pipelines and production facilities the following year.

Some additions to infrastructure at the Alpine Central Facility, for the processing of additional oil and gas, will also be required.

The company must still give final approval for construction of the drill site and its related infrastructure. That will be requested of ConocoPhillips’ board in late 2014, Lowman said. BP is also an owner in the Kuparuk field and is a partner in the new project.

At CD-5, contractors will begin mobilizing for construction late this fall. The project involves a bridge over the Colville River, a production pad in the west side of the river as well as related roads, pipelines and utilities.

“Construction of CD-5 is planned to begin in January 2014 and continue in winter 2014-2015. First production is expected in late 2015 and the initial gross production rate is estimated in the range of 16,000 barrels per day,” of oil, Lowman wrote in an email.

CD-5 will be the first commercial oil production from the NPR-A. The small field is west of the producing Alpine field, which is on state of Alaska lands, but because CD-5 is on the west side of the Colville River it is within the federally-owned NPR-A.

ConocoPhillips has also released cost and production estimates for the Kuparuk 2S drill site which is in the southern part of the Kuparuk River field, and the GMT-1 project in the National Petroleum Reserve-Alaska.

Kuparuk 2S is planned for construction in late 2014 with first production is expected in 2015. Costs are estimated at $595 million and peak production is expected to be 8,000 barrels per day.

The GMT-1 project in the petroleum reserve is estimated to cost $890 million to develop and is expected to produce 30,000 barrels per day with first production in 2017, Lowman said.

GMT-1 is within the Greater Moose’s Tooth Unit a few miles further west in NPR-A, and would be the second oil producing project within the reserve.

ConocoPhillips is the operator and majority owner of GMT-1 and CD-5 with 78 percent interest, with Anadarko owning a 22 percent interest.

The 30,000 barrels-per-day estimate for GMT-1 represents an increase over earlier estimates of its potential production. In a 2011 presentation to financial analysts in New York the company had put the production estimate at 15,000 barrels per day to 20,000 barrels per day.

Lowman would not comment on the revised estimate but said 30,000 barrels per day is the number the company is now working with.

CD-5 and GMT-1 will provide the first oil produced on a commercial basis from NPR-A but gas has been produced for several years at Barrow, in the far northern part of NPR-A. The gas field there is owned and operated by the North Slope Borough, the regional municipality.

It supplies Barrow Utilities, the local electric and gas co-op, which serves the Inupiat community of Barrow.

The 23-million-acre NPR-A covers the western part of the North Slope. It was created as a naval petroleum reserve in 1923 but did not see exploration until the 1950s and 1960s, which resulted in the gas discovery at Barrow and an oil discovery at Umiat, in the southeast part of the reserve.

The Umiat discovery was not economic when it was found but Australian independent Linc Energy began drilling last winter to delineate the field and will continue this winter. Linc hope to eventually produce 50,000 b/d from Umiat.

Meanwhile, CD-5, near the Alpine field, is within the federal reserve but the subsurface mineral rights are owned by Arctic Slope Regional Corp. of Barrow. That means ASRC will receive royalties from production at CD-5. Under terms of the Alaska Native Claims Settlement Act of 1971, the federal law under which ASRC onbtained the mineral holdings, 70 percent of the royalties must be shared with other Alaska Native corporations.

Also, Kuukpik Corp., the village corporation for Nuiqsut, the nearest Inupiaq community, is reported to hold a small overriding royalty interest in ASRC’s royalty share of the CD-5 subsurface, but the details of that are confidential.

ASRC also owns some mineral rights on state of Alaska leases on the Alpine field, which in the Colville River delta east of the NPR-A.

Third quarter earnings down vs. 2012

ConocoPhillips earned $494 million from its Alaska oil and gas production in the third quarter of 2013, the company announced Oct. 31. This is down from $585 million in earnings in the second quarter, mainly due to lower oil production.

The company’s Alaska production was down about 20,000 barrels per day during the quarter, much of its due planned turnarounds at its Prudhoe Bay and Kuparuk River fields and the natural decline of aging oil fields.

Production averaged 178,000 barrels per day in the third quarter, down from 197,000 barrels per day in the second quarter. However, ConocoPhillips’ third quarter production was roughly on par with third quarter 2012 with 176,000 barrels per day in production. Its net income for Alaska was down 7.6 percent, from $535 million to $494 million, compared to the 2012 third quarter while its overall net income as a company increased 7 percent in the same period.

ConocoPhillips is the only Alaska oil and gas producer that breaks out its Alaska earnings separately when it issues a financial report for worldwide activities.

As has been the case in previous quarters the company paid nearly twice as much in government taxes and royalties than it earned. Total taxes and royalties were about $900 million in the third quarter, with about two-thirds of this, or $652 million, paid to the State of Alaska during the third quarter.

“As we have reported historically, under the ACES production tax regime we pay almost twice as much in taxes and royalties as we keep,” said Bob Heinrich, ConocoPhillips’ Alaska vice president for finance.

“The recent oil tax change passed by the Legislature, with Senate Bill 21, improves the business climate in Alaska. As a result of these improvements we are now looking forward to increasing our North Slope investment.”

Alaska is a significant source of income for ConocoPhillips because most of the company’s earnings in the state are from crude oil, while in the Lower 48 states a good portion of income is from natural gas, which has experienced low prices.

Still, the company’s Lower 48 oil producing fields have seen significant increases in production, up 54 percent in the third quarter, compared with a 15 percent decline in Alaska oil production.

The figures are from ConocoPhillips’ presentation to financial analysts on Oct. 31.

Tuesday, November 5, 2013

Tesoro takes over; Refiner seeks right of way for new $50 million oil pipeline across Cook Inlet

Wesley Loy
For Petroleum News

Construction of a new subsea pipeline to carry crude oil across Alaska’s Cook Inlet now appears imminent.

Tesoro, which operates a refinery at Nikiski on the inlet’s east side, has assumed control of the project. The concept had originated with Cook Inlet Energy LLC, a westside oil and gas producer.

On Oct. 23, the newly incorporated Trans-Foreland Pipeline Co. LLC submitted an amended pipeline right-of-way lease application to the Alaska Department of Natural Resources. State records show the company has an address in San Antonio, Texas, where Tesoro is based.

Tesoro Alaska Co. is shown as the 100 percent owner of Trans-Foreland Pipeline Co. Three company managers are listed: Charles S. Parrish, G. Scott Spendlove and Gregory J. Goff.

The application package indicates a great deal of planning work has gone into the proposed $50 million pipeline. Project construction is scheduled to start in February and run through October.

Need for pipeline

Oil production peaked in Cook Inlet long ago, and the Tesoro refinery has been in operation since 1969.

It might seem curious, then, why a bold new pipeline is planned now.

Project backers cite a number of compelling reasons. First, the pipeline could eliminate risky tanker runs across the icy, turbulent inlet. Second, the line could provide westside oil producers a reliable alternative to the Drift River terminal where tankers load. Flooding from eruptions of the nearby Redoubt volcano in 2009 knocked the terminal out of service, hampering oil production for months.

A third benefit from the pipeline is potentially lower oil transportation costs.

The proposed pipeline, 8 inches in diameter, will have a design life of 30 years and a capacity of 62,600 barrels per day, the right-of-way application says.

The sponsors believe the project “will need to attract shipping commitments of approximately 4,000 bbls per day to make the tariff competitive with the existing CIPL system,” the application says. “However, given the increased operational reliability and environmental benefits offered by this line the project may be viable at lower throughput levels.”

CIPL is Cook Inlet Pipe Line Co., the Hilcorp subsidiary that operates Drift River terminal and related pipelines.

U-shaped route

It was Cook Inlet Energy that, in November 2012, filed the initial application to DNR for a right of way for the Trans-Foreland Pipeline. Cook Inlet Energy sells its oil to Tesoro.

The project takes its name from the fact that the pipeline will run between the West Foreland and East Foreland points on either side of the inlet.

The pipeline will begin at Cook Inlet Energy’s Kustatan production facility, which processes oil from the company’s offshore Osprey platform. The line will end at the tank farm at the Tesoro refinery.

The pipeline won’t run straight across the inlet. Rather, it will loop south and then north, coming ashore below Nikiski. From there the line will run, buried, along the Kenai Spur Highway to the Tesoro tank farm.

Laying the pipeline in a U-shaped configuration will make construction easier.

“The forelands represent the narrowest part of Cook Inlet and have high currents and a deep trench,” says a project description prepared by Michael Baker Jr. Inc.

The selected route will “minimize tidal stresses on the pipeline and avoid water depths greater than 200 feet, the maximum depth for safe operation by marine divers,” the project description says, adding the pipeline route doesn’t cross any seismic faults.

The underwater segment of the pipeline will run about 22 miles. Counting the onshore bits on either side, the line will run a total of 29 miles.

130 construction jobs

The right-of-way application estimates the cost of materials at $15 million, and the cost of construction at $35 million.

The estimated annual cost to operate and maintain the line is $5.2 million.

The project is expected to generate 130 construction jobs. A dozen people, eight in the field and four in the office, will be needed to operate and maintain the pipeline, the application says.

Two contractors are being considered for pipeline installation: Price Gregory and CONAM Construction, and NANA Construction.

A lay barge will install the subsea pipe, the application says. Most of the in-water construction work is scheduled for May and June, prior to the commercial salmon season. This is also a timeframe when annual tidal velocities are lowest, and beluga whales are out of the area.

The pipeline will rest anchored on the seafloor, and will be buried where conditions allow subsea trenching.

The pipeline will have a number of safety features including a leak detection system. It’ll accommodate smart pigs, devices that slide through a pipeline to test for problems such as corrosion. An epoxy coating on the pipeline, plus cathodic protection, will provide further defense against corrosion. The pipeline wall will be half an inch thick.

Most of the pipeline route crosses state lands. DNR’s State Pipeline Coordinator’s Office has set a Dec. 31 deadline for submitting written objections to the requested pipeline right-of-way lease.

Read more:

Saturday, October 19, 2013

Repsol plans: three more wells, three more rigs

Tim Bradner
Alaska Journal of Commerce

Repsol will drill three North Slope exploration wells this winter as part of its multi-year program to evaluate the company’s acreage, company officials said in an interview Oct. 11.

Two of the wells, designated Q-5 and Q-7, will be in the Colville River delta area east of the producing Alpine field. They are in the vicinity of wells drilled last year by Repsol and where discoveries were made, said Repsol Alaska Manager Bill Hardham.

A third well, named Tuttu 1, is further east near the Kuparuk River field, Hardham said. Tuttu is “caribou” in the Inupiat language

Spain-based Repsol is one of the most active exploration companies in Alaska. This coming winter season will be the company’s third year of drilling.

Two of the wells to be drilled in the Colville delta are to gather more information on oil and gas resources near wells drilled last year that were discoveries. Those were designated as Q-1, Q-3 and Q-6, he said.

Repsol has not yet announced a decision on the commerciality of those discoveries, Hardham said. Oil was also found in a third well Repsol drilled last year that was farther south.

“We are busy with this and we are working up some development scenarios. The wells we’ll drill this year will add to our information,” about the area, he said.

The company is still working on its drilling contracts but tentative plans are to use three Nabors Alaska Drilling Co. rigs for the winter season. A winter ice road will be constructed to the exploration area from the Kuparuk field roads, which are all-year gravel roads, and an ice airstrip and winter camp facility will be built near where the drilling will take place.

The exploration in the Colville delta is focused on conventional oil.

Several companies besides Repsol have been exploring in the area west of the Kuparuk field. One other firm is Brooks Range Petroleum, an Alaska-based independent that has been working in the area for several years and is now planning development of one discovery, “Mustang.”

Brooks Range hopes to have Mustang in production in 2015, according to the company’s Chief Operating Officer Bart Armfield. The company is working with the Alaska Industrial Development and Export Authority, the state’s development finance corporation, on an oil and gas processing plant for Mustang. Infrastructure to support the plant would also be available for other parties, according to the plan being discussed.

Meanwhile, one uncertainty affecting Repsol’s planning as well as that of other companies is a pending referendum in the 2014 Alaska primary election that would repeal a reduction of state oil production taxes approved by the Legislature earlier this year, Repsol spokeswoman Jan Sieving said.

Repsol supported the passage of the tax bill, Senate Bill 21, and is moving forward with its exploration, but the pending vote does create additional uncertainty, Sieving said.

“We are fully supportive of SB 21 and have started moving forward with investment decisions, but the referendum now adds to uncertainties. It’s difficult to make billion-dollar decisions when we don’t know what the tax structure will be,” Sieving said.

Wednesday, October 16, 2013

New crude crossing; Report says construction could begin within months on inlet subsea pipeline

Wesley Loy
For Petroleum News

Construction of a new subsea crude oil pipeline across Cook Inlet could begin as soon as 2014.

That’s the word from the Cook Inlet Regional Citizens Advisory Council, a congressionally sanctioned organization that monitors oil industry activity in the inlet.

“Cook Inlet RCAC has been informed that Tesoro is considering the installation and operation of a trans-Foreland subsea pipeline to transport crude oil from the west side of Cook Inlet to Tesoro’s refining facilities in Nikiski,” the council reported in its October newsletter. “Although still in the planning stages, all indications are that this pipeline is going to be built and construction could begin as early as spring 2014.”

Cook Inlet Energy’s idea

This news seems to build on a proposal that first emerged more than a year ago from Cook Inlet Energy LLC, a west side oil and gas producer. The company had said it was pursuing a 29-mile, $50 million subsea pipeline from its Kustatan production facility near West Foreland point to the Tesoro refinery near East Foreland point. That explains its name — the Trans-Foreland Pipeline.

Cook Inlet Energy is a subsidiary of Tennessee-based Miller Energy Resources Inc.

In January, Miller said Tesoro had agreed to fund up to $1.4 million in design costs for the proposed pipeline.

Petroleum News was unable to reach representatives of Tesoro and Cook Inlet Energy for comment.

Advantages of subsea line

As it stands, crude oil produced on Cook Inlet’s west side is shipped out via tankers. The inlet’s enormous tides and dangerous drifting ice add extra risk to the inlet crossings.

“Cook Inlet RCAC is very supportive of Tesoro’s proposed project,” the council said in its newsletter. “With the installation of the crude oil pipeline, there will be an alternative means of transporting crude oil from Cook Inlet’s west side facilities. We will continue to advocate for the installation of the pipeline and Tesoro has been invited to present their plans and status of the project at the Council’s Board of Directors December meeting in Anchorage.”

Cook Inlet Energy has said a subsea pipeline could offer other advantages, such as reduced oil transportation costs.

Another concern is the threat that nearby Redoubt volcano poses to the Drift River oil terminal, where tankers load. Eruptions in 2009 knocked the terminal out of service and idled oil production on the inlet’s west side for months.

The Cook Inlet RCAC said it had been in contact with Cook Inlet Energy and also Hilcorp Alaska, a major inlet oil producer. Hilcorp “has indicated that they are awaiting additional information before committing to utilizing the pipeline,” the council newsletter said.

The newsletter further said that two consultants, Glosten and Northern Economics, have been engaged to do a cost-benefit analysis of the cross-inlet pipeline.

Read more:

Sunday, October 6, 2013

State makes deal to sell royalty oil to Tesoro

Tim Bradner
Alaska Journal of Commerce

The Tesoro refinery near Kenai will purchase 5,000 to 15,000 barrels per day of Alaska royalty oil in an agreement reached with the Division of Oil and Gas. Deliveries will begin Feb. 1, 2014, and the contract runs through Jan. 31, 2015.
The state of Alaska has reached agreement with Tesoro Petroleum Corp. to sell 5,000 barrels per day to 15,000 barrels per day of state royalty crude oil from the North Slope for the company’s Alaska refinery near Kenai.

Notice of the sale, in a state Best Interest Finding document, was published on the state Division of Oil and Gas website.

Kevin Banks, chief of the commercial division in the state Division of Oil and Gas, said deliveries are to begin Feb. 1. The contract will end Jan. 31, 2015.

Tesoro’s refinery has a total capacity to process 72,000 barrels per day of crude oil but in practice processes less than that, about 65,000 barrels per day in summer, a period of high gasoline demand, and about 45,000 barrels per day in winter.

The sale will not require approval of the state Legislature because the quantities of royalty oil being sold are below the threshold requiring an OK by legislators.

Last spring the Legislature approved a larger royalty oil sale to Flint Hills Resources for that company’s refinery near Fairbanks.

The Tesoro agreement followed an informal solicitation of interest for purchases the state conducted last fall, Banks said. There were four responses, two from North Slope producers BP and ConocoPhillips, one from Flint Hills Resources and one from Tesoro. Petro Star Inc., which also operates refineries near Fairbanks and Valdez, did not respond.

Alaska has the option of taking its royalty share of oil and gas produced on state-owned leases in kind, in delivery of actual oil and gas, or in value, or payments in cash.

Traditionally the state has taken much of its oil royalty in kind, about half, to ensure that in-state refiners have a supply of crude oil.

“Some portion is always taken in value, in payments by producers, so the state has an indicator of market value to establish values for payment by refiners for royalty oil,” Banks said.

If both Tesoro and Flint Hills take the maximum amount of royalty oil their contracts allow, about 95 percent of the state’s royalty oil would be sold to the in-state refiners.

Royalties from state leases typically vary between one-eighth and one-sixth of production, although there are some leases with higher royalty rates.

Pricing terms on the Tesoro contract are similar to those in the Flint Hills contract, and are based on average west coast sales prices for North Slope crude with transportation costs subtracted.

The transportation deduction from the west coast Alaska North Slope crude price for Tesoro is $1.95 per barrel, which is the estimated difference between the west coast price and Valdez after transportation costs are accounted for. The Best Interest Finding said the state will earn a small premium on the royalty sale compared with what would have been paid by North Slope producers had the royalty been taken “in-kind,” or in cash payment.

If market price conditions between 2008 and 2012 continue through the contract period, the premium would be about 25 cents per barrel, the Best Interest Finding said.

Under state royalty sales contracts, the purchaser takes delivery of oil on the North Slope and makes arrangements for shipping with a Trans-Alaska Pipeline System owner.

To get the oil to its Kenai refinery, Tesoro uses a small shuttle tanker used now for Cook Inlet crude oil deliveries, to get oil from Valdez, in Prince William Sound, to Kenai.

Tesoro now purchases about 90 percent of its crude oil requirements from Cook Inlet and North Slope producers but has imported crude in the past. In 2012, the company imported three cargoes of foreign crude oil, according to the state Best Interest Finding.

The Kenai refinery was originally built to handle light Cook Inlet crude oil but as oil production from the Inlet declined over the years crude has had to be purchased elsewhere.

North Slope crude is heavier than Cook Inlet oil, which required Tesoro to import some lighter oil from foreign sources including at times Sakhalin, in Russia’s Far East, which has lighter crude.

Tesoro’s refinery supplies products to 31 company-owned Alaska retail outlets and 44 “branded” outlets operated by franchise owners, according to the Best Interest Finding document.

Read more:

Saturday, September 21, 2013

Utilities, state say $1B needed for grid upgrades

Tim Bradner
Alaska Journal of Commerce

The $359 million, 180-megawatt Southcentral Power Project owned by Chugach Electric Association and Municipal Light and Power held its grand opening earlier this year. The project is part of more than $1 billion in upgrades either under construction or completed in the regional electric grid.

Electric utilities in the Interior-Southcentral region known as the “railbelt” are studying plans for $1 billion in necessary upgrades to the regional electrical grid. This is on top of $1 billion in new power generation plants that have been built or are under construction, state and utility officials told an energy conference Sept. 16.

“The generation system is keeping pace with growth, but the transmission system is not,” Gene Therriault, deputy director of the Alaska Energy Authority, told the World Oil and Gas Congress meeting in Anchorage.

Matanuska Electric Association General Manager Joe Griffith said there are bottlenecks in a creaky transmission system.

“We can get power through the system, but not always when it is needed,” to allow utilities to optimize and run equipment most efficiently, he said.

Therriault cited an example with Golden Valley Electric Association, in the Interior.

“GVEA owns a share of Bradley’s (hydro) power but it can’t get it when it needs it,” to offset high-cost power, he said.

About $402 million in upgrades are needed in the southern part of the railbelt power grid, from Healy to Homer, and about $481 million in improvements are needed on the northern end, from Healy to Fairbanks. Another $20.5 million in projects are also needed in the Anchorage area.

The projects, and costs, are outlined in a consultant study completed in May 2013 for the AEA.

Therriault said the energy authority is discussing a plan for the utilities to finance the upgrades with debt, possibly revenue bonds sold by AEA’s sister agency, the Alaska Industrial Development and Export Authority, or AIDEA. That agency has new authority to finance energy projects and infrastructure with long-term, low-interest debt.

Despite the costs, the benefits of improving the system will be considerable for ratepayers, ranging from estimates of $146 million per year to $241 million per year.

The estimates assume the upgrades are funded with 30-year debt at 5 percent, and no direct financial contribution from the state.

Decisions on the upgrades will likely include an agreement among the utilities for a single system operator to coordinate the dispatch of power through the grid, he said.

Hopes are the plan can be agreed on by the end of the year, Therriault said, so that legislators can be briefed when the Legislature convenes its annual session in January.

If the planned large hydro project is built at Watana, on the upper Susitna River, its power cannot be efficiently distributed until the transmission system is upgraded, Therriault said.

Griffin said the transmission upgrades are really the unfinished business of agreements by the state and railbelt utilities in 1985 to finance the Bradley Lake hydro project near Homer. The dam was built, but oil prices, and state revenues, unexpectedly plunged, so the transmission upgrade to go with Bradley Lake was never finished.

“It was left to finish later at a far higher cost,” Griffin said.

The utilities have stretched their wallets with hefty expenditures on new power plants.

“We are out of debt capacity,” he said. “The state will have to help us.”

Consumers will ultimately pay for the new generation upgrades and, if it is financed with bonds, the transmission upgrades, through higher rates to pay off the debt.

Read more:

Friday, September 6, 2013

Pioneer sees good results from North Slope fracturing wells

Tim Bradner
Alaska Journal of Commerce

Pioneer Natural Resources is pleased with results of its large-scale fracturing of producing wells at the Oooguruk field on the North Slope.

Three producing wells were fractured in the first half of 2013 with production doubling in two wells and tripling in a third.

“We’re very pleased with the results, and we plan to fracture four more wells next year,” Pioneer spokesman Casey Sullivan said Aug. 30.

The three production wells were fractured following a successful test fracturing in late 2012 in a production test of an exploration well near Oooguruk.

The production figures were presented by Pioneer to financial analysts Aug. 1, Sullivan said.

All three wells are producing from the Nuiqsut formation, one of two formations that are tapped at Oooguruk.

Prior to fracturing, the Oooguruk wells produced in the range of 500 barrels per day to 800 barrels per day. Following the fracturing, two of the wells fractured in the early spring increased output to an average of 1,500 b/d and a third well fractured in late spring increased output to 3,000 b/d and sustained the rate for 40 days, according to information presented to analysts. The well is currently shut-in for maintenance.

A 2012 test of large-scale fracturing on a test well drilled into the Torok formation, which Pioneer hopes to produce from in its planned Nuna development.

The well flowed at 2,800 b/d, according to data given the analysts. Nuna is a potential new project near Ooguruk that is onshore, in the Colville River delta northeast of ConocoPhillips’ producing Alpine field.

Ooogouruk is owned 70 percent by Pioneer and is field operator, with 30 percent owned by Italian major Eni. The field produced 4,000 barrels per day net to Pioneer in the second quarter of 2013, according to the information presented to analysts.

Nuiqsut formation wells have had mixed results at Oooguruk, while production from the Kuparuk and Torok formations, being produced, has met expectations, a Pioneer official told a meeting of the Alaska Geological Society last April. The Ooogurk field is offshore, in shallow water, just north of the shore and Nuna’s location. Pioneer will make a decision on whether to develop Nuna later this fall, Sullivan said.

Smaller-scale fracturing has been done for years in North Slope fields but Pioneer’s tests were the first large-scale, multi-stage fracturing jobs. The company adapted the technique from similar procedures used by Pioneer in drilling of wells in the Eagleford shale and similar formations in Texas.

Read more:

Wednesday, September 4, 2013

I'm going to make this place (Alaska) your "home"

Deborah Brollini
Alaska's Energy Diva

One thing I have most enjoyed about my Thoughtful Thursday outreach has been spending time with Alaska’s youth, and young people. Their energy, and optimism is infectious. We could learn a lot from them if we would just get beyond our own baggage and opinions.

Our children continue to charge on in life with cheerful and generous hearts despite the painful world we have left them. This generation has witnessed evil to its highest degree and they have chosen to be joyful, dream, and be optimistic about their futures.

My daughter’s best friend’s father passed away last year, and she does not have a chip on her shoulder. She is a child, a senior in high school, and she continues to work everyday to contribute to her family, DREAM of college and “getting the heck out of here.” She has not allowed the loss of her father stop her from pursing her dreams. I’m not sure this young woman knows that I will move heaven and earth to make her dreams come true. This kid has a grownup in her corner.

It is a sad that we the grownups of the world sit around shaming each other because we want to be right rather than reaching out to find common ground and find solutions. We owe it to our youth to put our big boy shorts and big girl panties on and start acting like the grownups that we are.

I attended the Phillip Phillips concert on Monday surrounded by youth and American Idol fans. I am always amazed how music can bring people and generations together. My daughter bought me tickets to the concert for Mother’s Day. She knew I loved this kid because he is talented, grounded, and committed to excellence. My daughter may never know why I listened to “Home” thousands of times… over, and over, and over again. I listened to keep me focused and to keep Alaska her “home."

I hope our young people keep ignoring us, and keep on dreaming BIG! ________________________

Thoughtful Thursdays Alaska

Organizing for Alaska

Saturday, August 31, 2013

Former Governor Frank Murkowski steps in to meet with REI

Tim Bradner
Alaska Journal of Commerce

A former Alaska governor has stepped in to smooth over a potential diplomatic faux pas that might have impaired a Japanese initiative to invest in a North Slope liquefied natural gas export project.

Former Gov. Frank Murkowski offered to host the visit by Gov. Toshitami Kaihara, the former governor of Hyogo Prefecture in Japan and a key figure in the formation of a Japanese group interested in Alaska LNG, after Gov. Sean Parnell declined a meeting.

Resources Energy Inc., or REI, is a Japanese consortium of municipalities and business groups formed to find an independent source of LNG. The group opened an office in Anchorage a year ago.

In Japanese business and diplomatic protocol, declining such a meeting is considered a snub, particularly after Parnell met with the president of KoreaGas, a competitor to the Japanese in purchasing LNG, earlier this year.

“The Japanese tradition is to want to shake hands with the top guy. I’m not sure Parnell understands that,” said Murkowski, who helped organize a reception for Kaihara Aug. 20 at the Petroleum Club in Anchorage. “I was glad to step in to accommodate these visitors when our governor had other commitments.”

Murkowski is an old hand in Asian affairs, having chaired the U.S. Senate’s Foreign Relations Committee’s East Asia subcommittee for years while he was in the Senate.

There may have been more to Parnell’s declining the meeting than just diplomatic naïveté, however.

The problem may be Kaihara’s relationship with REI, and it tends to fit a standoffish attitude the governor has exhibited, on several levels, since REI announced its desire to pursue an Alaska LNG project separate from the project North Slope producers BP, ConocoPhillips and ExxonMobil and pipeline company TransCanada are working on.

Kaihara wanted to stop in Alaska on a trip back to Japan from Washington State to pay a courtesy call on Parnell on July 20, with officials from REI also attending. Ironically, Washington State Gov. Jay Inslee met with Kaihara in Seattle — the occasion was the 50th anniversary of a sister-city alliance between Seattle and Hyogo Prefecture — and made the former Japanese governor an honorary Washington State citizen.

Such things are important in Japanese business and government protocols.

Although the request to meet with Parnell was made July 10, the governor declined the appointment with Kaihara, citing schedule conflicts. The governor’s office offered a meeting with Deputy Natural Resources Commissioner Joe Balash as a substitute.

Kaihara did wind up meeting with Balash, and Murkowski organized a private meeting with ConocoPhillips officials. Other Alaska business leaders attended the Aug. 20 reception hosted by Alaska Nippon Kai, a Japan-Alaska business association. Later in the week Kaihara met with Lt. Gov. Mead Treadwell.

Treadwell, who has extensive Asia business experience, was unable to attend the reception but did send a letter welcoming Kaihara.

The sting of being turned down by Parnell was eased, although not completely.

Parnell spokeswoman Sharon Leighow downplayed the issue.

“Look, we can’t accommodate everyone who wants to meet with the governor,” she said.

As a follow-up, Leighow provided a written statement.

“Japan continues to be a major trading partner with Alaska and the governor appreciates our long-standing, respectful relationship with the Government of Japan,” Leighow wrote. “In the past year, Gov. Parnell has met with government officials of Japan as well as senior executives in Japan’s energy, utility and mining companies,” including REI officials.

Leighow also said Alaska Natural Resources Commission Dan Sullivan has met with REI president Shun Shimizu several times during visits to Alaska by Shimizu and REI’s technical team.

On those earlier visits, Shimizu had asked to meet with Parnell, but those meetings were also declined.

Leighow said there were other reasons contributing to Parnell’s decision not to meet with Kaihara but did not explain what they were. Some of it would be explained in emails the governor’s office had received from REI, she said, but the governor’s office could not provide the emails to the Journal unless a Pubic Records Act request was filed.

The Journal filed a Public Records Act request on Aug. 22, but as of Aug. 28 the emails had not been provided.

A source familiar with the proposed LNG export project, asking not to be identified, said he was struck by Parnell’s position.

“This is just plain rude. These kind of meetings are mostly ceremonial and when you’re governor this goes with the job,” the source said. “Someone comes in from overseas who wants to invest, and you shake their hand and tell them they are welcome.”

Parnell’s reluctance to meet with REI officials, most recently with Kaihara, may be rooted in a concern that such a meeting, even if only as a courtesy, might be interpreted as some form of state endorsement of REI’s independent LNG initiative.

The governor may also be concerned that the North Slope producers and TransCanada might interpret such meetings as the state’s flirting with potential competitors, and might use that as an excuse to ease off on efforts to advance their own project.

Parnell has been pushing the Slope producers and TransCanada to show signs of progress on an LNG export project, and expressed displeasure in June when the group failed to meet a key benchmark the governor had laid down: a commitment to begin Preliminary Front-End Engineering and Design work, a key step in the project.

Nuclear fallout

REI’s initiative is somewhat different than that of the producers and TransCanada, however.

For one thing, REI is not yet an actual customer for LNG, but is a startup company formed by Hyogo Prefecture and a group of Japanese technology firms who are anxious, following the near-total shutdown of Japan’s nuclear power industry, to develop their own, direct sources of imported LNG and not have to depend on Japanese LNG imports dominated by major Japanese companies like Tokyo Gas.

The company is an entrepreneur in the field, in other words. If the Alaska project appears possible, REI and its managers, mostly retired senior Japanese executives in the LNG business, would move to expand REI with additional Japanese municipal governments and regional industries, as well as utilities, who want their own direct sources of LNG.

While the company would like a State of Alaska endorsement, it would settle for some form of recognition by the state, REI has said in the past. This is still seen as important in Japan’s business culture given the importance of cooperation by governments in international trade.

To that end, REI asked for a “Memorandum of Understanding” with the state in mid-2011 that would lay out how the state would offer cooperation and an MOU was agreed to and finally signed last December after extended discussions. But rather than the MOU being signed by a senior state official like DNR Commissioner Sullivan, it was signed by a middle-level official, then-state AGIA Coordinator Curt Gibson. MOUs like this are typically symbolic. A previous MOU signed by the state with the Alaska Gasline Port Authority was signed by state commissioners Tom Irwin of DNR and Pat Galvin of the Department of Revenue.

However, the MOU offered REI enough encouragement that the company proceeded with a $20 million initial feasibility study of an independent LNG project in Southcentral Alaska and the marine shipping of LNG to Japan, REI Vice President Mary Ann Pease said.

The study was concluded last April, and while the results are confidential they were promising.

Among other things, the study showed LNG could be shipped to Japan for about $1 per million British Thermal Units, half to one-third of the shipping cost from competing sources of LNG to Japan, Pease said.

REI rebuffed

Meanwhile, the state administration has also been slow to sign a long-pending MOU with the Japan Bank for International Cooperation, or JBIC (formerly the Export-Import Bank of Japan), Japan’s government investment group that is interested in whatever REI might be able to do in Alaska.

The arms-length attitude toward REI was illustrated on another level. The state’s Alaska Gasline Development Corp., AGDC, declined REI’s request in June to establish a confidentiality agreement, as allowed under House Bill 4 approved by the Legislature earlier this year.

A June 18 letter written to REI President Shimizu by Dan Fauske, CEO of the state gas corporation, said, “we have concluded that, due to current law and contractual obligations between the state of Alaska and the AGIA licensee (TransCanada Corp.) AGDC cannot participate in further discussions with REI.”

A key point of concern for AGDC, the letter indicated, was REI’s request to work with the state corporation on shipping 750 million cubic feet per day of gas, which is beyond the limit of 500 million cubic feet per day allowed for AGDC under the state’s agreement with TransCanada.

In an interview, Fauske said he was told by the Department of Law not to sign a confidentiality agreement with REI even though HB 4 now gives the state corporation the authority to do so for commercial discussions.

Despite the terse wording of the June 18 letter, which Fauske said was suggested by state attorneys, “the door is always open” at AGDC for REI or other potential customers for the state-backed pipeline, Fauske said.

Fauske and other AGDC officials also met with Shimizu and others in the visiting Japanese group August 23 to smooth over any misunderstanding about the June letter. Fauske also said he urged REI to participate in an open season for gas shipments that AGDC plans in late 2014 or early 2015.

Pease attended the meeting.

“We indicated that we were willing to start off with a small plant, in the range of 200 million cubic feet per day, which is well below the 500 million cubic feet per day legal limit imposed by AGIA,” she said.

“Even without a confidential agreement, my specific request at the meeting was that REI be included in the list of potential industrial customers who could be anchor customers for an AGDC pipeline. We did not get an answer to that.”

But, because of the inability to sign a confidentiality agreement, REI cannot share any data from its feasibility study on an LNG project with AGDC, which is unfortunate, she said.

Murkowski, in an interview, said he was concerned that REI’s initiative is being given short shrift not only by the current state administration but also the producer-led LNG group.

“I’m concerned over the lack of willingness to really evaluate what these people have to offer,” the former governor said. “Here the Japanese are coming in with a willingness to spend their own money and are not asking for anything,” in the form of a state subsidy.

Murkowski contrasted that to the producers’ and TransCanada’s project where the state is chipping in $500 million at a 90 percent cost reimbursement rate under TransCanada’s AGIA (Alaska Gasline Inducement Act) license, funds that are now being shared with BP, ConocoPhillips, and ExxonMobil as well as TransCanada, he said.

“There seems to be a presumption that only the producers can develop this project and monetize the gas,” Murkowski said. “That may be the case, but here we have people with different ideas who are willing to invest in a project and buy state royalty gas at the wellhead,” to transport it through a pipeline.”

Murkowski said he doesn’t understand why Parnell recently extended the state’s contract with TransCanada, which includes the subsidy, and he faults Parnell for not explaining why he felt the extension was necessary.

“I feel the governor is really exposed on this, by not explaining to the public what we’re getting for our money,” Murkowski said.

Read more:

Wednesday, August 21, 2013

Facing a headwind; Schutt describes the challenges for independent power producer in Alaska

Alan Bailey
Petroleum News

The saga leading to the implementation of Cook Inlet Region Inc.’s Fire Island wind farm, offshore Anchorage, was marked by a sometimes acrimonious debate between the Alaska Native Corporation and its potential power utility customers over issues such as the ease or difficulty of integrating fluctuating wind power into the Alaska Railbelt electricity grid. But were these technical bones of contention the symptoms of some deeper issues regarding the place of independent power production in the Railbelt energy scene?

Cook Inlet Region Inc., or CIRI, funded the Fire Island wind farm as a private project, with the intention of selling power to Railbelt power utilities. But when the wind farm went on line in 2012, CIRI only had one wind power customer — Chugach Electric Association — and the farm itself was smaller than the Native corporation had originally planned.


On July 31 Ethan Schutt, CIRI’s senior vice president for land and energy, told the International Association for Energy Economics’ North American conference about some of the hurdles that the Fire Island project had faced. Characterizing the hurdles as interactions with government, Schutt said that Alaska has no formally recognized space for independent power producers.

“If you want to be an independent power producer in Alaska, you’ve got to make your own space, because it doesn’t exist,” Schutt said.

Early on in the Fire Island project, given this lack of commercial space in the power market, CIRI was faced with something of a Hobson’s choice in having to decide whether to go through the tortuous and risky process of trying to be legally recognized as a regulated power utility, or whether to seek a state government exemption from regulation, allowing the wind farm to operate as an independent power producer. In the event, CIRI opted for that latter course, persuading the state Legislature to pass legislation allowing the corporation to sell power, albeit on a relatively small scale, only from a renewable energy source, and only to regulated utilities, Schutt said.

De-facto government

As CIRI’s project moved forward, the corporation came to the realization that all six of the Railbelt electricity utilities, the wind farm’s potential customers, are either government organizations or de-facto government organizations, Schutt said. Two of the utilities are directly owned by municipalities, while the other utilities are vertically integrated customer-owned cooperatives, operating as monopolies within government-granted, certificated geographic regions, he said. Beyond periodic rate cases, in which the Regulatory Commission of Alaska reviews and approves the rates that the utilities charge their customers, the utilities are largely free to act as they see fit within their certificated areas, Schutt said.

At the same time, although the state has set a target of obtaining 50 percent of Alaska electricity from renewable energy source by 2025, there are no formal incentives, regulatory requirements or public support for the independent production of renewable energy, Schutt said. There is a renewable energy grant fund, but there are no market-based mechanisms for facilitating change, he said.

And while most if not all of the commercial-scale power transmission infrastructure in Alaska is either built or substantially funded by the state, the state exerts very little operational control over the infrastructure and over market access to that infrastructure for private enterprise, Schutt said. Compounding this phenomenon and distorting the energy market is extensive state involvement in the funding of power projects such as the project to construct a major hydropower dam at Watana on the Susitna River, he said. State funding of energy projects raises questions over why people would want to buy energy from a privately-funded facility rather than buy relatively cheap, subsidized power, he said.

“That obviously has significant impacts and distortions on the market,” Schutt said. “We felt it directly with our project.”


Then there is the question of the regulation of power rates. Although CIRI obtained an exemption from regulation for the Fire Island project, there is de-facto regulation because the Regulatory Commission of Alaska has to approve utilities’ power purchase agreements, including the power rates within those agreements, Schutt said. And, despite CIRI conducting what it viewed as “arms-length” negotiations with its eventual utility customer, the Native corporation ran into substantial opposition from some utilities during the power purchase agreement approval process, he said.

In the course of trying to bring the Fire Island project to fruition one utility threatened legal action against the wind farm, while another used what CIRI viewed as manipulated numbers to argue against the merits of the project, Schutt said.

“There is actually something of a deep, pervasive suspicion of for-profit companies within the energy space here in Alaska,” Schutt said.

Read more:

Sunday, August 18, 2013

Arctic drill rules advance; Shell spill dome OK’d

Tim Bradner
Alaska Journal of Commerce

A top federal official offered fresh assurances that new rules governing drilling in the Outer Continental Shelf off Alaska’s Arctic coasts will be out by the end of the year, and that Shell’s special Arctic “capping stack” and containment system for spilled oil have been given final approvals.

“Those systems are now certified. The engineering problems have been overcome,” said James Watson, director of the U.S. Bureau of Safety and Environmental Enforcement, or BSEE.

Shell was unable to get certification for key parts of its containment system — a special barge designed to process and store oil recovered in a spill and the undersea containment capping stack — in time for the 2012 exploration season in the Arctic.

The first tests of the containment dome in Puget Sound failed when it surfaced and the top half was “crushed like a beer can,” according to an email account of the test written by BSEE Alaska Director Mark Fesmire reported by the Seattle National Public Radio affiliate KUOW in December 2012.

Because the spill response barge could not reach the Arctic in 2012, regulators gave Shell approval only to drill “top holes,” or the upper parts of the wells, on two exploration wells. Top-holes do not penetrate potential oil and gas reservoirs, so that there was no risk of a blowout from the 2012 drilling. The wells can be completed when Shell returns to the Arctic, possibly in 2014.

The regulations will also incorporate special requirements placed on Shell’s Chukchi and Beaufort seas exploration in 2012 for standby rigs for relief wells and for an undersea blowout containment system.

“We expect to formally incorporate these procedures in the very near future and to go to a proposed rulemaking (notice of new regulations) by the end of the year,” Watson said at a meeting held by the North American Marine Environmental Protection Association, or NAMEPA, a trade association.

Fesmire has said those things earlier, but Watson’s remarks as the agency’s top manager underscored what Fesmire said.

Shell and other companies are awaiting the new rules so that they can make plans for new drilling. Shell suspended its program for 2013 and has not said when it might resume exploration started in 2012, citing the lack of the federal rules as one uncertainty.

ConocoPhillips has not indicated what year it will drill on Chukchi Sea leases it holds, also citing the lack of the new rule. Statoil, another company holding leases, said it hopes to drill in 2015.

Watson added new details to what is known about the pending rules, however, mainly that BSEE will require independent third party audits of operators’ environmental and safety management programs.

Watson also described the pending new rules as a hybrid of a conventional compliance regulatory system, where the federal agency will do inspections, with a kind of performance system where industry must show it can meet certain standards and goals.

To do that, companies will be required to develop a Safety and Environmental Management system and to obtain audits by independent firms that their operating practices adhere to the management systems, Watson said.

“We don’t want to actually approve the management system because that puts us in a position of responsibility and liability. We will want to see the third-party verification that they are following it,” he said.

BSEE adopted similar requirements for third-party verification of compliance on well completion and cementing for deepwater offshore drilling following the 2010 Deepwater Horizon blowout in the Gulf of Mexico.

The pending new rules were first proposed to apply to the Alaskan Arctic OCS but they will now be broadened to apply to drilling on all OCS submerged lands off Alaska, Watson said. That would include any exploration in the Bering Sea, Gulf of Alaska and Lower Cook Inlet.

OCS lease sales and exploration drilling has previously been conducted in all of those areas but without success by industry.

U.S. Coast Guard Rear Admiral Thomas Ostebo also spoke at the NAMEPA conference, raising fresh concerns about increasing commercial marine traffic in the Arctic and the lack of international rules, both of which are creating risks.

“This is not something in the future. This is happening now,” Ostebo said. “Eight days ago we had a 1,000-foot tanker carrying a million gallons of fuel transit the Bering Straits. This is not a U.S.-registered vessel, it is operated by a third party (not the vessel owner) and it is not polar class,” which meant it lacked special ice protection, Ostebo said.

This year also saw the earliest entry of a cruise ship into the Arctic, a Russian vessel with 600 passengers.

“What would happen if there were a problem? We could have 600 people and half a million gallons of fuel in the sea off Point Hope,” he said.

The risks aren’t just fuel. Chemicals are also being carried on vessels crossing the Arctic. Russia has issued permits to more than 200 vessels to make the crossing this year, a four-fold increase in two years, Ostebo said.

The Coast Guard is particularly concerned about the lack of agreed-on “rules of the road” in the Bering Strait.

“We do not have a vessel separation and traffic system in place,” Ostebo said, unlike other geographically congested points where there is marine traffic, such as the Straits of Mallaca or Gilbralter. “What we have is a free-for-all, with whoever going where they want.”

The rules are complex for establishing international vessel traffic systems under the International Maritime Organization, or IMO, so the best approach is a bilateral agreement with Russia.

“Lt. Gov. Mead Treadwell has proposed a voluntary system that has a lot of merit, but Russia has asked us to go a little slower in developing it,” Ostebo said.

Russia has a lot of influence because the bulk of the Arctic traffic is over Russia’s Northern Sea Route, across the Arctic from Europe to Asia, and through the Bering Strait.

“The U.S. and Russia are the two nations sharing the strait, and every ship transiting the Arctic must go through it,” Ostebo said.

Unimak Pass is an Aleutians is one other area where there is high vessel traffic and no international traffic rules, but at least there are ocean-going tugs available to assist ships. There is nothing near the Bering Strait.

Sunday, August 11, 2013

ConocoPhillips applies for new NPR-A permits

Tim Bradner

CononoPhillips has applied for permits to develop a new production site in the National Petroleum Reserve–Alaska, the 23-million-acre federal reserve in the western North Slope. The company also has a second project on the drawing boards.

The application to develop the first project, GMT-1, was made in late July to the U.S. Bureau of Land Management, which administers the NPR-A. ConocoPhillips submitted the permits on behalf of itself and Anadarko Petroleum Corp., a minority partner, BLM spokeswoman Erin Curtis said.

GMT-1 was one of several projects ConocoPhillips announced it would pursue in the days following the state Legislature’s action April 14 to reduce the state production tax. Although NPR-A is federal land the state tax applies to oil and gas produced there.

The company also said it is evaluating a new production site in the Kuparuk River field and will accelerate drilling and well “workover,” or major maintenance, work.

In the NPR-A, ConocoPhillips owns 78 percent interest in federal leases in the Moose’s Tooth Unit with Anadarko holding the remaining 22 percent.

ConocoPhillips spokeswoman Natalie Lowman said her company will seek corporate approval to develop the GMT-1 project in the Greater Moose’s Tooth Unit of NPR-A in the second half of 2014, assuming the permits are issued by BLM.

If all goes as planned, construction would begin in early 2016 and first production in late 2017. No estimates of cost or production were included in the BLM application.

“We are still doing the preliminary engineering and design to determine cost and the estimated production,” of GMT-1, Lowman said.

The application also said the company also plans the second project, GMT-2, that would be 8 miles west of GMT-1.

“Upon the successful permitting and construction of GMT-1, ConocoPhillips intends to submit permit applications for development of GMT-2. The exact dates for these applications is unknown,” ConocoPhillips said in its filing with BLM.

GMT-1 is approximately 17 miles west of the producing Alpine field, which is on State of Alaska lands and is also owned by ConocoPhillips and Anadarko in the same 78 percent-22 percent shares as the NPR-A leases.

The two companies are also now developing CD-5, an Alpine field satellite unit a few miles west of the field but which is within the NPR-A because it is west of the Colville River channels that forms the boundary between and federal lands.

Construction of CD-5 is scheduled to begin in late 2014 and continue through 2015, with first production in 2015.

An issue that could complicate the CD-5 schedule and possibly GMT-1 are two lawsuits challenging the CD-5 permits. A lawsuit brought in federal court last February against the U.S. Army Corps of Engineers was filed by six residents of Nuiqsut, a nearby Inupiat village.

In June, the Center for Biological Diversity, an environmental group, filed a second lawsuit challenging the CD-5 permit, also in the U.S. Alaska District Court.

The villagers’ lawsuit claims a Colville River bridge and related roads planned for CD-5 will adversely affect wetlands that support subsistence hunting and fishing, and that the Corps did not properly consider tunneling under the river for a pipeline and air-supported access as a reasonable alternatives to the bridge and roads.

In its intervention in the case, ConocoPhillips claimed an underground tunnel for the pipeline creates environmental risks because corrosion and oil leaks are more difficult to detect and repair in a buried pipeline than a surface pipeline. In its separate lawsuit, the Center for Biological Diversity claims that threatened and endangered species are affected.

The State of Alaska, Arctic Slope Regional Corp., and Kuupik Corp. have intervened in the villagers’ lawsuit on the side of the Corps, but a motion to intervene by the North Slope Borough is being opposed by the village plaintiffs represented by Trustees for Alaska, an environmental law firm.

ConocoPhillips has also been granted intervenor status on behalf of the Corps in the Center for Biological Diversity lawsuit.

The case presents a new uncertainty over the CD-5 bridge permit, which was held up by an extended Corps of Engineers review before a corps permit for the bridge and roads was finally issued. If the permit is overturned the schedule for CD-5 could be disrupted, which could also affect the NPR-A site developments because they will depend on the bridge and roads built for CD-5.

The schedule for GMT-1 outlined in the permit application calls for the ordering of long lead-time materials for the project, such as steel, in the fourth quarter of 2014. One year later, in fourth quarter of 2015, the first ice roads would be built to support construction.

Gravel mining and construction of gravel roads, pads and bridges would occur in the first quarter of 2015. Pipeline vertical support members, the pipeline, production facility and power and telecommunications cables would be installed in first quarter, 2017. The first production would be in late 2017.

The project would include 7.8 miles of road to the project from the CD-5 drillsite now in construction; 8.4 miles of pipelines to connect GMT-1 to CD-5, and 8.4 miles of power and telecommunication lines built on horizontal supports from the pipeline.

There would be an 11.8-acre gravel pad at the project site with sufficient space to support 33 production wells.

Several pipelines would be built to support the project including a 20-inch produced fluids pipeline that would move a mixture of crude oil, natural gas and water from GMT-1 to the Alpine field oil and gas processing facilities.

There would also be a 14-inch pipeline to carry seawater or produced water (water produced from the oilfields) from Alpine to GMT-1 for reservoir pressure support, and two separate 6-inch pipelines, one to carry gas from Alpine to GMT-1 to support “artificial lift,” or below-surface pumps, to help bring oil to the surface, and a second 6-inch line to carry a miscible injectant fluids from Alpine that can be used for enhanced oil recovery.

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Monday, August 5, 2013

Alaska gets pipeline, just barely

—Wesley Loy

July 17 marked the 40th anniversary of a pivotal moment in Alaska history.

It came in 1973 in the U.S. Senate.

“Vice President Spiro Agnew cast the tie-breaking vote on an amendment offered by Senators Mike Gravel and Ted Stevens to remove all environmental and legal impediments to the pipeline carrying oil south from Alaska’s North Slope,” the Senate’s official Alaska timeline says.

The vote capped an epic environmental battle over the pipeline. Later that year, the Arab oil embargo would provide the final push needed to bring about the long-delayed construction of the 800-mile line.

Daniel Yergin, in his book “The Prize,” talks about the complicated road to the pipeline after the elephant Prudhoe Bay field was confirmed in 1968.

Lots of ideas were considered to get the remote, arctic crude to market: icebreaking tankers, trains and trucks, jumbo jet tankers, nuclear-powered submarine tankers.

A pipeline route into Canada also was considered, but ultimately the choice was for an “all-American route” to the ice-free port of Valdez, where the crude could be loaded aboard conventional tankers that could go to the Lower 48 or to Asia.

An oil company group including ARCO, BP and Standard Oil of New Jersey (Exxon) organized to build the line.

The consortium “rushed out and hurriedly bought 500,000 tons of forty-eight-inch pipe from a Japanese company; they did not think there was time to wait for American manufacturers to gear up,” Yergin wrote. “They were wrong. The pipeline was to come to a dead halt before it even started.”

Alaska Native land claims and “wrangling among the partners” slowed the project. But the real impediment was an effective legal challenge from environmentalists.

Tens of millions of dollars of stockpiled pipe and heavy equipment languished for years in the cold.

The Native claims were mostly settled in 1971, and eventually the environmental battle came to Congress.

Construction finally begins

On a vote of 50 to 49, with Agnew casting the decisive vote as the body’s president, the Senate passed the Gravel-Stevens amendment declaring that the Interior Department had met all the requirements of NEPA, the National Environmental Policy Act, for the pipeline project.

Three months later, in October 1973, the Organization of Petroleum Exporting Countries, or OPEC, would impose an oil embargo that shocked the nation.

Not long after, on Nov. 16, 1973, President Nixon signed right-of-way legislation, the Trans-Alaska Pipeline Authorization Act, into law.

Construction began in 1974, first oil flowed from Pump Station 1 in 1977, and the pipeline has since moved more than 16 billion barrels of crude.

Oil revenue utterly transformed Alaska and its economy. And the hope is that the pipeline can continue to operate for many years to come, although throughput has declined to around 550,000 barrels per day, or roughly a quarter of the peak of more than 2 million barrels in 1988.

Alaska Sen. Lisa Murkowski, the top-ranking Republican on the Senate Energy and Natural Resources Committee, commemorated the historic 1973 vote with a July 17 press release.

“It was a monumental decision that has shaped the trajectory of Alaska to this day,” Murkowski said.

She added: “A vast amount of oil remains as yet untapped in Alaska, most of it trapped on federal lands. It’s my hope that on this 40th anniversary of the pipeline, we’ll start to pay greater attention to the looming problem of losing a major portion of our country’s domestic oil production if more federal lands in Alaska aren’t opened to responsible development.”

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Friday, August 2, 2013

Oil production booms, demand drops, prices stay high: Why?

Tim Bradner
Alaska Journal of Commerce

University of North Dakota student Maxwell Johnson, an intern for Hess Corp. stands in front of an oil rig July 10 near Tioga, N.D. Production from the Bakkan oil play in North Dakota jumped 50 percent last year and contributed to the largest single-year increase ever in oil production for the U.S.. Despite the increase in supply and slack demand, prices remain high, however.

The world is awash in oil and the U.S. recorded its biggest increase in oil production last year. Oil demand is down, mainly due to high prices and the weak economy, but also due to huge gains in energy efficiency.

Yet oil prices remain high. Why?

That’s a conundrum energy economists are struggling with, says BP’s chief U.S. economist Mark Finley. If supply is up and demand is down, price ordinarily would fall. It isn’t happening, though.

“It’s a key question we’re facing, and we don’t really know the answer,” Finley said.

One possible answer might be that there is demand on world markets that isn’t being tracked, he said, possibly from governments quietly buying up oil to build strategic stockpiles.

“The U.S. isn’t the only nation with a strategic oil stockpile. China is also building a stockpile, and we now know that Saudi Arabia is building a supply storage, so that it has inventory for strategic advantages,” Finley said.

This could be one explanation for why oil prices remain high.

Finley spoke in Anchorage July 29 to a group of business and community leaders at a luncheon sponsored by the Alaska Oil and Gas Association.

Finley’s comments were drawn from data in BP’s annual Statistical Review, the 62nd edition of the report. BP’s data for 2012 is the latest available as of May, 2013, and the company’s report is typically the first analysis of energy trends published for a year, and is ahead of other reports, such as those produced by the U.S. Department of Energy’s Energy Information Administration.

Overall, the world’s energy market showed weak growth across all regions and all types of fuel.

“Energy consumption grew by 1.8 percent, which is low by recent standards,” Finley said.

The 10-year average is 2.6 percent. Energy consumption in OECD (Organization of Economic Cooperation and Development) countries, or developed nations, fell by 1.2 percent, led by a decline in the U.S. of 2.8 percent.

Among OEDC countries oil consumption dropped 1.3 percent, or 530,000 barrels per day, the sixth decrease in the past seven years. Among non-OECD nations, oil consumption grew by 3.3 percent, or 1.4 million barrels per day.

Non-OECD nations, mostly the developing nations, saw a 4.2 percent growth, but that was below the 10-year average of 6.3 percent growth.

Oil development continues at high levels, however.

“For every barrel of oil consumed reserves grew by two barrels, mainly because of technology improvements, such as in shale oil production,” he said. The world now has a 53-year supply of proven oil reserves and a 56-year supply of gas reserves.

The U.S. enjoyed a booming increase in oil and gas production, led mainly by the technology revolutions in shale production, but oil demand was down in the U.S. mainly due to a sluggish economic recovery and continued high prices.

An interesting aspect of the U.S. shale revolution is that the technology gains continue to improve in shale, somewhat confounding experts who had predicted a plateau effect.

“North Dakota saw its production increase 50 percent (mostly shale oil) but the number of rigs were up only 10 percent. Why is that? It is because the rigs were more productive, and drilling more wells. They were more efficient,” Finley said.

Global energy efficiency gains were also at record levels. Worldwide, the “energy intensity” of economic growth dropped by 1 percent mainly due to efficiency gains, Finley said.

In Asia, still the driving force in world energy markets, oil demand in China fell due to slowing growth, but coal use continued to increase. In Japan, cutbacks in that nation’s nuclear industry led to increased use of oil and particularly gas for power generation, in the form of imported liquefied natural gas, or LNG.

That had a chain-reaction effect on LNG markets, and indirectly on U.S. coal markets, Finley said.

“European LNG purchases fell 25 percent as Europeans were outbid by Japanese importers. To fill that need for fuel for power generation, Europe imported more coal, mostly from the U.S.,” he said.

The U.S. had coal available because cheaper natural gas was available, due to shale production. U.S. gas prices fell by one-third percent in 2012, making gas more attractive for power generation. This illustrates the linkages across regions and types of fuels that connect the world’s energy business today.

Oil remains the dominant fuel of in the world but it is gradually losing market share to other fuels, mainly gas and coal.

“The decline in oil use tracks perfectly with price,” Finley said. “The use of oil (in the mix of energy) is the lowest it has ever been.”

However, in the long term oil demand will be driven by growth of demand for transportation fuels, which is linked to larger numbers of automobiles being purchased, mainly in Asia.

“Twenty years ago China accounted for only 2 percent of new sales in the world. Now it accounts for 20 percent,” Finley said.

Asia overall accounted for 16 percent of new care sales two decades ago and now accounts for almost 80 percent.

A key message Finley conveyed to listeners is that most of the big innovations in energy like shale oil and gas, production from deep offshore fields and the Arctic, and including the biggest gain in energy efficiency in decades, have mostly been in North America.

That’s no accident. “It has happened because we have a political and economic structure that allows markets to respond. We don’t (have the government) pick winners and losers,” in industry, he said.

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