Sunday, January 29, 2012

SB 167 Oil and Gas Decoupling Senate Finance Committee Hearing - 01/27/12

Overview: oil and gas decoupling (47 minutes)
Presenters: Brian Butcher, and Bruce Tangerman
Department of Revenue Slides
SB 167: Legislative Documents


Saturday, January 28, 2012

CPAI earns $1.9B in 2011; A 34 percent jump in oil prices helped offset a 6.5 percent decline in production

Eric Lidji
For Petroleum News

A steep rise in oil prices last year helped ConocoPhillips earn nearly $2 billion in Alaska, an increase over 2010 earning despite falling oil and natural gas production in the state.

ConocoPhillips earned $1.9 billion in Alaska last year, up from $1.7 billion in 2010.

While ConocoPhillips’ annual earnings in Alaska rose, its quarterly earnings fell.

The company earned $443 million in the fourth quarter, down 11 percent from the third quarter ($501 million) and 7 percent from the fourth quarter of 2010 ($476 million).

ConocoPhillips earned $1.2 billion from its Lower 48 E&P operations in 2011, up from around $1 billion in 2010, while maintain roughly level production throughout the year.

Companywide, the company earned $12.4 billion in 2011, up from $11.3 billion in 2010.

Rising Lower 48 oil

While ConocoPhillips continues to earn more from its upstream operations in Alaska than from its upstream operations in the Lower 48, that balance could start to shift this year.

The company plans to ramp up its activities in the oil-rich Eagle Ford and Bakken Shales this year to take advantage of high oil prices and, conversely, shut-in around 100 million cubic feet of North American natural gas production due to chronically depressed prices.

In Alaska, ConocoPhillips produced 215,000 barrels of oil and natural gas liquids per day in 2011, a 6.5 percent decline from the 230,000 bpd of liquids the company produced in 2010. ConocoPhillips produced 61 million cubic feet of natural gas per day in the state last year, down roughly 25 percent from the 82 mmcf per day the company produced in 2010.

In the Lower 48, ConocoPhillips produced 168,000 bpd of liquids in 2011, up slightly from 160,000 bpd in 2010, and 1.5 billion cubic feet of gas per day, down from 1.7 bcf in 2010.

Significantly higher oil prices in Alaska continue to offset gradual production declines for ConocoPhillips. The company realized an average oil price of $105.95 per barrel for Alaska last year, up from $78.61 in 2010. By comparison, the company realized an average price of $74.09 per barrel for Lower 48 liquids in 2011, up from $57.69 in 2010.

While oil jumped, natural gas prices remained relatively flat year-over-year for ConocoPhillips, from $4.62 per thousand cubic feet in 2010 to $4.56 per mcf in 2010. By comparison, Lower 48 gas prices fell from $4.25 per mcf in 2011 to $3.99 per mcf in 2010.

Liquefied natural gas sales declined considerably in 2011, as ConocoPhillips began the process of closing its nearly 45-year-old facility on the Kenai Peninsula. The company sold 26 mmcf per day in 2011, down nearly 45 percent from 47 mmcf per day in 2010.

While mentioning recent discussions about a proposal to market North Slope natural gas as LNG, ConocoPhillips’ executives made no noteworthy comments about the project.

Tax debate continues

ConocoPhillips has released its year-end earnings as Alaska lawmakers are once again considering changes in the state’s production tax code.

In his recent state-of-the-state address, Gov. Sean Parnell tied tax reform to his goal of increasing throughput in the trans-Alaska oil pipeline to 1 million barrels per day over the coming decade. Because it is the only major oil producer to break out financial figures for Alaska on a quarterly basis, something BP only does annually and Exxon does not do at all, ConocoPhillips’ earnings often become a wedge in those debates, something Parnell seemed to anticipate by asking, “Do we have enough will to give up short-term gains for long-term growth?”

With tax reform, the industry is willing to invest $5 billion in legacy fields, Parnell said.

Rep. Les Gara, an Anchorage Democrat, is promoting an alternative bill designed to create incentives for companies to explore and develop new fields in the state.

ConocoPhillips doesn’t release its complete annual report until late February. The filing typically includes Alaska-specific taxation, spending and budgetary information.

Friday, January 27, 2012

Moving gas in-state; House plan combines existing bills, wraps ANGDA into AGDC with same board

Kristen Nelson
Petroleum News

Last year the Alaska House picked away at issues surrounding an in-state gas pipeline, moving three bills to the Senate.

In July, the Alaska Gasline Development Corp. delivered its feasibility report to the Legislature, complete with a list of recommended legislative changes.

House Speaker Mike Chenault, R-Kenai, and Rep. Mike Hawker, R-Anchorage, introduced legislation Jan. 24 combining the existing bills with recommendations from AGDC and additional tools, all of which Chenault described as designed to advance a natural gas pipeline project and bring natural gas to Alaskans.

AGDC has been working on a plan for an in-state gas pipeline since the Legislature passed House Bill 369 in the spring of 2010. HB 369 called for the development of an in-state natural gas pipeline plan, with a proposal to have gas moving through a line by 2015 to be delivered to the Legislature in July 2011.

AGDC delivered the initial plan, but told legislators that it would take until 2018 for first gas.

The new legislation, a committee substitute for HB 9, would keep the momentum going for development of gas for Alaska, “while keeping open all the options for participating in an aligned project,” Chenault said, referring to the governor’s proposal that a large line under AGIA, the Alaska Gasline Inducement Act, could morph into a liquefied natural gas project and combine with an in-state project.

Hawker said he believes we are “on the verge” of seeing a pipeline constructed “that actually will bring Alaska’s gas to Alaskans,” and said the proposed legislation would empower AGDC to carry through to the point where “we can bring a project back before the Legislature and debate the sanctioning” of a project.

He said the bill brings state agencies, including the Alaska Natural Gas Development Authority, “together into a common mission with a common management.” The bill eliminates the present ANGDA board and moves ANGDA under the Alaska Housing Finance Corp. board of directors, which would also replace the Joint In-State Gasline Development Team, which has been the board for AGDC.

Dan Fauske, president of AGDC and CEO of Alaska Housing Finance Corp., said the legislation would give AGDC additional tools. ANGDA’s role in the development, he said, would be in gas marketing and gas purchasing.

Fauske said AGDC is currently in the process of working on a draft environmental impact statement, with public hearings scheduled, and said the EIS is expected to be completed in May. An open season is planned for 2013.

Committee substitute

The proposed legislation is a committee substitute for House Bill 9, introduced last year and includes HB 203, which establishes a fund to receive $200 million appropriated in 2011 for work toward an open season and directs fund management and investment; HB 215, which limits challenges to right-of-way leasing decisions similar to protections extended to the trans-Alaska oil pipeline; and HB 189, which allows AGDC to enter into confidentiality agreements. All three of these bills were passed by the House last year and are in the Senate.

In addition, HB 9 gives AGDC the ability to determine pipeline ownership and operating structure, to exercise eminent domain, to issue bonds and to manage pipeline and related project assets. The bill also removes language limiting an in-state line’s scope to linking North Slope to tidewater, allowing flexibility if there are major finds elsewhere in the state.

The bill recognizes AGDC as an Alaska Housing Finance Corp. subsidiary by replacing the Joint In-State Gasline Development Team with AHFC’s board of directors, and brings the Alaska Natural Gas Development Authority under common management with AGDC. It also protects the state and AHFC from liability related to AGDC and directs state agencies to support AGDC’s efforts by providing permits and state resources such as water, sand and gravel, at no cost.

It amends regulatory requirements for a state-sanctioned project by allowing AGDC to operate a pipeline as a contract carrier and provides AGDC the option for Regulatory Commission of Alaska oversight.

And the bill would exempt an in-state gas pipeline from state and local taxes during construction.

ANGDA changes

The sectional analysis for the committee substitute for HB 9 says certain statutory provisions relating to ANGDA pertaining to the construction of a natural gas pipeline are deleted.

“The overall effect of the amendment in this and later bill sections would be to clarify that ANGDA may operate as a shipper of gas but not as a pipeline owner or developer. This clarifies the respective responsibilities of AGDC and ANGDA and conforms to general requirements of FERC and other potential pipeline regulatory agencies,” the analysis said.

Other provisions of the bill would allow ANGDA to focus on marketing, and give ANGDA the ability to pledge royalty gas owned by the state as long as that gas is not already committed by contract.

Alignment possible

In discussing the proposed legislation, Hawker said that one of the things it does is to broaden the authority of AGDC so that the project could have alignment with a large line going through the state to a tidewater port.

Fauske said the AGDC team is “in constant communication” with the AGIA (Alaska Gasline Inducement Act) project — the Alaska Pipeline Project — and with Kurt Gibson (director of the Alaska Gas Pipeline Project Office, the state agency which is working on the AGIA project) and his staff and with TransCanada.

AGIA is the project being pursued by TransCanada and ExxonMobil to take North Slope natural gas to North American markets in a large line, some 4.5 billion cubic feet a day. The project has held an open season but so far no shippers have committed to shipping on the line, and Gov. Sean Parnell asked the project proponents late last year to look at shipping Alaska North Slope natural gas to Asian markets as liquefied natural gas, a reflection of high prices in Asian markets and the fact that the Lower 48 currently seems more than adequately supplied with natural gas from new shale developments.

Fauske said there is a “community spirit” in progressing the project and noted that if AGIA goes forward, then the work AGDC is doing “is worthwhile in that it becomes the spur line coming off the big line.”

Hawker said provisions in the bill enable AGDC to be a partner or an investment equity holder in other projects, and also allow it to take capacity in other projects, so “this legislation expands the powers and authority of AGDC to be an active participant in other lines.”

Asked about this project in relation to AGIA, Chenault said the legislation “is not about picking a winner: This is about getting gas to Alaskans.”

HB 369 was structured to be within the limits established in the AGIA which prohibits the state from investing in a competing project which would deliver more than 500 million cubic feet a day of natural gas, he said.

Norway Lessons Learned - Legislative Lunch and Learn

Senate’s oil tax bill ready in less than two weeks, Senate President says

Tim Bradner
Alaska Journal of Commerce

JUNEAU —­ Senate President Gary Stevens, R-Kodiak, says the Senate’s version of an oil tax reform bill is being drafted and will be before the Senate Resources Committee within two weeks.

Stevens spoke in a briefing by Senate leaders held in Juneau Thursday.

The oil tax change is considered one of the key issues to be resolved by the Legislature in its 2012 session. “It’s the elephant in the room,” Stevens said.

Gov. Sean Parnell said the state needs to adjust taxes to encourage more oil industry investment on the North Slope, where production is now declining.

After the Resources Committee finishes its work the bill will go to the Senate Finance Committee, then to the floor of the Senate and the state House, which passed its own version of oil tax changes last year.

That bill, House Bill 110, had been introduced by the governor, and is now in the Senate Labor and Commerce Committee. Stevens said the pending new Senate bill will be the “vehicle” for resolving the issue rather than the House bill.

“Our goal is to get it to the House with 30 days left in the session, the give House members time to review the proposal,” Stevens said.

That timetable would have the bill to the House by mid-March. Stevens said some conversations have been held already with House Speaker Mike Chenault.

Senators in the Thursday briefing, which included co-chairs of the Senate Resources and Finance committees, would not comment on contents of the bill being prepared but said it would deal with problems in the “progressivity” formula in the current tax law as well as investment tax credits and tax audit procedures.

The progressivity formula is the source of many problems, oil producers have said, because it sharply ratchets up the state tax rate when oil prices climb. At current oil prices, the tax rate is among the highest in the world. Given the high costs of developing new oil on the Slope and the expected modest-sized discoveries, Alaska is now having trouble being competitive in attracting investment, the companies have said previously.

Stevens said there was agreement in the Senate majority that action is needed to get more oil into the Trans-Alaska Pipeline System, which is moving smaller amounts of oil with the decline of production in the North Slope oil fields.

However, the approach being developed in the Senate is “far apart” from the approach taken by the governor and the House in HB 110, Stevens said. Stedman said the two versions of the tax change would be closer than many expect because there is agreement on the problem areas in the tax.

“People agree on the choke points. What we have to agree on is the policy changes needed to fix them,” Stedman said in the briefing.

Stedman said one focus of the Senate bill will be on the split of production profits at different crude oil price ranges between the state and the producing companies.

Sen. Joe Paskvan, D-Fairbanks, co-chair of the Resources Committee, said legislators now have far more information about the need for a tax change than was available a year ago, when HB 110 passed the House.

“I now have 100 pages of answers to my questions from the Department of Revenue and 25 pages of answers from the Department of Natural Resources,” Paskvan said.

Read more:

Thursday, January 19, 2012

Fairweather builds Deadhorse Aviation Center

Jonathan Grass

An architectural rendering shows the exterior of the new Deadhorse Aviation Center that will be the area’s largest facility. It is scheduled to open this summer.
Courtesy of Fairweather, LLC

A dormant North Slope project has been reborn as a way to support oil and exploration companies faced with the area’s currently scant facilities. The Deadhorse Aviation Center is designed to be the area’s largest and most modern piece of infrastructure, and is expected to open this summer.

The 70,000-square-foot facility includes a 21,000-square-foot hangar joining two floors of various accommodations plus a mezzanine. The facility — owned by Fairweather, LLC, Offshore Support Services, LLC (an Edison Chouest company) and Kaktovik Inupiat Corp. — is to provide support and safety to both large oil companies and smaller operations that use this area of the North Slope.

The multi-modal facility is located on the north end of runway 5 of Deadhorse’s airport, one of the North Slope’s busiest.

“This will be, if not the, one of the newest pieces of infrastructure available for the industry in Deadhorse,” said Fairweather Manager Sherron Perry.

DAC will house a cargo and passenger terminal, offices, conference rooms, a medical facility and clinic, ambulance and medevac facilities, bedroom accommodations for 48 people, kitchen capacity for 60 people and secure areas for hazardous materials. There is also an adjacent 10.5-acre gravel yard for outside storage. High-speed Internet will be available there as well.

Fairweather’s medical personnel will operate the clinic. This will be Deadhorse’s largest medical facility, as well as the only privately owned one on the North Slope.

Fairweather Director of Business Development Lori Davey said companies that utilize this service will likely use the center’s other services as well.

Another feature that will be new to companies outside big oil will be the incident command center.

“This will provide smaller companies that don’t have a lot of infrastructure up there to be able to come into the secure environment and manage a spill or a leak or some other problematic issue that they need to set up an instant command structure to manage,” Perry said.

The hangar accommodates offshore helicopter capacity and fixed wing activities.

The design also calls for Deadhorse’s first heated jet ways. These won’t be constructed unless a contract is reached with an air carrier, however.

The project manager is Neil McCleary, who helped design the facility with Marvin Ungerecht of Architects Alaska. McCleary works for Fairweather.

The hangar is finished with the exception of the fire suppression system. Building is under way for the rest of the facility. Contracting work is being done through Ukpeaġvik Iñupiat Corp.’s construction services out of Barrow.

Perry said the total costs will be $35 million once the facility is completely finished.

The facility actually went into construction in 2006, when it was to be used to support Shell’s offshore operations. Construction was suspended shortly after Shell was unable to move offshore and had to abandon its leases in the summer of 2007.

“We believe the market is growing now and it’s time for us to lead this project,” Perry said. He said he believes offshore development will proceed this summer and has seen an increase wintertime exploration.

The center is using its original design as a shore base to support offshore drilling and exploration activities.

“A number of companies have seasonal work in the area,” he said. This includes government research projects such as those by the U.S. Forest Service, Bureau of Land Management and National Oceanic and Atmospheric Administration.

DAC will be ready for occupancy in June 2012. The next step is to sign leasers. None are signed yet. Fairweather is talking with several prospects, including all the big oil companies and gasline companies with aviation components. Perry said there are discussions with aviation companies, Alyeska Pipeline Service Co., the U.S. Coast Guard, the Air Force and other government and private agencies.

The state Department of Transportation has identified a number of issues in current Deadhorse aviation facilities, including inadequate lighting, limited expansion possibilities and the need for runway surface rehabilitation. The survey also indicated current insufficient sizes for a flight service station, rescue and fire fighting, and now removal equipment.

The new DAC is intended to address several of these. It also accommodates Transportation Security Administration screening compliance, something that current Deadhorse facilities are too small to do. This design is based on TSA recommendations.

Fairweather has multiple specialty divisions, such as environmental science and medical subsets, which played a big role in the diversifying the new resources. Davey said an example of such advantages is that leasers will be able to get weather and ice reports from the building, something that is important to offshore drilling. She said Fairweather’s logistics support is also important to oil companies that may not know everything involved with drilling in the North Slope.

“It’s been important for gaining the support of all the different entities combined because we’re considered a third-party, non-biased entity doing the science,” Davey said.

Read more:

Buccaneer Energy starts production at new Kenai natural gas well

By Tim Bradner
Alaska Journal of Commerce

Bucaneer Energy has started natural gas production at its Kenai Loop No. 1 well near Kenai, the company announced in a written release Monday. Production began Jan. 14.

The well will be produced at a rate of 5 million cubic feet per day for the next two to three months while performance of the reservoir is evaluated, company spokesman Dean Gallegos said.

Buccaneer, an Australia-based independent company, will sell its gas into the daily gas auction conducted by Enstar Natural Gas Co. and will also have the ability to sell gas to ConocoPhillips Alaska Inc. for that company’s gas liquefaction plant in Nikiski under a contract with ConocoPhillips, according to the press release.

Enstar’s daily gas auction “is a system where gas producers are advised of Enstar’s additional requirements for the next 24 hours and the producers bid the price and volume to sell gas to meet those requirements,” the press release said.

Buccaneer plans additional drilling in its Kenai Loop field beginning in the second quarter of 2012, the company said. The Kenai Loop No. 1 well was completed as a successful gas discovery in early 2011 but a second well drilled nearby was unsuccessful. Buccaneer planned additional seismic work this winter to better map the potential reservoir.

The additional drilling is planned to confirm other reserves.

Meanwhile, Buccaneer will be drilling offshore wells in Cook Inlet this summer with a new jack-up rig being brought to the Inlet by an affiliated company, Kenai Offshore Ventures. The company’s offshore prospects have potential for oil as well as natural gas.

There is already one jack-up rig in the Inlet brought north in 2011 by Escopeta Oil Co., a Houston-based independent. Escopeta partly drilled its first Inlet exploration well in late 2011 and discovered gas. Drilling was curtailed for the season with the onset of winter, and will resume next spring.

Read more:

State of the State: Parnell lays out 2012 benchmarks for LNG deal

Tim Bradner
Alaska Journal of Commerce

Alaska’s Republican Gov. Sean Parnell gives his annual State of the State address Jan. 18 to the Alaska State Legislature in Juneau. In the background is Senate President Gary Stevens, R-Kodiak, left, and House Speaker Mike Chenault, R-Nikiski.

Alaska’s Republican Gov. Sean Parnell gives his annual State of the State address Jan. 18 to the Alaska State Legislature in Juneau. In the background is Senate President Gary Stevens, R-Kodiak, left, and House Speaker Mike Chenault, R-Nikiski.

AP Photo/Chris Miller

In his annual State of the State address, Alaska Gov. Sean Parnell laid out benchmarks he hopes North Slope producers will reach in 2012 on a possible deal to build a natural gas pipeline and liquefied natural gas project.

Parnell spoke to a combined audience of the state House and Senate in the state capitol in Juneau Wednesday night.

If the companies meet the benchmarks, Parnell committed to introduce a needed agreement on natural gas production taxes to the 2013 state legislative session. The companies say a deal on fiscal terms including taxes and royalties are needed before a major gas project can be pursued.

Parnell had met with the CEOs of the three major slope producers in Anchorage Jan. 5 and urged them to work together on a large LNG project in lieu of an all-land pipeline now being pursued by TransCanada Corp. and ExxonMobil Corp.

BP's Robert Dudley, ConocoPhillips' James Mulva and ExxonMobil's Rex Tillerson met with Parnell.

In his speech to legislators Parnell said he hoped to see the three companies come together in an agreement to pursue an LNG project by March 31, on a plan to integrate work the state has done with a 24-inch in-state pipeline from the Slope, and by Sept. 30 a schedule for a new, large gas project.

An LNG project, aimed to serve export markets, would involve a large-diameter pipeline from the Slope to a southern Alaska port, either Valdez, the present terminus of the Trans-Alaska oil pipeline, or the Kenai Peninsula, near Anchorage, where ConocoPhillips now operates a small LNG plant supplied by Cook Inlet gas fields.

Parnell said he is also pushing for quick resolution to a lawsuit over state leases at Point Thomson, east of Prudhoe Bay on the slope, which all parties agree must be resolved before a major gas deal can move forward.

Point Thomson holds an estimated 8 trillion cubic feet of gas, a sizeable portion of the 35 tcf of gas reserves identified on the Slope that would support a gas pipeline.

“In the last 24 hours I spoke with the CEOs of all three producing companies to ask if there has been progress on reaching agreement on Point Thomson, and I was told there was not,” Parnell told legislators in his speech.

If agreement does not come in the next two weeks Parnell said the state would “vigorously” argue the state's position in the dispute in a hearing planned Feb. 8 by the Alaska Supreme Court.

The case involves a claim by the state that Point Thomson lease-owners, which include ExxonMobil, BP, Chevron and CononoPhillips, did not abide by work commitments. Based on the claim the state moved in 2007 to terminate the Point Thomson Unit.

The lease-owners sued and the case has been winding its way through the state courts since, and is now before the state's high court.

The state has negotiated a possible settlement with ExxonMobil, the operator of the unit, but BP, Chevron and ConocoPhillis, the other major leaseowners, have not agreed to the deal.

Alaska Senate President Gary Stevens says many of Parnell's priorities fit with those of his bipartisan coalition.

Stevens says Parnell is right that this will be an important legislative session, particularly as it pertains to oil and gas and trying to find meaningful solutions to spur production. But he says there are problems with Parnell's oil tax-cut plan and says he'd like the Senate to craft its own tax bill.

House Minority Leader Beth Kerttula says her Democratic caucus wants to ensure Alaska gets its fair share from a tax regime and will stand against giving away the state's resources.

Read more:

Friday, January 13, 2012

A TAPS bottom line; Operation economics as much as technology will determine pipeline future

Alan Bailey
Petroleum News

The question of how low the flow rate of oil through the trans-Alaska pipeline can go before the pipeline becomes inoperative seems a bit like the proverbial question about how long is a piece of string: it all depends on how long you want it to be. And in the case of the pipeline commonly referred to as TAPS it seems that the ultimate answer depends on how much money can viably be spent making pipeline modifications to keep ever smaller volumes of oil trickling south from pump station one on Alaska’s North Slope.

As illustrated by the recently concluded court case over the tax valuation of TAPS, the question of how little oil the pipeline can carry matters a great deal. The lower the volume of oil that can flow down the line, and the longer the life of the line, the more pipeline is worth and the greater the property tax bill for the pipeline owners. At the same time, extending the pipeline life increases the amount of oil that can potentially be recovered from North Slope oil fields, thus enabling oil producers to beef up their “booked” oil reserves, hence increasing the values of their companies and raising their appeal to potential investors.

But just what are the facts regarding the issues surrounding the slowing flow of oil through TAPS?

Falling throughput

Few people, if any, dispute the nature of the essential problem: Pipeline throughput is steadily dropping and the 48-inch diameter pipeline was designed to move much more oil than it carries at present. At its peak the line shipped about 2 million barrels of oil per day, while at present that daily throughput has dropped to just over 600,000 barrels.

To enable pumps to push oil over the ups and downs of a pipeline route that includes a couple of mountain ranges, it is necessary to keep the entire line filled with oil. To keep the line full as pipeline throughputs drop, the rate at which the oil flows down the line has to become lower and lower. And nowadays the diameter of the line really is too large for the quantity of oil that the line carries.

With temperatures in Alaska well below freezing during the winter, the oil, warm as it exits the oil fields, cools as it flows south from Prudhoe Bay. And the slower the oil flows, the colder it becomes before it reaches the Valdez Marine Terminal for loading into oil tankers. If the temperature of the oil drops below the freezing point of water, ice is likely to form in the line, potentially causing line blockages and damaging pipeline equipment. At low temperatures, increasing amounts of wax will tend to drop out of the oil, causing clogging of the line. And, also as flow rates drop, the flow in the line will become less turbulent, transitioning into what is termed “laminar flow” and increasing the tendency for sludge to drop out of the oil.

Pig operations

Alyeska Pipeline Service Co., the company that operates the pipeline on behalf of the pipeline owners, periodically runs torpedo-shaped devices called “pigs” down the interior of the line, to scrape and clean the inside walls. Were ice to form in the line, a pig would likely become stuck, a situation that would be difficult and expensive to remedy and that would presumably cause a pipeline shutdown. In addition, the difference in fluid pressure between the front and rear of a pig drives the pig down the line — as the oil flow in the line drops that pressure differential also drops, thus making it increasingly difficult to move pigs and hence clean the line. But, as wax and sludge deposits increase in low-flow scenarios, pig operations become increasingly important in keeping the pipeline clean.

One helpful feature of the TAPS configuration is the existence of an oil refinery at North Pole, near Fairbanks, around the midpoint of the pipeline route. The refinery accepts part of the crude oil stream from the pipeline, refines some products such as jet fuel from it, and then returns the residual fluids back to the line. The residual fluids retain heat from the refinery process, thus heating the oil as it continues on its route to Valdez. Were the refinery to close, Alyeska would presumably have to install some form of heating system, to replace the heating effect of the refinery residues.

A threshold?

The big questions over the future of TAPS relate to estimates of throughput levels at which low-flow problems will start to appear, and whether there is some throughput threshold, below which the pipeline will become impossible to operate.
There are ways to deal with the cooling of the oil, such as the installation of heaters and the warming of the oil by circulating the oil through pipes at pump stations. But can these low-flow mitigation measures handle very low throughput volumes? And at what point does the cost of installing and implementing the mitigation measures cease to be viable? The higher the pipeline operating costs, the higher becomes the transportation cost of the oil, thus lowering the oil’s wellhead value.

In the TAPS valuation court case Superior Court Judge Sharon Gleason accepted the principle that there is some minimum throughput flow rate, below which TAPS ceases to be viable, even if technically the pipeline with appropriate mitigation measures could handle very low rates.

Alyeska study

A report published by Alyeska in June 2011, following a study into TAPS low-flow issues, says that low-flow mitigation measures will be essential to keep oil flowing through the pipeline at flow rates below about 550,000 barrels per day. The report listed a number of potential low-flow mitigation measures, such as the heating of the oil upstream of cold points on the line, but said that the Alyeska study had not addressed the mitigation of low-flow problems at flow rates below 350,000 barrels per day.

“As flow rates decline below 350,000 bpd, issues related to low flow will increase the problematic impact on the TAPS operation,” the 2011 low-flow report said. “Measures to mitigate these issues utilizing the existing 48-inch pipe at throughputs below 350,000 bpd have not been determined at the date of this report.”

In the TAPS valuation court case, the TAPS owner companies used the results of the Alyeska low-flow study to claim a minimum viable TAPS throughput rate in the range 300,000 to 350,000 barrels per day. However, Judge Gleason rejected this argument, saying that the Alyeska study had addressed questions of how to keep the pipeline in operation with throughputs down to 300,000 barrels per day, and that the study had not attempted to establish any minimum possible throughput capacity.

And Dan Hisey, a former Alyeska chief operating officer, testified that TAPS has no hydraulic or mechanical minimum throughput level.

According to an Associated Press report, Alyeska spokeswoman Michelle Egan has said that the Alyeska low-flow study was not intended to identify some technical or economic limit for the pipeline.

BP projections

Judge Gleason’s decision document says that BP had until 2004 used 300,000 barrels per day as the likely minimum TAPS throughput when making estimates of remaining oil reserves on the North Slope. That minimum throughput estimate was apparently based on the use of the turbine powered pumping systems originally installed in TAPS to drive oil from Prudhoe Bay to Valdez. However, the conversion of the pumping systems to the use of new electrically powered pumps as part of a major TAPS upgrade project called “strategic reconfiguration” had considerably increased the flexibility of the system to handle lower oil volumes.

In 2004 BP commissioned a study by a consortium headed by JTG Technology & Information Services Inc. into the potential minimum TAPS throughput following strategic reconfiguration. And a 2005 JTG Technology report for the company suggested that, with the application of heat to the line and some other possible pipeline modifications, pipeline throughput could be sustained down to levels of about 135,000 barrels per day. Further hydraulic flow testing would be required to confirm that result, the report said.

The report also said that, were the pipeline owners to replace the original 48-inch pipeline from Prudhoe Bay to Fairbanks by a new 20-inch pipeline, with oil being carried by railroad from Fairbanks to tidewater in Southcentral Alaska, throughput could be sustained down to 45,000 barrels per day.

Lower limits

BP subsequently used the 135,000 barrels per day lower throughput limit to determine the North Slope oil reserves that the company reported to the Securities and Exchange Commission, the court decision document says. According to testimony presented at the court, transitioning to the 20-inch pipeline option to handle lower flow rates would have involved a “stair step” cost of around $3 billion.

The decision document says that in 2010 BP retained Phil Carpenter, an expert in TAPS low-flow issues, to determine the feasibility of operating TAPS at throughputs below 135,000 barrels per day, without that $3 billion cost hurdle. Carpenter concluded that that it would be possible to operate the pipeline with throughputs in the range of 70,000 to 100,000 barrels per day by installing heaters at intervals along the line. Carpenter’s report stated that wax deposition and issues with pig operations would probably put a lower threshold of 50,000 to 70,000 barrels per day on throughput supported by pipeline heaters. Going below that threshold for oil throughput would likely require other remedies, such as the mixing of seawater with the oil, to maintain total fluid throughput rates, the report said.

However, Carpenter did express concern about the feasibility of operating pigs in the line at 70,000 barrels per day — he recommended research into pig designs for use in this type of scenario, the court decision document says. Carpenter also expressed concern about the impact of pipeline shutdowns and slowdowns on oil temperatures and wax accumulation, the document says.

Cost of heating

In 2010 BP commissioned a report into the likely cost and timing of implementing the system of heaters proposed in the Carpenter report. And from the fall of 2010 BP started using the 70,000- to 100,000-barrel range as the low-flow limit when booking its North Slope oil reserves, the court decision document says.

According to the decision document the BP-commissioned cost report estimated that the implementation of heaters as per the Carpenter plan would cost about $3 billion. However, the Carpenter plan assumed the installation of a heating capacity 70 percent in excess of what might actually be needed, thus making the potential implementation cost substantially lower than the cost estimate prepared for BP, the decision document says. But even with the $3 billion cost, the value of proven oil reserves on the North Slope would render the heating upgrade viable, the document says.

Gleason: 100,000 barrels

Judge Gleason concluded that, based on evidence presented in the court, TAPS can carry oil down at least to a minimum throughput of 100,000 barrels per day.

The question of how this presumed minimum throughput translates to an estimated life expectancy for TAPS then depends on estimates of how much oil remains technically recoverable from Arctic Alaska and on future oil prices, with the prices determining the economic viability of oil production. Testimony presented in court illustrated the considerable uncertainty in current estimates of both oil resources and future oil prices, with various consultants presenting a wide range of estimates for different stakeholders in the economics of TAPS.

Persuasive forecast

Ultimately, Judge Gleason found oil production forecasts presented by consultant Dudley Platt to be the most persuasive of the various forecasts presented to the court. Platt, who used to maintain oil production forecasts for the Alaska Department of Revenue, had prepared forecasts for the Alaska municipalities that obtain revenues from TAPS property taxes.
The decision document says that Platt’s forecasts of remaining recoverable reserves lead to a probable end of life around 2065 to 2068 for TAPS, assuming a 100,000-barrels-per-day minimum throughput. This estimate excludes possible production from the Point Thomson field, the field that is currently the subject of a dispute between the field owners and the State of Alaska.

By comparison, reports by BP to the Securities and Exchange Commission for the Prudhoe Bay Royalty Trust, an investment fund for the Prudhoe Bay field, have indicated TAPS end-of-life expectancies ranging from 2049 to 2075, with that wide range of years apparently related to an equally wide range in future oil price expectations. The pipeline owners’ testimony to the court presented a range of years from 2032 to 2053, with significantly lower estimates of remaining oil reserves than those presented by Platt. The State of Alaska, with reserves estimates between those of the owners and those of the municipalities, estimated an end of life ranging from 2043 to 2053, if the pipeline is operates to its economic limit, the decision document says.

Thursday, January 12, 2012

Shell gets final OK on air permit for Chukchi Sea drilling

Tim Bradner
Alaska Journal of Commerce

The U.S. Environmental Protection Agency's Environmental Appeals Board has approved Shell Oil's air quality permit for the Noble Discoverer drillship, Shell announced Thursday.

The drilling vessel will be used by Shell to drill up to three exploration wells in the Chukchi Sea this summer if Shell secures other permits and approvals that are still pending.

The EAB, an internal appeals panel within the EPA, denied petitions for review of the permits filed by environmental groups.

“Achieving usable air permits from the EPA is a very important step for Shell and one of the strongest indicators to date that we will be exploring our Chukchi and Beaufort Sea leases in July,” Shell spokesman Curtis Smith said in a statement. “That our air permits for the Noble Discoverer withstood appeal is a testament to the robust nature of the work we have done to have the smallest possible impact on the Arctic airshed,” Smith said.

Shell equipped the drillship with advanced emissions control technology and will use ultra-low sulfur diesel fuel in operations of the vessel. Shell is planning to use another drill vessel, the Kulluk, in the Beaufort Sea in 2012.

The company has not yet decided to mobilize for the summer drilling.

“The validation of Shell’s first air quality permits is almost the end of what has been a long and exhaustive process,” said Sen. Lisa Murkowski. “I’m relieved that the EPA’s internal appeals board chose here not to drag out the process any further, and I hope that the permits for Shell’s second drillship, the Kulluk, are similarly confirmed in a timely manner.”

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Gov. Parnell says he’s upbeat about state’s economy

By Tim Bradner
Alaska Journal of Commerce

Gov. Sean Parnell presented an upbeat picture of Alaska’s prospects, but also highlighted the state’s immediate challenges in a keynote address to the Alaska Support Industry Alliance’s annual Meet Alaska conference in Anchorage Jan. 6.

Parnell first applauded the Alliance and its industrial service and support company members.

“You are in the business to do what Alaskans have done from the beginning: maximize opportunity, develop private enterprise,” the governor said. “Every day you accomplish what no government can do. You generate an authentic GDP. And I don’t mean ‘Government Dependent Programs.’ I mean an honest-to-goodness Alaska GDP based on free enterprise. You make that happen every day.”

For now, things are looking positive for the state.

“In case there’s any doubt, I want to make something very clear: Alaska is open for business. Today’s newspapers let us know we’ve had the third straight year of job growth in Alaska. Yesterday (Jan. 5) we saw further evidence that others are taking notice that Alaskans will work together to grow our economy. Three CEOs from major oil companies met here in Alaska to talk about a gas line, to talk about alignment,” Parnell said. “It was the first time these three CEOs have been together in Alaska. Our discussions were very productive, and I was very encouraged. Also, it was announced that our state bond rating was upgraded to AAA. In this world economy, think about what that means. Alaska’s business environment is getting better.”

Still, there are troubling times ahead, he said.

“In 2012, my administration will not yield in our effort to directly address the most pressing economic issue facing our state – the decline of oil coming through the Trans-Alaska Pipeline System. TAPS production is an economic survival issue for Alaska,” Parnell said.

To address this problem, the governor’s plan to increase oil production from its current rate of about 600,000 barrels per day back to 1 million barrels per day was developed last year out of discussions with business and community leaders.

“We sat down, talked with business and community leaders across the state, and we heard their concerns. We carefully listened to these ideas,” Parnell said. “We said we were going to put more oil leases up for sale. We did so in December, during the annual (North Slope areawide) lease sales. We said we were going to challenge federal foot-dragging, and we do so at every turn. Alaska’s voice has rung loud and clear.

“Finally, we are seeing Washington loosen its death-grip on the NPR-A and OCS,” Parnell said, in reference to the federal government’s recent approvals of a permit for a key bridge crossing providing access to the National Petroleum Reserve-Alaska, or NPR-A.

“The federal agency approval is for CD-5, which will mean a bridge over the Colville River that allows access to leases within the NPR-A,” Parnell said.

There are also recent approvals for exploration plans for Shell’s offshore exploration.

“Progress is slower than we’d like, and some of Washington’s decisions in this regard have been disingenuous. But there has been change. We’re thankful for it, and we’re going to keep on fighting,” the governor said.

Parnell laid our some action items as the Legislature opens its 2012 session in Juneau.

“We will restructure our oil tax system to increase production. We will build roads to resources, and you’ll note in my 2013 budget we have funds for a road to Umiat and the Ambler District. We will continue to make the case for a vibrant, business climate and a growing economy,” the governor said.

Looking at the long term, Parnell said the state will reach the goal of having 1 million barrels per day in 10 years. And noted there will be a gas line, he said.

Infrastructure investment is a key part of the plan, he added.

“That means Roads to Resources. Transportation infrastructure. Maintenance of public facilities. And there’s a $350 million bond package I propose putting before Alaska voters to upgrade ports in communities from Ketchikan to Anchorage to Emmonak,” Parnell said.

The state’s investment in a 600-megawatt hydro project in Watana, on the upper Susitna River, is also part of the plan, he said. Susitna-Watana means, “massive amounts of hydro power that will lower the cost of doing business all across the Railbelt, and grow jobs during the construction phase,” the governor said.

There is other recent good news, most notably the fact that Sen. Lisa Murkowski introduced a bill to move permitting for offshore drilling under the Clean Air Act from the Environmental Protection Agency to the Interior Department.

And, “we’ve got a great turn-around story in Cook Inlet, with new players coming in,” Parnell said. “LNG shipments have continued from Nikiski, in response to a changing market around the Pacific Rim. We’re seeing more exploration on the North Slope than we have for a few years.

“Mining – now there’s a strong trend for 2012,” he added. “Red Dog, Greens Creek, Usibelli, all accounting for massive increases in our exports. Donlin (gold mine) is closer to production, and numerous other mines of all sizes are in advanced stages of development. We’re launching our state’s rare earth element mining sector.”

According to the Alaska Miners Association, one-third of all mining exploration in the U.S. is happening in Alaska. And last year exploration in Alaska topped $260 million.

Tim Bradner can be reached at

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State Senate to float new ideas on oil tax changes

Tim Bradner
Alaska Journal of Commerce

Most of the attention on oil tax legislation has been focused on Gov. Sean Parnell’s House Bill 110, a bill that passed the state House last year and is now in the state Senate.

State senators meanwhile are working on their own ideas for oil tax changes, which will be brought forth in separate bill, or perhaps added to, or substituting for, the existing language in HB 110.

Sens. Tom Wagoner, R-Kenai, and Lesil McGuire, R-Anchorage, are crafting a new version of Senate Bill 85, a bill introduced by Wagoner, which takes a different approach in changing oil taxes than the governor’s bill. Last year Wagoner, who is co-chair of the Senate Resources Committee, attempted a variation of a tax incentive used in Alberta, where companies investing in new development get a speedy recovery of their capital.

Wagoner spoke with other legislators at Jan. 5 meeting of the Resource Development Council in Anchorage. Speaking at the same meeting, House Speaker Mike Chenault, R-Nikiski, said he expected some version of an oil tax change to pass in 2012 and that the House is waiting to see what ideas are developed in the Senate in addition to Parnell’s proposal.

Chenault said most of the attention will be on the “progressivity” formula in the production tax, a formula that escalates the tax rate sharply as oil prices climb, as well as the investment tax credits allowed in the current law. Sen. Bert Stedman, R-Sitka, is reported to be working on his own proposal for changes to the tax. Stedman is co-chair of the Senate Finance Committee.

Wagoner said there are problems with the original version of his SB 85, so a new approach is being crafted in consultation with McGuire, Wagoner said. An idea being studied is a “tax holiday” for new oil production, a period during which there would be no state taxes on new oil that is developed.

Wagoner said he has solicited, and is receiving, technical advice from the Alaska Oil and Gas Association on the idea. AOGA is the petroleum industry’s trade association for Alaska. An oil company tax specialist, speaking on background, confirmed that industry tax specialists are offering advice through the trade association. The idea of a tax holiday on new production is not new and has proven to be effective elsewhere.

Wagoner also said he will seek legislation through a new bill or an amendment to an existing bill to extend the special Cook Inlet jack-up rig investment incentives to the Nenana Basin, an underexplored Interior Alaska sedimentary basin west of Fairbanks, where there is potential for natural gas discoveries and possibly oil.

Doyon Ltd., the Interior Alaska Native regional corporation, is now leading a consortium of Alaska companies intent on exploring state lands in the Nenana Basin. One exploration well was drilled two years ago, and although it did not find a commercial gas deposit, the information yielded confirmed the presence of hydrocarbons in the basin.

Doyon is now doing seismic work in another part of the basin and a well may be planned there if the results are favorable, but being able to use a set of investment tax credits similar to those available to new offshore explorers in Cook Inlet would greatly speed the exploration.

If gas is found in the basin, and enough of it, a 60-mile pipeline could be built to bring gas to Fairbanks.

Read more:

I will be supportive of Senate Bill 85 only if the Competitive Review Board remains in the bill. - Deborah Brollini Please listen to the audio from Sen. McGuire's comments from Senate Resources Committee on 4/4/11 (highlighted below)

SCR4: Creating and relating to the Alaska Oil and Gas Competitiveness Review Task Force

Alaska's Future: Sen. McGuire's proposed competitiveness review is important

Energizing Investment in Alberta

SB 85

SB 85: Documents (4/4/11 Competitive Review)

SB 85 Senate Resources Hearing (Audio): Mary Jackson, Staff to Senator Thomas Wagoner, and Michael Pawlowski, staff to Senator Lesil McGuire, testimony to Senate Resources on March 25, 2011.

SB 85 Senate Resources Hearing (Audio): Catherine P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission, and et al and invited testimony (4:41)

SB 85 Senate Resources hearing (Audio): Invited and public testimony (3/30/11)

SB 85 Senate Resources Hearing (Audio): Michael Pawlowski, staff to Senator Lesil McGuire testimony, and Senator McGuire’s comments on the Oil and Gas Competitiveness Review (OGCR) Board. Senator McGuire asks for recommendations rather than a “no” (4/4/11 at 3:38)

Alaska’s Oil Investment Tax Structure, Establishing A Competitive Alaska, Commonwealth North, March 2011

Time to move beyond talk as legislative session starts

By Lee Leschper
Alaska regional vice president for Morris Communications

We’re off to an interesting start on what could be an historic year.

Already this year Gov. Sean Parnell has gathered a room full of movers and shakers, with the CEOs of Alaska’s big three oil companies, to talk about the potential for a natural gas pipeline to produce liquefied natural gas for sale in the Far East.

It’s in keeping with his commitment to do what it takes to refill the trans-Alaska oil pipeline with 1 million barrels of oil a day. And the opening round in a legislative session that starts this week in Juneau with some big expectations and bigger challenges.

This is the leadership we need from the governor. Great things always start just such a vision. Connecting the dots, moving from vision to action, will be a larger undertaking.

The Jan. 6 Meet Alaska conference, the annual gathering of the Alaska Industry Support Alliance, got down to detail and to reinforce the need for a change in tax law to attain that goal.

Specifically, BP Exploration (Alaska) Inc.’s John Minge said that only a big change in Alaska oil tax policy will bring more oil company investments to the state. And that it will take a $150 billion investment from those players to generate those million barrels a day.

The state Department of Revenue’s Bruce Tangeman was equally emphatic, saying that only radical changes, not just a few tweaks on the oil tax’s reciprocity, will bring that investment to Alaska.

Is it the right time?

Clearly the vast majority of Alaskans, in and out of the oil business, want action.

Alaska’s Clear and Equitable Share, ACES, was passed in large part because the timing was right, because both voters and legislators agreed the state deserved a bigger share of oil profits.

They united behind then-new Gov. Sarah Palin to demand a bigger cut for the state. And in the final version of ACES, the Legislature demanded even more. The whole process happened in weeks, really just days, so it’s reasonable to expect it was a bold but imperfect draft. It was also based on a lot of projections.

It made great sense in 2006. Does it still?

Aggressive taxation may have made sense when there were fewer alternatives to Alaska oil. That is no longer the case. Now it is time to review five years of history under ACES, with real data, and work to improve the plan.

There seems almost universal agreement it’s got to address reciprocity and reward both exploration and production, with rewards for both the state and the oil companies. It’s got to be a win-win for the industry, Alaskans and Alaska businesses.

It can’t abandon the expectation that Alaskans get a fair return.

The next generation of Alaska oil tax codes has to continue to protect the 90 percent of Alaska’s operating revenue that oil generates.

We also have to understand that the more radical the proposed changes, the less chance we can expect agreement in the Legislature.

It’s not said often enough that ACES hasn’t been all bad for the state. During these last few brutal economic years, when most of other states are sinking deeper into bankruptcy, Alaska has added billions to our reserve.

BP’s Minge pointed out last week that the oil industry makes billion-dollar decisions based on expectations 50 years into the future. We need to have that same 50-year vision for the state.

Is it realistic that any new oil program works whether oil is selling at $80 or $180 a barrel, and whether gas is $2 or $10, whether the customer is China or the Lower 48?

Time will tell.

The perception is that Legislature does most of its work in a flurry at the end of the 90-day session. Let’s not waste those 90 days this year. Lawmakers have heard for months – since well before the 2011 session – that ACES needed changing, that the big producers won’t invest the big money to find and produce new oil in the current tax environment.

Alaskans share an expectation — that their elected officials will do their jobs, will work together and compromise to make real and positive legislation to benefit all Alaskans as well as to the businesses that provide us the economic benefits we have come to rely on.

That meaningful work must begin from Day 1 of the session.

Lee Leschper is Alaska regional vice president for Morris Communications publications including the Alaska Journal of Commerce. Email him at

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Friday, January 6, 2012

Battle on ACES tweaks to dominate session

Analysis by Tim Bradner
Alaska Journal of Commerce

The 2012 state legislative session convenes Jan. 17, and probably the most important bill on the session agenda besides the budget is Gov. Sean Parnell’s bill to reduce the state oil production tax as an incentive for new industry investment. It will be a very contentious issue and it may preoccupy legislators in terms of dealing with other significant matters, excepting the state capital budget.

There will be tough sledding for the governor on this bill as it was in 2011. Senate Democrats, who are partners in the Republican-Democratic Senate leadership coalition, appear to be dug into their positions opposing House Bill 110, the governor’s bill that passed the House last session.

However, there may be some room for optimism. In a December talk to Commonwealth North, an Anchorage-based public policy group, Senate President Gary Stevens, R-Kodiak, said the Senate Majority would examine the tax and particularly the “progessivity” formula, a formula in the tax that ratchets up the tax rate as oil prices climb.

Another key Senate leader, Sen. Bert Stedman, R-Sitka, said in legislative committee interim meetings this fall that he recognizes that state taxes on North Slope oil and gas operators merits a close look, and that a mismatch now exists between the industry’s economic situation in Cook Inlet, where there are virtually no state taxes, and the North Slope.

The action on HB 110, will take place mainly in the Senate. It passed the House last March by a vote of 22 to 16, a narrow margin because 21 votes are needed to pass a bill in the 40-member House. HB 110 is now in the Senate Labor and Commerce Committee, which held hearings last summer on employment aspects of the legislation with a focus on local-hire in the oil and gas industry. If the bill moves from the Labor and Commerce Committee it would go to the Senate Resources Committee and then to the Finance Committee.

HB 110 is important because it seeks to stimulate industry investment on the North Slope, hopefully stabilizing or reversing the decline in production. Critics argue the bill gives back too much to the industry and that there are no guarantees that new investments would actually be made. Last year the industry was not able to convince legislators, particularly in the Senate, that investments would occur if tax relief were given.

Near the end of the session ConocoPhillips’ CEO Jim Mulva came to Alaska and in a talk to an Anchorage business group, came as close as any senior executive can come in making a guarantee that a billion dollar-plus project in the west part of Prudhoe Bay would move forward if the tax were adjusted.

Guarantees like this are difficult for public companies because boards of directors ordinarily approve projects. Also, ConocoPhillips has partners in the Prudhoe field, which also must give approvals. In this case, BP’s Alaska president echoed Mulva’s commitment in a separate speech a few days later.

It was, however, too late in the session. Attitudes in the Legislature had already hardened.

The major producing companies, and the governor, argue that there is insufficient new investment on the North Slope in projects that will produce new oil, such as new production wells in the existing fields and projects to increase production of lower-quality oil, such as thick, or viscous, oil now being produced in limited quantities.

Substantial capital investments are being made in the North Slope oil fields, and these amounts are even increasing, according to state Department of Revenue data. But field operators say that much of this is focused on increased maintenance of aging facilities in the producing fields, and that money allocated for new production, such as new in-field drilling, is lagging.

ConocoPhillips, which operates the large Kuparuk field, has said that nearly 70 percent of its capital budget is now devoted to maintenance. A year ago the percentage devoted to maintenance was 60 percent. Given that the capital budgets of the two major operating companies, ConocoPhillips and BP, have been relatively static in recent years, about $900 million a year for each, this means less money is going to develop new oil in the producing fields.

New exploration no panacea

There is new exploration under way, but it is no panacea. The winter 2012 North Slope exploration drilling season looks to be the busiest in many years, but most of this is being driven by one company, Repsol, which has four to five rigs contracted.

Repsol has said it must develop an aggressive exploration program this winter because of expiration deadlines on some of the 500,000 acres of state leases in which it holds an interest. Absent Repsol, the winter exploration season looks about average, with three small independent companies planning test wells.

However, accumulations that might be discovered, at least on state-owned lands, are likely to be modest in size, even Repsol acknowledges. No large Prudhoe Bay-type finds are expected, in other words. Also, any discoveries will take several years to put into production because of the lead times needed to secure permits and build infrastructure like pads, wells, roads, utilities and pipelines.

In contrast, the governor and supporters of HB 110 argue that substantial additions of new oil could be put into production quickly enough to make a difference in slowing the production decline, but this must come from within the existing producing fields, where there is currently infrastructure.

In many cases the resources are known – the large deposits of viscous oil, for example – but the major producing companies say these projects are uneconomic to develop unless the existing state tax is changed.

The surge in exploration is also somewhat of an illusion in that the state itself is paying for much of the cost of the new wells, more than half in some cases, through exploration incentive tax credits in the production tax law. This has created an unusual situation of a tax subsidy for exploration of likely modest oil deposits but an overall tax law that discourages larger resources being developed in the larger fields, the supporters of HB 100 argue.

HB 110 changes the formula

The governor’s bill would address this by reducing the production tax rate and making other changes. The current tax is structured to increase the tax rate as crude oil prices rise to the point that, at the current range of oil prices, Alaska’s tax may be among the highest in the world. Given that the North Slope state-owned lands offer prospects of only modest discoveries and that access is costly, it can be seen why Lower 48 states are enjoying a surge of new industry investment and Alaska is not.

House Bill 110 reduces the tax by changing the “progressivity” formula in the law that causes the tax rate to escalate at high oil prices. The bill also “brackets” the tax law so that it works like the federal income tax, so that high tax rates apply only to the higher brackets of oil prices. The governor would also extend to the North Slope most of the investment tax credits and other incentives that now apply to Cook Inlet, where there is a resurgence of new industry exploration.

The argument against HB 110

The argument against HB 110 is mainly that the bill would result in a significant reduction in future state revenues – how much depends on the assumptions made – and there is no guarantee that new investment would follow.

With production declining, legislators are acutely aware of the fragility of the state’s future finances and are wary of giving up the certainty of revenues in the existing tax system without some clear guarantees that investments will be made that will result in new oil production, strengthening the fiscal outlook.

There seems to be wide political acceptance in the Legislature, even among opponents of HB 110, for the exploration investment tax credit approach, even to the point of the state paying for most of the cost of the new exploration. The difference between the two approaches is that HB 110 would cause a general reduction in taxes, while the investment tax credits, a different form of tax reduction, occur only after an investment is made.

This is an important point. For a long time the governor was lukewarm to the idea of a general tax reduction, like that now proposed as the core of HB 110, but supportive of tax reductions linked to performance, such as through an investment tax credit mechanism.

There appears to be considerable support in the Legislature for the concept of investment tax credits, as illustrated by the exploration credits, but obviously less support for the idea of a general tax reduction, mainly because of the lack of a guarantee. It would seem that a compromise, of some sort, would involve a tax change that reduces the overall tax rate, achieving the objectives of HB 110, but that is linked to some kind of performance guarantee.

It’s possible something like this could develop as the Legislature resumes work on the governor’s bill after Jan. 17.

Read more:

Thursday, January 5, 2012

South Korea natural gas needs lend opportunity for Alaska

Bob Tkacz
Alaska Journal of Commerce

SK Energy has opened 260 “recharging stations” like this one in South Seoul, since LPG and hybrid-powered cars and trucks arrived in Korea in 2009. LPG prices are posted in liter equivalents for convenient comparison to standard fuel costs. In this November 2010 photo LPG at 944 won per liter ($3.07 per US gallon). In November 2011 LPG at 1070 won (.925 cents/$3.49 per gallon) compared to $6.35/gallon for unleaded gasoline and $6.12 for diesel.

SK Energy has opened 260 “recharging stations” like this one in South Seoul, since LPG and hybrid-powered cars and trucks arrived in Korea in 2009. LPG prices are posted in liter equivalents for convenient comparison to standard fuel costs. In this November 2010 photo LPG at 944 won per liter ($3.07 per US gallon). In November 2011 LPG at 1070 won (.925 cents/$3.49 per gallon) compared to $6.35/gallon for unleaded gasoline and $6.12 for diesel.

Photo/Bob Tkacz/For the Journal

An unexpected increase in South Korea’s short-term natural gas demand, and uncertainties in the energy-poor country’s long-term supply outlook could open opportunities there for sales of Alaska’s clean energy.

While South Korea is making substantial investments in oil and gas from Canada, decision-makers in the Asian country lack information on what’s available from Alaska and state officials have made few, if any, attempts to open the market, according to Korean and U.S. officials there.

Officials said Alaska could improve its prospects for LNG sales to South Korea with some basic steps, some of which are already on the state’s agenda, but Alaska so far has made no toward that.

“We know very little so we did not include it in outlook and price projections,” for Alaska energy resources, said Jinwoo Kim, president and CEO of the Korea Energy Economics Institute, a government agency that tracks and projects Korean energy use and sources.

With virtually no domestic resources, energy is not only a necessity, but a national security issue in South Korea. With 48 million residents, it is the world’s tenth largest energy consumer, importing 97 percent of its energy.

“I do see that Korea will continue for a long time in the future to be the world’s second largest importer of natural gas (after Japan) and will stay that way for quite some time to come despite a lot of emphasis being done for renewable energies,” said Mark O’Grady, commercial attaché at the U.S. Embassy in Seoul.

Partly in response to President Lee Myung-bak’s “green growth/low carbon” initiative, as well as to climate change and oil market issues, South Korea has made dramatic changes in its energy supply and electrical power generation mix.

From 1981 to 2010, oil dropped from 58 percent to 40 percent of the country’s energy sourcing. As a fuel for electrical generation, oil has virtually disappeared, from nearly 80 percent in 1981 to less than 5 percent last year. Coal, including some imports from Alaska, fell slightly as a primary energy source to 29 percent from 33 percent over the same period, but remains an important fuel for electrical generation at 42 percent, up from 6 percent three decades ago.

Nuclear rose from nearly 2 percent to 12 percent of overall energy supplies during the same period and leapt from 7 percent of electrical generation to 31 percent last year. KEEI projections indicated it would generate nearly 60 percent of the South Korea’s electricity by 2030, but the Fukoshima Daiichi power plant disaster in Japan changed that.

“The Korean government has had a very aggressive nuclear expansion plan, but some other voices now coming from NGOs and other ordinary people to reconsider the nuclear expansion plan,” said Ki Joong Kim, the senior research fellow in KEEI’s oil and gas policy division. “If our government has to change their position on nuclear plant expansion then we might have more room to import LNG from other sources.”

Alternative energy now provides for 0.8 percent of Korea’s electrical. Projections call for an increase to 11 percent by 2030, but Jinwoo Kim called that a very optimistic expectation, which could further increase the demand for natural gas.

After nuclear power, natural gas has filled the gaps in Korea’s energy. From zero use in 1981 LNG accounted for 15.7 percent of the country’s energy supply and 20.4 percent of its electrical generation last year.

Korea’s natural gas demand was 31.2 million tons in 2010 and KEEI’s pre-Fukoshima projection showed an increase to 34.1 million tons by 2024. That included a short-term spike in gas use for electrical generation from 2014 to 2017 without, as yet, an identified supply.

The gas gap is projected to start closing in 2017, when a pipeline from Russia that would deliver 7 million tons of natural gas per year, but security questions over its route through North Korea continue to dog the project despite top level support from the South and Russia.

The agreement calls for negotiation, beginning in March, of a master project plan in time to start construction in 2013. South Korean critics continue to question the wisdom of handing North Korea a new tool to threaten the South.

The project schedule is still unclear.

“It’s not 100 percent sure yet. We just hope to start the construction work in the middle of 2013,” said Jinwoo Kim.

O’Grady noted that South Korea and Japan recently announced they have opened discussions to create an LNG “buying block.”

“I don’t know how far that will go, but recent media reports show that they just got through with initial discussions to try to figure out a way that they can harness the fact that they are the first and second biggest importers of LNG to work together to drive down the prices,” O’Grady said.

KEEI spokesmen said the world glut of natural gas allows buyers to demand more flexible terms from suppliers. Ki Joong Kim said U.S. gas could be a hedge against the uncertainty of the Russian project and that Gulf of Mexico producers have traditionally been “very flexible.”

He added that Alaska’s linkage of taxes on natural gas to its oil tax regime is a significant discouragement.

“If Alaskan gas wants to compete with Gulf area LNG, it must offer more flexible conditions,” Ki Joong Kim said.

Some Alaska legislative leaders have said decoupling the state’s oil and gas tax regimes should wait until shippers and TransCanada Corp. come to terms on the Alaska Pipeline Project.

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BP, ConocoPhillips endorse LNG project as best for North Slope gas

Tim Bradner
Alaska Journal of Commerce

BP and ConocoPhillips now believe a major liquefied natural gas project is the best option for marketing North Slope gas, the chief executive officers of the two companies said following meetings with Gov. Sean Parnell Thursday morning.

Robert Dudley of BP, James Mulva of ConocoPhillips and Rex Tillerson of ExxonMobil met with Parnell and then, along with the governor, briefed state legislators on the talks in a separate meeting.

Parnell met with the CEOs to discuss how to align the major Slope producers on a major gas project. ExxonMobil Corp., another major producer, participated in the meetings but did not comment afterward while the leaders of BP and ConocoPhillips said their companies now believe LNG is the best way of marketing gas from the Slope.

“Given the outlook with shale gas in the Lower 48, it looks like LNG has the best potential. We’re not saying the pipeline (to Canada) is impossible,” but a pipeline to southern Alaska to an LNG plant appears to have the best prospects, BP CEO Dudley told reporters following the meetings with Parnell and legislators.

ConocoPhillips’ Mulva agreed with Dudley.

“We believe LNG is the best alternative for North Slope gas, far better than any alternatives,” Mulva said.

Parnell said the three companies have agreed to work with the state on a review of all alternatives including an LNG export project as an alternative to an all-land pipeline from the North Slope to Alberta.

TransCanada and ExxonMobil are now pursuing a land pipeline with state support under the Alaska Gas Inducement Act, or AGIA, but Parnell said an LNG project could be done under the framework of the existing agreement with TransCanada.

AGIA includes a provision that an LNG project can be done as an alternative.

The AGIA contract provides for the state to provide up to $500 million in grants to support engineering and environmental work in return for TransCanada and ExxonMobil meeting certain state requirements on schedules and tariff structure.

AGIA requires TransCanada to file an application for a land pipeline with the U.S. Federal Energy Regulatory Commission this October.

TransCanada vice president Tony Palmer, who attended the noon meeting with legislators but did not participate in the meetings of the CEOs with Parnell, said he supports the new initiative and that the meeting of the three CEOs with Parnell was hugely important.

An LNG alternative would involve a large-diameter, 800-mile pipeline to an LNG plant at a south Alaska port, either at Valdez or near Kenai, on Cook Inlet. ConocoPhillips operates a small LNG plant near Kenai that exports Cook Inlet gas to Asia.

Valdez has also been considered in the past as a possible LNG plant site because of the deep water harbor, and proximity to infrastructure along the existing Trans Alaska Pipeline System and the Valdez Marine Terminal, which ships crude oil.

Cook Inlet is navigable for smaller LNG tankers now used by ConocoPhillips but may have limitations that would impede an expansion of the present LNG plant.

Parnell has been urging the producers to shift their support from an all-land pipeline from Alaska to Alberta to an LNG project to export Alaska gas to Asia. The glut of shale gas in Lower 48 gas markets and continued strong markets for LNG in Asia now make an LNG project more viable than a land pipeline, Parnell has said.

There has been substantial previous work on a large Alaska LNG project as well as previous efforts on an all-land pipeline. In the 1990s BP, ARCO Alaska (now ConocoPhillips), Foothills Pipeline (now TransCanada) along with Marubeni, a major Japanese company, did conceptual feasibility studies of a pipeline to Valdez parallel to TAPS and an LNG plant built adjacent to the Valdez Marine Terminal.

The project did not move forward because the companies felt the Asia LNG market would not be able to absorb sufficient volumes of Alaska LNG to make the project viable.

A separate initiative was led by Yukon Pacific Corp., or YPC, a subsidiary of CSX, a major U.S. transportation company. YPC obtained conditional rights-of-way for the pipeline and a lease for the LNG plant along with a federal LNG export license, but the company was never able to get support from the North Slope producers.

The producers’ and TransCanada’s current work on a land pipeline began in 2001. It followed a failed attempt by an earlier consortium of U.S. utilities and North Slope producers to build a pipeline in the early 1980s. Changes in U.S. gas markets and deregulation of the gas industry made that project uneconomic.

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State officials visit China to spark interest in LNG export

Tim Bradner
Alaska Journal of Commerce

Gov. Sean Parnell has tilted the state’s support toward a large liquefied natural gas, or LNG, export project for North Slope gas, and senior state officials are talking up the idea in Asia.

“We realize deals will be cut by the parties involved, but we want to make sure people in Asia know about Alaska and our potential,” said Dan Sullivan, state commissioner of Natural Resources.

Sullivan and Deputy State Commerce Commissioner Curtis Thayer were in China in mid-November to attend a high level Asia regional energy conference and to meet with senior government and private-sector officials who influence China’s energy policies.

Sullivan had been invited to address the Asia Pipeline Summit, a major conference, held in Beijing Nov. 16. While there, he and Thayer organized a number of appointments to talk about Alaska.

“This was part of a broader effort we are making to promote a better understanding of what is going on in Alaska, and of our resource potential, in the aftermath of the governor’s speech,” announcing the shift to supporting an LNG project.

“The governor was in Europe to meet with BP and Shell, along with attending a seafood marketing event, and Commissioners (Susan) Bell and (Marc) Luiken were also in China at about the same time we were to make calls on seafood buyers and air carriers,” Sullivan said.

The Asia pipeline conference itself was attended by 150 to 200 people, Sullivan estimated, and included a cross-section of government and private officials from several nations interested in energy development and transportation in Asia.

Sullivan’s presentation to the conference was a version of the talk about Alaska’s oil and gas potential he has given many times at conferences and private meetings, highlighting the oil and gas resource base.

Several points were tailored to the audience in Beijing, however. One is that Alaska is currently the only U.S. state exporting gas, in the form of LNG, to Asia. The state has a 40-year record as a reliable supplier of LNG to utilities in Japan. In 2011 the first LNG shipments were made from Alaska to China.

“A lot of people in Asia don’t know about Alaska’s track record as a reliable supplier,” Sullivan said.

Secondly, Alaska’s North Slope gas is “wet” with natural gas liquids mixed with the methane, the main component of natural gas used for heating. This is important because natural gas liquids like ethane are important in the manufacture of other products.

“Wet gas is more valuable than dry gas as a petrochemical feedstock – it contains more of the larger (hydrocarbon) molecules that can be refined and reconfigured into more varied compounds,” Sullivan said in his presentation at the conference.

Among all of the advantages of doing energy business with Alaska, one that seemed to impress people the most was geographic diversification of energy supply sources.

“If China is going to buy more LNG, these people don’t want to be bound to two or three supply sources,” Sullivan said. “Most of the presentation was what I make to others, but people in China were still impressed at how large just the conventional resources are, to say nothing of the unconventional. When I explained that we produce and re-inject 8 (billion) to 9 billion cubic feet of gas daily on the North Slope, a lot of people express disbelief. That’s about the average gas consumption of Canada.”

In addition to the conference, Sullivan met with officials at the Ministry of Finance; China Council for the Promotion of International Trade; The Clean Air Task Force; Goldman Sachs; National Energy Administration; and the CITIC Group. He also met with U.S. Ambassador Gary Locke and other officials at the U.S. Embassy.

Thayer attended many of the meetings.

Potato trade

On a different topic – Alaska seed potatoes – Sullivan met with officials from Heilongjiang Province, including one who had flown to Beijing just to meet with the commissioner.

“They are interested in buying seed potatoes from Alaska and collaborating in research,” Sullivan said.

On returning to Alaska, the commissioner passed the information on to officials in the state Division of Agriculture, which is part of the Department of Natural Resources headed by Sullivan.

Sullivan has previous experience in China from his days working in the U.S. State Department as an assistant secretary of state responsible for energy, among other areas, and has attended dozens meetings there. The experience proved useful on the November trip.

“I’m not a China expert but you get a sense of when someone is just being polite in a meeting. In these meetings there were a lot of questions and some meetings that were scheduled for 45 minutes turned into an hour and a half,” Sullivan said.

Everything learned there has been passed on to the Alaska producing companies, which would actually negotiate any contracts, the commissioner said.

Thayer said he was impressed with how much some officials knew about Alaska even before the meetings.

“They knew about our decline in production and pipeline throughput, and wanted to know what we are doing about it,” Thayer said.

Also, although political concerns over energy ties with the U.S. didn’t surface in talks directly, the subject came up in oblique ways.

“There was concern as to how the U.S. government would view exports of gas to China,” he said.

The U.S. government’s rejection of a bid by a major Chinese company to buy Union Oil Co. of California was mentioned.

Alaska’s rejection four years ago of a bid by major Chinese energy company Sinopec in the Alaska Gasline Inducement Act solicitations did not come up in talks, Sullivan said. Although there were political concerns raised at the time by Alaska’s congressional delegation the company’s AGIA application had other problems with its qualification, the commissioner said. Sinopec was represented by an Alaska company owned by a Chinese-American.

Although China has not yet made a direct investment in Alaska natural resources, Chinese companies are indirectly involved through other parties, Sullivan said. For example, a Chinese company owns a substantial share of Teck, which operates the Red Dog and Pogo mines in Alaska. Also, another Chinese company has an agreement to purchase gold produced at the Kensington Mine near Juneau.

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Congress cuts funding for Alaska federal gas coordinator by 75%

Tim Bradner
Alaska Journal of Commerce

The budget for the Alaska federal pipeline coordinator has been reduced by 75 percent to $1 million for federal fiscal year 2012, Larry Persily, director of the office said Jan. 4.

The action was taken in the House-Senate budget conference committee. It is an indication that some in Congress doubt a proposed $40 billion-plus Alaska natural gas pipeline will be built anytime soon.

Persily said the office has $2.25 million in funds remaining from its fiscal 2011 appropriation, and those funds, along with the $1 million for fiscal 2012, is sufficient to cover the expected workload for the office over the next two to three years. There will have to be some reductions in the 10-person office staff, he said.

The federal coordinator’s office was established to oversee federal agencies’ responses to permit applications for the pipeline, which would deliver 4 billion cubic feet a day of gas to Alberta, from where it would be shipped on through other pipelines to the continental U.S.

“Whether the federal coordinator’s office has $1 million, $2 million or $3 million, or whether it has eight employees or 10, isn’t going to affect the project. What is going to determine the future of the Alaska gas line is the state’s fiscal system on oil and gas, and the natural gas market,” Persily said.

A glut of shale gas in North American markets has dampened prospects for the large Alaska pipeline. In addition, North Slope gas producers are seeking a long-term fiscal agreement with the state of Alaska before committing to ship gas through a pipeline.

Persily said his plan assumes TransCanada Corp. and ExxonMobil Corp. will proceed with the filing of an application with the U.S. Federal Energy Regulatory Commission for their proposed 48-inch pipeline from Alaska to Alberta next October, as the two companies are required to do under a contract with the state of Alaska, Persily said.

The state of Alaska is contributing $500 million to preliminary engineering and environmental work for the project on the condition that TransCanada and ExxonMobil meet certain performance benchmarks, the most important being the filing of the application to FERC in late 2012.

Although the two companies are contractually committed to continue work on the pipeline to Alberta Alaska, Gov. Sean Parnell has asked TransCanada and ExxonMobil and other North Slope producers to consider a pipeline to a southern Alaska port and an LNG project that would export Alaska gas to Asia.

The alternative LNG project could be done under terms of the existing contract the companies have with the state, which includes the option of LNG instead of an all-land pipeline.

Cost-saving moves will include vacating the federal coordinator’s 13,000-square-foot office in Washington, D.C., which costs $750,000 a year in lease fees, Persily said. The office in Washington will not close, however, and the office in Anchorage will also remain open, he said.

“I expect layoffs and other spending cuts,” Persily said, although there are as yet no details of reductions.

“I don’t think Congress was trying to send a particular message with the cut. They are starting to wonder what is going on, however. Congress passed the loan guarantees, tax breaks, expedited FERC schedule and establishment of our enabling office in 2004. The $1 million, plus our reserves, will get us by until something happens, or not,” Persily said.

Tim Bradner can be reached at

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