Sunday, December 30, 2012

New AGDC bill to be offered, separating agency from AHFC

—Kristen Nelson

The Alaska Gasline Development Corp., AGDC, was established by the Alaska Legislature in 2010 to develop an in-state natural gas pipeline, called ASAP — the Alaska Stand Alone Gas Pipeline.

AGDC was set up as a subsidiary of the Alaska Housing Finance Corp. with a legislative mandate to get North Slope natural gas to Alaska consumers at the least possible cost. The original legislation, House Bill 369, established a timetable for the project and required that a project be presented to the Legislature by July 2011.

AGDC met the project requirement, but has been working with what it calls an optimized schedule and is now looking at first gas in 2019, rather than in 2015 as mandated in HB369.

A bill to expand AGDC’s authority was introduced last year by House Speaker Mike Chenault, R-Nikiski, and championed by one of the co-sponsors, Rep. Mike Hawker, R-Anchorage. House Bill 9, 32 pages in length, passed the House in March of 2012, but failed to find traction in the Senate.

Chenault and Hawker told a Dec. 20 meeting of the Alaska Legislature’s Joint In-State Gas Caucus that a bill based on HB9 would be pre-filed for the upcoming 2013 Legislature.

Hawker said the new bill, currently 42 pages in length, expands on HB9, and is intended to provide AGDC “with the greatest possible power to advance that in-state natural gas pipeline.”

Statutory obligation

Hawker said the agency would continue to have the statutory obligation to get that natural gas to Alaskans at the least possible cost, and he said that if the project being worked by TransCanada and the North Slope majors under the Alaska Gasline Incentive Act, AGIA, or any other “purely private sector” line comes to fruition, “AGDC will be there able to play a role representing our interests.”

If a private sector project doesn’t come together, “we will be able to pursue a project that continues to meet the needs of the State of Alaska.”

He said he and Chenault “believe in the private sector,” but believe the state needs to provide “an environment and a catalyst that will move projects forward and should the private sector be unable or unwilling to perform, we have to look at getting natural gas into the hands of Alaskans as a public works project, just like highways, water and sewer systems. ...”

AGDC has “elevated the energy security for the state of Alaska to a priority state mission,” Hawker said.

The new bill is based on HB9, he said, and is a project compatible with AGIA, not competitive.

If an AGIA project goes ahead, AGDC will give the state a seat at the table; if AGIA turns out to be a dead end, AGDC can “move Alaska’s gas forward at the direction of the Legislature,” Hawker said.

Significant change

Hawker said there is one significant change in the new legislation: It “will physically relocate the operations of AGDC as a corporate entity out of Alaska Housing Finance Corporation.”

AGDC has been a subsidiary of AHFC, but he said it’s time to “move AGDC into the big leagues,” and the legislation would establish it as a standalone public corporation in the Department of Commerce and Economic Development. AGDC would, he said, exist much like the Alaska Railroad and AHFC exist, with AHFC’s corporate statutes used as a template.

AGDC would have its own board of directors and the legislation proposes that the governor would appoint directors with “specific expertise in the things necessary to build, operate, manage pipeline and distribute natural gas.”

As in HB9, ANGDA — the voter-created Alaska Natural Gas Development Authority — would be preserved as “a marketing entity for the state’s gas,” Hawker said. A pipeline builder has to be separate from a pipeline shipper and ANGDA would be able to act as an aggregator and marketer to help coordinate gas buys for Alaska communities and utilities who individually “may not have the wherewithal nor the, both the level of demand nor the economic ability to make 30-year long-term commitments,” he said.

Hawker described the new bill has having “all of the provisions we had in the last House Bill 9 as well as some optimization” to provide statutory authority AGDC needs to move forward, including removing “some of the bureaucratic roadblocks” that AGDC faces.

The bill would allow AGDC to issue revenue bonds, project financing based on the merits of the project, and allow for confidentiality so that AGDC can exchange data with commercial entities and other state agencies.

Contract carrier

Hawker said there have been technical revisions and improvements to the section providing the regulatory framework for contract carriage, which would be a separate section within Regulatory Commission of Alaska statues so current RCA regulations and statutes won’t be impacted.

The new section on contract carriage would be applicable to any project, not just AGDC.

And the legislation would make sure AGDC has “the statutory authority to conduct further build outs” and projects that would deliver gas to other areas of the state. This won’t change what the Alaska Energy Authority or the Alaska Industrial Development and Export Authority do, he said, but would allow AGDC to facilitate pipelines throughout the state once the decision is made to do a project.


The maximum state investment in AGDC would be $400 million, Hawker said.

There is $200 million which has been parked but must be re-appropriated for the project, he said. The governor has proposed $25 million in his budget, and about $100 million more is needed to bring the total to $400 million, including some $73 million previously committed.

Hawker compared this $400 million to the $500 million the state had put into AGIA.

The $400 million, he said is “money in the hands of a state agency that we can control that is accountable to us and ultimately to the people of Alaska,” which he contrasted to the $500 million where there is “no accountability to the people of the state of Alaska.”

Read more:

ASAP to carry lean gas; In-state gas line plan simplified — no NGLs, lower pressure, no straddle plant

Kristen Nelson
Petroleum News

Plans for ASAP, the Alaska Stand Alone Pipeline, have been simplified, with the proposal to ship natural gas liquids removed from the plan, allowing for lower pipeline pressure and easier offtake along the line.

The optimized plan also has a larger, 36-inch diameter pipe, allowing the project to use industry-standard pipe, fittings and valves, Frank Richards told the Alaska Legislature’s Joint In-State Gas Caucus Dec. 20.

Richards, manager of pipeline engineering for the Alaska Gasline Development Corp., established by the Legislature in 2010 to develop a natural gas pipeline project, said the new design premise contrasts with the proposal presented to the Legislature in 2011, which called for a 737-mile, 24-inch, high-pressure line. The proposed pressure, 2,500 pounds per square inch, was required because of the enriched gas composition, he said.

But the 2,500 psi pressure meant that a straddle plant was required to deliver natural gas to Fairbanks, “a plant that would allow the natural gas liquids that were entrained in that gas stream to be pulled out, gas to be depressurized” for shipment to Fairbanks. The extracted NGLs would also have to be “reinjected back into the line and then brought down to Cook Inlet where there was going to be a natural gas liquid, or NGL, extraction facility,” Richards said.

The straddle plant made the tariff higher for Fairbanks than for Anchorage, a feature of the 2011 plan which drew considerable objection from Fairbanks legislators.

‘Awash’ in NGLs

The facilities needed for NGLs are expensive, Richards said, that plan was based on “a market where natural gas liquids were at a premium,” and that premium for NGLs was going to help reduce the cost of natural gas for citizens of the state. “However, the world has changed in the last couple years,” he said. “Now we see that the world is awash with natural gas liquids,” because of Lower 48 shale gas production, and NGL prices “have softened considerably, down nearly 60 percent over the last couple of years.”

There is “an NGL glut in the Lower 48,” Daryl Kleppin, AGDC’s commercial manager, told the caucus.

Kleppin said companies have been losing money on the NGL portion of their business, although petrochemical companies are benefitting from the NGL glut because they can make product from very low-priced feedstock.

Alaska’s “problem is that we have to transport those components over 700 miles and pay the tariff on them and the tariff is, well in most cases would be higher than the end value of the product,” he said.

Kleppin said that in conversations AGDC has had with potential shippers, “no one really had an interest in those components.” And “it makes the project a lot simpler if you take those out.”

Components no longer needed once NGLs are taken out of the plan include straddle plants for offtake along the line, the NGL extraction plant, a fractionation facility and intermediate compressor stations.

Entraining NGLs in the gas stream required a higher pressure.

“The higher pressure of 2,500 psi meant that we were not at industry standard piping, fittings and valves,” Richards said. The “high-pressure pipe comes at an extreme premium” for the pipe, the fittings and the values, raising the cost of the project.

And the enriched gas stream, at higher pressure, meant fewer takeoff points because of the high cost of straddle plants, limiting “the amount of gas available to Alaskans along the route.”

Evolution of project

Richards said the project evolved.

As AGDC looked at the engineering and economic aspects of the project, modifications were made to meet the charge AGDC had been given or providing natural gas in “the quickest possible timeframe, (at the) lowest possible cost to Alaskans.”

With the elimination of NGLs, the pipeline size was increased to a 36-inch diameter and the pressure decreased to 1,480 psi, “industry standard for not only the pipe, but the valves.”

The bill would allow AGDC to issue revenue bonds, project financing based on the merits of the project, and allow for confidentiality so that AGDC can exchange data with commercial entities and other state agencies.

The elimination of compressor stations along the line reduces the operating costs and the environmental footprint, he said.

Tariff drivers

With the changes in the project, including how the tariff is calculated, the projected tariff is lower, Kleppin said.

One change is that the tariffs are now calculated over a longer period, 30 years vs. 20 years in the 2011 plan.

Capital cost estimates have been updated and contingencies for different components have been adjusted, Kleppin said.

The key components of change are the lower operating pressure and the 36-inch diameter vs. the original 24 inches.

There is still a lot of engineering work required before costs can be finalized — and the requirements of shippers are not yet known, he said.

With the changes, the tariff is still within the original range for Anchorage, but the Fairbanks tariff “is significantly lower” with the main driver there elimination of the straddle plant, the cost of which was borne only by Fairbanks.

Cost at $7.7 billion

The current cost, on a plus or minus 30 percent basis, is $7.7 billion, compared to the $7.5 billion estimate in 2011. “Inflation over the last year has added almost $200 million to the cost of the original concept, so $7.7 (billion) is essentially the cost estimate for both project,” Richards said, with and without NGLs. Each year of project delay adds 2.5 percent to 3 percent inflation to the cost of the project.

The optimized plan has “less risk going forward” without the NGL component and the higher pressures in the line.

The cost to consumers at the burner tip for the optimized case is $9-$11.25 per million Btu in 2012 dollars in Anchorage and $8.25-$10 per million Btu in 2012 dollars in Fairbanks. That compares to the 2011 case of $9.63 per million Btu in Anchorage and $10.45 per million Btu in Fairbanks.

Contingent on funding

Richards said AGDC received $25 million in this year’s capital budget and has “been able to continue some of the pipeline engineering work” and is initiating some of the facilities engineering work.

But staying on schedule, with an open season in 2014, a go/no-go decision in late 2015 and first gas in late 2019, “really depends on what we receive in funding and how much work we’re able to do,” he said.

If AGDC is again partially funded work would be done on advancing the pipeline and facilities, with limited field investigations.

“If we’re fully funded then we will advance through what is known as the front-end loading 2 phase of our design for both pipelines and facility engineering to get us to that class 3 estimate for an open season,” Richards said, with heavy engagement with regulators, including the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, but also environmental regulators, followed by “a very extensive engineering field investigation program in 2013 to advance those projects.”

The state’s contribution, including some $73 million AGDC has already received, would total $400 million “to advance the project through to project sanction.”

“That’s getting through an open season, successfully acquiring shippers and purchasers of the gas, and then getting to a point of having to decide whether to go/no-go on the project to the next phase ... build out,” Richards said.

For consumers

The optimized cost and tariff means that consumers in “Anchorage will see rates ranging from $9 to $11.25 per million Btu in 2012 dollars. That’s comparable to what we’re likely going to be paying in 2013, with the cost increases that we’re hearing from our utilities,” Richards said.

That compares to the 2011 base case, with NGLs, of $9.63, he said.

In Fairbanks, “the optimized case provides gas at $8.25 to $10 per million Btu as opposed to the $10.75 we were projecting last year,” and compares to some $23 per million Btu Fairbanks is now paying, based on the cost of diesel for home heating.

“And then any community along the line that wants to tap in and have natural gas as an option for their home heating or power generation would see comparable rates available to them. And any resource developer that is looking to provide for jobs and resource extraction could gain access to reasonably priced gas,” Richards said.

Confidentiality issue

Richards said many of the features of House Bill 9, which passed the House but got no traction in the Senate in the 2012 legislative session, “are still needed to be able to move this project forward.” We need sufficient funding, he said, and because AGDC lacks confidentiality abilities which were included in HB9, because “we are subject to the open records act, and then folks feel that they can’t really share anything with us without it being flat open to the world.”

Ownership of the line is also an issue that needs to be determined, he said.

AGDC is working to determine that the project would be economically viable, “but in the end there’s going to have to be a builder-owner-operator and we need that ability to make that decision.”

Regulatory Commission of Alaska statutes are also an issue, because they “currently don’t cover contract carriage.” The current law is common carriage, he said, which means anybody that wants to ship gas is granted access.

The challenge is illustrated by utilities, he said, who need to know that volumes they expect are available to meet their power load requirements. With common carriage, existing shippers would be forced to reduce their rates to accommodate the new shipper, and “the end user, the utility” would get less gas.

“Under contract carriage it is a contract between the shipper and the buyer of that gas” and the utility knows that they will receive that volume.

Friday, December 28, 2012

Pivotal year ahead for oil and gas

Tim Bradner
Alaska Journal of Commerce

The year 2013 could be pivotal for Alaska’s oil and gas industry. To breathe new life into the state’s aging, and declining, North Slope oil fields, the Legislature will consider once again a reform of the state’s oil and gas production tax.

Gov. Sean Parnell argues the tax is too high compared with other producing regions and is impeding the industry investment needed to stem a continuing 6 percent annual decline in oil production.

Parnell is expected to introduce a bill making changes when the Legislature convenes in Juneau Jan. 15.

A critical question for legislators will be whether a tax decrease can somehow be linked to a demonstration of increased production in the large producing fields. This was one of the key issues which caused the failure of the legislation in the 2012 session.

Writing a tax bill that would accomplish this is complicated, however.

There seems wide agreement in the Legislature that new fields outside of the existing producing fields could receive a tax break. However, much of the potential for new oil yet to be developed on the Slope, particularly in the near-term, are prospects within the existing fields where there is infrastructure that is in place.

The potential for large oil discoveries in new fields on the North Slope, outside of the Arctic National Wildlife Refuge, is quite limited.

ANWR is off-limits to exploration until Congress approves it.

Another key development in 2013, hopefully in the first half of the year, would be the first substantial step by North Slope producing companies and TransCanada Corp., a pipeline company, on a large-diameter natural gas pipeline and liquefied natural gas, or LNG, export project.

That step would be a decision to begin “pre-Front End Engineering and Design” on the giant project, a step that will involve expenditures of several hundred million dollars.

The companies are now in the “concept development” stage, a very preliminary scoping of options. When the pre-FEED decision is made, several important decisions will have been made including a proposed southern terminus for the pipeline and location for the LNG plant.

Valdez and Cook Inlet are the leading contenders for the location of the plant.

A separate gas pipeline project, related indirectly to the bigger pipeline plan, is the state’s proposed project to build a 36-inch pipeline from Prudhoe Bay to Southcentral Alaska to serve communities and industrial customers in Alaska.

This is being worked on by the Alaska Gasline Development Corp., or AGDC, a state corporation. AGDC has done preliminary engineering and has secured a final environmental impact statement for its initial plan for a 24-inch pipeline, an important step.

The project has now been reconfigured to a 36-inch, lower-pressure pipeline to allow less expensive access by communities along the pipeline route.

However, the state Legislature must pass a bill in 2013 to allow the project to proceed, more important to make money set aside for the project in a special fund available to spend. About $200 million was set aside for engineering two years ago but a separate appropriation is needed to allow ADGC to actually tap the fund.

Last year the Legislature failed to approve the change, which has effectively set the project back a year.

A third important development is Shell’s continued exploration, and possible discoveries, of oil in the Chukchi and Beaufort Sea federal offshore areas where the company began exploration wells.

Those wells, one in the Chukchi Sea and one in the Beaufort Sea, were only partially-drilled. They will be completed in 2013, along with other wells Shell plans to drill.

To do the drilling Shell must again mobilize its drill fleet to the Arctic in early July, ice conditions permitting. The vessels are at least closer this year. One of Shell’s two drillships, the Noble Discoverer, is spending the winter moored in Seward. The second, the mobile, conical drill structure Kulluk, is at Dutch Harbor.

An assortment of other vessels such as anchor-handling tugs and oil spill response barges will also be on hand.

One hurdle Shell will face in 2013, as it did in 2012, is moving a specialized spill response barge and undersea containment dome to the Arctic. Federal rules require that the system be in the vicinity when exploration wells are being completed.

The containment dome is designed to capture any oil leaking from an undersea blowout with the captured fluids contained and transported to the surface. The barge at the surface has facilities that will separate oil, gas and water from the captured fluids.

Shell suffered delays in finishing work on the barge and securing final inspections in 2012, and the undersea containment dome was damaged during a test in Puget Sound.

The dome is being repaired this winter but will be tested again before the system moves to the Arctic.

Read more:

Thursday, December 27, 2012

Assembling the data; Great Bear ends drilling season, plans seismic, assessing drill results

Alan Bailey

Having drilled its first two vertical wells, the Alcor No. 1 and the Merak No. 1, as part of a pioneering shale oil program on Alaska’s North Slope, Great Bear Petroleum has called a halt to its drilling season for this year, Ed Duncan, the company’s president, told the Alaska Geological Society on Dec. 23. The company is drilling a series of test wells at six locations next to the Haul Road south of Prudhoe Bay, in hopes of proving the technical and economic feasibility of producing oil direct from the prolific oil source rocks of northern Alaska.

“The first two wells that we’ve drilled south of Prudhoe have provided us a plethora of new data,” Duncan said.

Drilling suspended

The company had originally hoped to drill a couple of horizontal sidetrack wells from the initial vertical wells by the end of this year, to test oil production from the shale oil play. But, with the drilling and subsequent rock sample analysis taking longer than anticipated, the company has settled for just drilling the two vertical wells for the time being.

“We have suspended drilling operations for the season,” Duncan said. “Certainly operations took a little bit longer than we expected, particularly on Alcor, and the lab analysis quite frankly has taken much longer than we had hoped.”

The concept behind the test wells was to drill through the three major North Slope source rock units — the Shublik, the lower Kingak and the Hue shale/HRZ — at locations where geologists have predicted that the extent of past subsurface heating, referred to as the thermal maturity, would be appropriate to the formation of oil, and hence to support the existence of oil in the rocks.

And Duncan expressed optimism about what his company has found so far.

“We have drilled through all of our targeted source rock units,” Duncan said. “We’ve proven those (to be) present at the depths predicted and in the state of thermal stress or thermal maturity, certainly within the range of expected outcomes.”

Data collection

Duncan said that Great Bear and its partner, Halliburton, had taken considerable care to obtain as much data as possible from the two test wells and that the companies had done extensive rock coring in the wells. The idea now is to plug the data into regional geology and petroleum system models, particularly targeting the geology and properties of the Shublik, the top contender for a potential shale oil play.

And, in addition to penetrating the source rock intervals, the two wells drilled through other rock sequences — Brookian turbidites, Kuparuk sands and the Ivishak — that elsewhere on the Slope form oil reservoirs in some of the producing conventional oil fields of the region.

“We’re also going to be revising regional reservoir models for all the conventional units,” Duncan said. “They’re clearly of high interest to us in addition to the unconventional resource play.”

Seismic surveys

Great Bear has already carried out a small, 57.6-square-mile 3-D seismic survey around its well locations. This winter the company plans to extend its seismic coverage west across the company’s leases and has contracted with CGGVeritas to carry out a suitable survey.

“We’ve just executed a contract to acquire another 380 square miles of 3-D,” Duncan said. “Effectively we’ll be covering the central core of the … Great Bear lease holding.”

The additional seismic data will feed into Great Bear’s geologic modeling, to provide insights into where to conduct resource play tests. And although the company continues to focus on shale oil, the seismic will probably shed new light on conventional exploration opportunities.

The larger seismic survey “is very likely to populate our prospect inventory, not just with additional locations for resource play tests … but we also expect a fair number of conventional type prospects to evolve out of that,” Duncan said. “We’ve got some good ideas, but I would really like to make our investment decisions with a large inventory of conventional things to play with as well.”

Geologic modeling

A part of the data analysis involves the updating of a North Slope petroleum system model based on computer software developed by Schlumberger. Great Bear used this model when deciding on where to acquire leases and the company now anticipates refining the model using new data.

“Now that we have additional well information from Alcor and Merak, we’ll be able to up the ante by quite a lot, in fact, on adding additional detail and fidelity to the model output,” Duncan said.

Duncan said that Great Bear had contracted with retired U.S. Geological Survey geologist Ken Bird, a recognized expert on North Slope geology, as part of the team working on Great Bear’s data analysis. A PhD student from Stanford University will also be working on the company’s seismic and well data, and the company is considering the potential involvement of other students in the analysis.

Environmental assessment

Great Bear has also carried out a more than 200-square-mile survey using Lidar, a laser-based system for measuring surface topography. This survey will provide highly detailed topographic information for Great Bear’s leased acreage, as well as bathymetry for lakes, with this information providing a platform for a regional environmental assessment, and for state and federal permitting.

“We’ll be initiating a regional environmental assessment across the tundra, particularly moving west from the highway into the core of our acreage,” Duncan said. “Those studies will be very important for the purposes of federal and state permitting as we move to the west over time.”

The company will also be participating in the “current and pending political process” in Alaska, Duncan said.

Work schedule

But Duncan did not offer any comment on how the timeline for the geologic data analysis program might impact the schedule for moving towards the development phase of Great Bear’s overall shale-oil program. The company had hoped to start some extended shale-oil testing this winter, with a view to possibly making a decision in mid-2013 on whether to proceed to a full-scale development. Presumably, with no horizontal wells drilled and no production tests started, that decision will have to be deferred.

Patrick Galvin, Great Bear’s vice president of external affairs and deputy general counsel, told Petroleum News in a Dec. 17 email that the analysis of data from the Alcor and Merak wells was taking much longer than anticipated and that the company’s drilling rig contract had expired for the season before the company had reached a position to decide on what drilling to do next.

Although Great Bear sees the possibility of conventional oil targets as an exciting addition to its North Slope program, the company continues to see its core strategy of pursuing the shale-oil resource play as its primary objective, Galvin wrote.

“When the analysis on our drilling program is completed, bolstered by the 3-D program we are acquiring, Great Bear will be in a strong position to determine its next steps in its exploration program,” he wrote.

Read more:

Friday, December 21, 2012

Monday, December 17, 2012

AIDEA funds Mustang road; With $20M loan, public corporation will help build early infrastructure

Eric Lidji
For Petroleum News

In a move described as a sign of things to come, the Alaska Industrial Development and Export Authority has agreed to loan $20 million to a small independent looking to build road and pad infrastructure to support a budding North Slope oil field development.

The $20 million purchases an 80 percent stake in Mustang Road LLC, a new company the public corporation will create with Brooks Range Petroleum Corp. The company will fund the initial infrastructure needed to bring the Mustang field into production by 2014.

The field is in the Brooks Range Petroleum-operated Southern Miluveach unit, located in the central North Slope, adjacent to the southwestern corner of the Kuparuk River unit.

By financing one small piece of a development project with the goal of improving the overall economics of the entire project, the Mustang Road deal “breaks new ground for the authority,” AIDEA board member Robert Sheldon said during a meeting Dec. 6.

Through Mustang Road, AIDEA and Brooks Range Petroleum plan to build five pieces of infrastructure in the coming year: a winter ice road, a gravel mine, a 19.3-acre gravel production pad, a 0.7-mile access road from the mine to the pad and a 4.4-mile open access road from the pad to the existing road system at the nearby Kuparuk River unit.

Under the deal, Brooks Range Petroleum is currently on the hook for the remaining $5 million needed to fund the project, expected to cost some $25 million, as well as “any additional cash calls required to complete the road and pad,” should the project exceed its budget. The Brooks Range Petroleum portion of the funding is guaranteed by its parent company Alaska Venture Capital Group and its partner Ramshorn Investments

Inc. Brooks Range Petroleum would operate and maintain the open access road.

The deal involves an 8 percent rate of return over 15 years, which would bring AIDEA around $5.44 million. AIDEA believes existing tax credits will constitute 46 percent of the total capital cost, totaling some $11.5 million and reducing AIDEA’s initial payments considerably. Mustang Road LLC will also become a 1 percent working interest owner in the Southern Miluveach unit, allowing AIDEA to collect royalties on future productions.

A mid-sized field

In addition to the potential to create jobs and increase North Slope oil production, AIDEA is interested in the Mustang project, in particular, because of its size and location.

While a Brooks Range Petroleum-commissioned study by DeGolyer & MacNaughton estimated the proved reserves of Mustang at 24.7 million barrels, an AIDEA-commissioned study by David Hite estimated 30.7 million barrels in proved reserves. (The Hite study, however, came in under the DeGolyer & MacNaughton study when it came to estimating the less likely “proved, probable and possible” reserves at Mustang.)

Additionally, the Mustang discovery wells are less than a mile from the Alpine Pipeline, making the project cheap by North Slope standards, from a transportation standpoint.

AIDEA rates ‘very competitive’

Asked by the AIDEA board why his company sought public financing, Brooks Range Petroleum Chief Operating Officer Bart Armfield said they tested the waters in the Lower 48 and found the interest rates offered by AIDEA to be “very competitive.” Additionally, Brooks Range Petroleum believes the Mustang project, if successful, could become a model, making it easier for smaller independents to get a toehold on the North Slope.

While AIDEA hopes to create a model it can replicate in the future, it also believes the Mustang road will improve the economics for other development projects in its vicinity.

In particular, AIDEA has already approached two nearby lessees, the Arctic Slope Regional Corp. subsidiary ASRC Exploration LLC and the Spanish major Repsol, about using the road as a staging area and said both companies seemed amenable to the idea.

AIDEA is also interested in financing the $178.6 million production facility Brooks Range Petroleum would eventually need to build to bring the prospect online.

In addition to the approval of its board, though, AIDEA would need authorization from the Alaska Legislature before it could participate in the larger financing project.

An emerging trend

In 2011, AIDEA took its first big leap into the oil and gas industry by helping Buccaneer Energy Ltd. purchase a jack-up drilling rig for exploring in shallow offshore regions.

Recently, Gov. Sean Parnell announced AIDEA would be the lead agency for issuing up to $275 million in loans to spur private construction of a North Slope liquefaction facility, a project designed to bring natural gas to the Interior and potential Southcentral.

Read more:

Wednesday, December 12, 2012

Crossing Cook Inlet; Anchorage-based oil producer seeks ROW for $50 million subsea pipeline

Wesley Loy
For Petroleum News

A small independent is seeking a state right of way for a new subsea oil pipeline across Alaska’s Cook Inlet.

Such a pipeline could reduce or eliminate the current risky practice of shipping crude oil by tank vessel from the west side of the turbulent, icy inlet to the Tesoro refinery at Nikiski on the Kenai Peninsula.

Cook Inlet Energy LLC on Nov. 26 applied to the Alaska Department of Natural Resources for a right-of-way lease for the proposed Trans-Foreland Pipeline.

The 29-mile line will start at Cook Inlet Energy’s Kustatan oil production facility, near West Foreland point, and cross beneath the inlet to the tank farm at the Tesoro refinery, which is near East Foreland point.

The pipeline will loop south to avoid deep trenches and strong tidal currents prevalent in the strait between the Forelands.

The $50 million pipeline is slated to commence operations in August 2014, say documents submitted to DNR.

Risky oil shipments

Anchorage-based Cook Inlet Energy is a subsidiary of Tennessee-based, publicly traded Miller Energy Resources Inc.

Cook Inlet Energy has an assortment of oil and gas assets on the west side of the inlet, including the West McArthur River oil field and the offshore Redoubt unit and Osprey platform. Oil from Osprey is piped ashore to the Kustatan production facility.

Cook Inlet Energy is aiming to rapidly increase its production, and a number of other companies also are producing or exploring on the west side, including Hilcorp and Apache.

Presently, west side crude flows via pipelines to the Hilcorp-operated Drift River terminal, where tankers or barges pick up the oil for delivery across the inlet to the Tesoro refinery.

Water transport of crude oil is inherently hazardous, and the inlet’s big tides and dangerous winter ice floes add an extra measure of risk.

Cook Inlet Energy says the subsea pipeline could eliminate the need to move oil by tanker or barge, and could reduce oil transportation costs.

The company also notes the close proximity of Redoubt volcano to the Drift River terminal. Eruptions in 2009 closed the terminal and idled west inlet oil production for months.

The company further says the Trans-Foreland Pipeline is needed to “bypass the aging infrastructure on the west side of Cook Inlet.”

Large-capacity line

The new pipeline, 8 inches in diameter, will have a capacity to move 90,000 barrels per day of sales-grade crude, Cook Inlet Energy’s right-of-way application says. That’s a very large number relative to current oil production from the west side.

Cook Inlet Energy says it believes it will need to attract shipping commitments of about 4,000 barrels per day to make the tariff competitive with the Cook Inlet Pipe Line system. CIPL is the Hilcorp subsidiary that operates the Drift River terminal.

“However, given the increased operational reliability and environmental benefits offered by this (Trans-Foreland) line, the project may be viable at lower throughput levels,” the right-of-way application says.

A project description offers considerable detail on the pipeline route. The pipeline will start at the Kustatan facility and run 2.2 miles, buried in uplands, to the bluff on the west side of the inlet.

At the top of the bluff, the pipe will be installed using horizontal directional drilling for 2,640 feet into Cook Inlet, where it will exit onto the seafloor.

The line then will run about 26 miles across the bottom.

“The pipeline is laid in a horseshoe shape to facilitate construction in the high tidal currents occurring between the East and West Forelands,” a project description says. “The forelands represent the narrowest part of Cook Inlet and have the highest currents and deepest trenches. The route was also selected to minimize tidal stresses and avoid water depths greater than 200 feet, the maximum depth for safe operation by marine divers.”

On the east side, the buried pipeline will run 1.6 miles along Hedberg Drive and the Kenai Spur Highway to its terminus at the Kenai Pipe Line Co. tank farm near the Tesoro refinery. KPL is a subsidiary of San Antonio, Texas-based Tesoro.

Construction schedule

The pipeline will be equipped with a leak detection system and a cathodic protection system to prevent corrosion. And the design will accommodate internal inspection devices known as pigs, the application says.

A lay barge, tugs and other support vessels will be used to install the pipeline on the Cook Inlet seafloor.

Cook Inlet Energy says 130 construction jobs will be filled for the project. About eight field workers and four office workers will be needed to operate and maintain the pipeline.

Construction is scheduled for April through August 2014. The work schedule will be designed to avoid conflicts with commercial salmon fishing.

Cook Inlet Energy says two contractors are under consideration for the pipeline installation: Price Gregory and CONAM Construction, and NANA Construction.

Most of the pipeline route, including the long stretch under Cook Inlet, is on state land. Thus, Cook Inlet Energy is seeking a DNR lease for the right of way.

The application materials are posted online at

Tuesday, December 4, 2012

Back to Basics

By Ann L. Lovejoy
Creative Intermedia LLC

Every decade or so, some group brings up how the schools need to get “back to basics – you know – reading, writing, and arithmetic.” Apparently, spelling is not one of these “three R’s.”

This post is about the nuts and bolts of figuring out what projects to invest in. There are some real R activities that happen before big projects kick off: these are Results, Resources, Requirements, and Risk.

Results: We get actual results at the end of a project. But we need to understand our expected results first. Thinking about goals must come first because if you don’t know where you are going – there is no way to know when you’ve arrived. Goals are tangible. They can be measured. Examples include profit, quicker time to deliver, lower inventory expense, better cash flow, lower error rates. Goals are specific, measureable, actionable, and time-bounded. Measurements include such categories as quantity, quality, time, cost, and trend or velocity.

At the end of the project, if the actual results meet the goals, then the project was successful. These results are facts because they can be checked – you’ve set up measurements before you start. If your project’s results do not meet the goals; then the project wasn’t successful. We invest money to do a project. That money is wasted if the investment didn’t give us good results.

Requirements: Requirements describe what needs to happen to meet a goal. We define requirements to make sure we know how big the project or investment will be. A requirement is specific, and lists one concrete thing that must be done. A typical large project has thousands of requirements, each stands alone. When a high-priority requirement conflicts with another, then we have to decide which one to do. Typically there is a hierarchy and business rules for which ones are more important.

Resources: People, equipment, and money are resources. We also have to describe what kind of people – usually we want people who are experienced, educated, an expert. The resource is their knowledge. The project can only meet requirements if we have resources to do the work.

Risk: We think about what can go wrong, that’s a risk. We also think about how likely that risk will happen. This is the frequency of the risk.

Most of the time we know pretty well how frequently a bad thing might happen, and we write down assumptions that must be met for success. For example: “We assume experienced people are available and can be hired since 8% of the population has these skills, and 5% are currently unemployed in this market.”

A risk, on the other hand, may or may not happen: “Turnover of key personnel is a risk; the typical turnover in these roles is 10%. If we backfill staff to build back-up knowledge, we reduce the risk.”

Risks can be a catastrophe: Fires are fairly frequent. “A plane will hit the building.” The frequency is low. So in that case, we document it, and we take actions to store information somewhere else. I once worked in a place where war zone military supply planes came in low over our building every day. That plane crash risk was more likely than flood damage from a river 1000 feet below us.

So, how do these R’s help us decide on what projects to invest in?

We use another R – we rank the possibilities based on the results expected, resources, requirements, and risks. We may look at net present value (NPV) at the end of the project. This is cash flows and discounted interest rates from the project. We want the results to be more valuable than what we paid to do the project. Suppose one project returns twice as much as it cost – this is better than a project that gave us just a few dollars more than it cost.

We look at resources and risks. If one project is harder to do – it needs more resources. If the risks are higher, then we want a higher return to make the risk worthwhile. Often, a lower-risk project is better. A low-risk project is much more likely to be successful. Cash flow matters. A failed, high risk project means no results, no cash, lost investment, wasted resources. If this happens a lot – the whole company fails.

Decision-making is a kind of balancing act. We weight the rules to help decide. A bunch of project proposals together is called a portfolio. We may say something like, “Only a small percentage of our portfolio can have a high risk factor. Most of our projects must have a lower risk score with guaranteed cash flow.”

When projects are ranked, the next step is to set the priorities for 1, 3, 5 or more years. Any organization cannot do every single proposed project – there’s not enough time, money, or people to manage them. The rejected projects may be reconsidered when the top priority projects are finished and generating results.

So, what’s the bottom line for Alaskans thinking about oil and gas project investments? Knowing how project investments are made helps us to ask better questions. And we will have a better expectation of what results are possible and probable.

Ann L. Lovejoy is a consultant who helps organizations be better to do better.

Monday, December 3, 2012

Forecast of U.S. oil supremacy draws wide notice, and doubts

—Wesley Loy

The Paris-based International Energy Agency created quite a stir Nov. 12 with the launch of its 2012 World Energy Outlook.

The report made global headlines with some startling predictions about U.S. oil and gas production.

The recent rebound in U.S. production is driven by upstream technologies that are unlocking light tight oil and shale gas resources, the IEA report said.

By around 2020, the United States is projected to become the largest global oil producer, overtaking Saudi Arabia until the mid-2020s, the report said.

Concurrently, the country will start to see the impact of new fuel efficiency measures in the transportation sector.

“The result is a continued fall in U.S. oil imports, to the extent that North America becomes a net oil exporter around 2030,” the IEA report said.

Further, under what the IEA calls its central scenario, the United States becomes a net exporter of natural gas by 2020, and is “almost self-sufficient in energy, in net terms, by 2035,” an IEA press release said.

The IEA describes itself as an autonomous organization working to ensure reliable, affordable and clean energy. It has 28 member countries, including the United States and Canada. The prediction that the United States will become the world’s top oil producer by 2020 surprised many, and brought out a few skeptics.

Analysts with Deutsche Bank were reported to have produced an investor note arguing the United States won’t surpass Saudi Arabia as the No. 1 oil producer. They said U.S. policy restricting exports, coupled with sagging domestic demand for oil, could soften prices and discourage project development.

“The idea that the U.S. could overtake Saudi Arabia, even temporarily, is a stunning development after years of seemingly inexorable declines in domestic oil production,” wrote Kevin Bullis, senior editor for the MIT Technology Review.

As for the IEA’s conclusion that the United States could be nearly energy self-sufficient by 2035, that’s only after offsetting oil imports with exports of coal and natural gas, Bullis noted.

“To be truly energy independent,” he wrote, “the United States would have to invest in technology for converting natural gas and coal into the liquid fuels needed for transportation, or have other technical breakthroughs, such as improved batteries or biofuels, that would quickly reduce the demand for oil.”

Read more:

Friday, November 30, 2012

Oil tax reform requires all stakeholder support

Deborah Brollini
Alaska Energy Dudes and Divas

The Anchorage Press recently referred to my energy blog Alaska Energy Dudes and Divas and I as the “face of big oil.” I know some share that sentiment. Would it surprise you that for a decade that I’ve collected a paycheck from the healthcare industry? For eight years I managed the finances for the Alaska Native Tribal Health Consortium’s research and HIV/STD prevention programs, and for the past 15 months have been managing the traveling nurses for Providence Hospital statewide. I report to a board of two whom are my children, and their futures are on the line, and that is why I am in the trenches for oil tax reform. Thus, my educational outreach efforts to engage all Alaskans.

I was excited to be invited to present to the Alaska Native Tribal Health Consortium (ANTHC) board by ANTHC board President Andy Teuber at the Alaska Federation of Natives (AFN) convention in October. The presentation was to discuss energy issues, and my outreach efforts. I invited Senator Lesil McGuire to attend and present to the ANTHC board because she could speak to legislation passed to deal with the energy issues impacting rural Alaska. However, since the election the concern became about the organization of the Senate. Therefore, the conversation needed to address the boards' concerns, and Senator McGuire spoke to the ANTHC board on November 28, 2012.

I learned on November 28th that it was the first time a sitting state legislator presented to the ANTHC board. Senator McGuire set worries to rest about Senate organization, and looked these Alaskans in the eye and committed as Senate Rules Chair that nothing will get on the Senate floor that will harm Alaska Native people or rural Alaska. Ultimately, taking responsibility for the next four legislative sessions concerning issues impacting my people.

The majority of the exchange with the ANTHC board was about oil tax reform, energy, and the state budget. I was personally surprised at how informed this board was about oil tax reform, and the state budget. One board member went so far as to ask why does it take eight to 10 years to get a project permitted on the North Slope? I found that an interesting question coming from a board member whom I thought was an oil novice. I later learned that this board member's region is impacted by North Slope oil production, and she has a full grasp of the rub between industry and communities.

Alaska’s first people need to be at the oil tax solution table, and I would argue have never been invited. Senator McGuire pulled out the chair and offered everyone in the room a seat at the policy table. For those who do not know the ANTHC board is a powerful bunch. The members of the ANTHC board sit on multiple boards around the state and collectively with their tribal powers can help move Alaska forward. What most people do not know is that Alaska Native leaders advocate for all Alaskans, because when Alaska Native people win... all Alaskans benefit.

For the record, I am not the face of “big oil.” I am advocating for the future of my children, your children, your grandchildren, and your businesses. I’m advocating for all Alaskans and always have.

Thursday, November 29, 2012

Utilities make first draw from gas storage

Tim Bradner
Alaska Journal of Commerce

Just in time for recent cold weather, Southcentral Alaska utilities are now making their first withdrawals from a new natural gas storage facility near Kenai.

“We’ll be depending on gas storage for 20 percent of our estimated peak needs this winter,” Chugach Electric Association spokesman Phil Steyer told the Anchorage Chamber of Commerce Nov. 26.

The storage project, completed this year, “is just in time” for the winter, Steyer said. Other utilities are withdrawing gas from storage also. Enstar Natural Gas Co. said colder weather has resulted in more gas demand from its customers.

The new Cook Inlet Natural Gas Storage Alaska, or CINGSA, facility is critically important this winter because the ConocoPhillips natural gas liquefaction plant near Kenai is no longer able to divert gas to the utilities as it has been in past winters.

“We are now selling all the gas we produce to the utilities. We are not making LNG at the plant, which is in a “warm shutdown,” ConocoPhillips spokeswoman Amy Burnett said.

Chugach Electric, Anchorage’s city-owned Municipal Light and Power and Matanuska Electric Association made presentations to the chamber on new electrical generation and power distribution projects they have under way, but uppermost of the minds of utility managers are looming long-term shortages of gas, the need to meet peak-demand periods this winter, and rate increases needed to pay for new projects and for rising prices of gas.

Steyer recommended to chamber members that they plan for electric rate increases of 5 percent to 10 percent in 2013, although final numbers won’t be known for some time.

Enstar Natural Gas Co. rates will rise, too. Although Enstar was not at the chamber Nov. 26, its spokesman John Sims said the utility has advised the Regulatory Commission of Alaska that its cost for natural gas will increase by 14 percent in the first quarter of 2013, an amount that will have to be passed on to consumers.

Enstar’s gas costs are expected to average $7.24 per thousand cubic feet, or mcf, in the first quarter of the year, up from $6.16 per mcf in the last quarter of 2012 and $6.71 per mcf in the first quarter of 2012. The major challenge for Enstar is simply getting enough gas for its needs in 2013, however. Sims said the utility still faces a gap of about 4.2 billion cubic feet of its expected 2013 requirement of about 33 billion cubic feet, although negotiations are continuing with producers in the region.

“The fact that we are going into the new year with a gap this large puts us into an uncomfortable position,” Sims said.

If Enstar is unable to secure its supplies the utility will have to ask the electric utilities to share gas they have under an agreement between the Southcentral utilities. This would be expensive, but the electric utilities have capabilities to shift to alternatives for some of their needs, such as using diesel to some extent, halting sales of power outside the region or even importing power from Golden Valley Electric Assoc. in Fairbanks.

“The electric utilities will bear the brunt of any fuel shortage because you can shut us off,” from gas, Joe Griffith, Matanuska Electric Association’s general manager, told the Anchorage chamber. Enstar has no alternatives, however, and its system must be protected, he said.

Steyer reviewed the gas supply situation for chamber members. Although Enstar’s gap is immediate, Chugach faces its own gas supply gap in 2014 and 2015, and ML&P faces future gaps as well.

Steyer cited findings from a consulting firm hired by the utilities that has forecast an annual supply gap, between total gas demand and estimated total supply, of 6.2 billion cubic feet in 2015, 11.4 billion cubic feet in 2016 and 16.6 billion cubic feet in 2017.

The utilities are working together now to meet those gaps with either imported liquefied natural gas or compressed gas. Suppliers of LNG and compressed gas have now responded to Requests for Proposals from the utilities, and an economic consulting firm will be hired soon to compare the proposals and make recommendations.

“Some are saying ‘no, no’ to gas imports, but we will have to have some kind of new gas in the pipeline by the winter of 2014 and 2015,” ML&P’s general manager Jim Posey said.

It’s too early to know the additional cost of importing gas but at the chamber meeting Posey said it might cost 30 percent to 40 percent more than what is now being paid to gas producers in the region.

LNG prices in Pacific markets are now trending downward.

“There’s a lot of gas on the water,” he said.

ML&P improvements ongoing

Posey reviewed ML&P’s plans with chamber members. The city utility, which is celebrating its 80th anniversary this year, serves a 20-square-mile core area of Anchorage’s downtown and midtown, including the bulk of the city’s large commercial and institutional including the midtown office, university and health care buildings.

To modernize and keep up with growth, ML&P has a $459 million five-year capital improvements program under way, Posey said. The bulk of this, $274 million, is for new power generation facilities including ML&P’s 30 percent share of the new Southcentral Power Project now being built in south Anchorage.

The new generation plants are more efficient than what they are replacing, and are expected to use 28 percent to 34 percent less natural gas to generate the same amount of power.

“This is the busiest construction year we’ve seen in the last 40 to 50 years. The work is being driven by improvements we’re making at our power plants but also to repair damage from the wind storm that hit us this fall,” Posey said.

One large project underway is construction of expanded generation facilities at ML&P’s power plant near Muldoon on the Glenn Highway. About 200,000 cubic yards of dirt were excavated this year at a site for a new power plant building adjacent to the existing plant. Three new gas turbines are on order, which will arrive in 2014 and be installed in 2015, Posey said.

ML&P is also continuing work to replace above-ground power lines with underground lines. About $2.5 million is budgeted this year for this work, Posey said.

A new, $22 million substation is also being installed so ML&P’s share of power from the new South Anchorage power plant can be moved efficiently to midtown Anchorage, the largest growth area for the utility.

“The construction of new office towers has shifting our whole load to midtown,” Posey said, and the power transmission infrastructure must meet this demand. Another major customer will be Verizon Wireless, he said.

ML&P gets most of its natural gas from the Beluga gas field, where it is the one-third owner. The field is declining at rates of about 17 percent per year but continued investments in compressors and new producing wells have offset some of that.

In 2011, the owners of the field, which include ConocoPhillips, which operates the field, Chevron (now Hilcorp Energy) and ML&P, invested $60 million and achieved an 18 percent to 20 percent production increase, Posey said, but the long-term underlying decline has continued.

New production wells drilled in the Beluga field don’t produce as much as gas, either. In the field’s early years there were wells that produced as much as 40 million cubic feet of gas per day, Posey said. Now the average daily rate per well is 15 million cubic feet, he said.

New Chugach plant to fire up in 2013

Chugach Electric Association’s largest construction project is the new $369 million, 183-megawatt Southcentral Power Project, of which it is 70 percent owner with ML&P owning the remainder. The plant is nearing completion and will be generating electricity to grid in the first quarter of 2013, Chugach’s Steyer said.

Chugach has a number of other projects also under way including replacements of transmission lines along the Seward Highway that serve Hope and Seward, and development of a stream diversion at Chugach’s Cooper Lake hydro facility, at Stetson Creek. Stream diversions have the effect of putting more water through a hydro plant, increasing the amount of power produced, Steyer said.

Things are busy in the Matanuska Electric Association service area which includes the Matanuska-Susitna Borough along with parts of north Anchorage. MEA’s biggest project is construction of its new Eklutna Generating Station at Ekutna, its manager, Joe Griffith, said. Design work is essentially done on the plant as well as site preparations and a connection to a natural gas pipeline.

Ten large engines that will produce the power are on order. They are large machines, 19 feet tall and 60 feet long, each weighing 300 tons.

The engines use natural gas as fuel but Griffith is investigating where a propane-air mixture can also be used. They can also be switched to diesel quickly, but if that were to happen the fuel cost to MEA would triple.

MEA has other projects underway also including planning for a 37-mile new distribution line to move power more efficiently from the new generation plant at Eklutna to MEA’s main center of demand in the Wasilla area.

Read more:

Tuesday, November 27, 2012

LNG project is linked to oil tax change, producers say

Tim Bradner Alaska Journal of Commerce

All three major North Slope producing companies say progress on a large natural gas pipeline and liquefied natural gas project is linked to reform of the state’s oil production tax, an issue that will be before the state Legislature again in its 2013 session.

The three companies made presentations at the Resource Development Council’s annual Alaska resources conference Nov. 14, and all three voiced the same message:

“It is essential to build a competitive fiscal regime for both oil and gas. Stability is essential,” said Randy Broiles, ExxonMobil Production Co.’s vice president/Americas.

John Minge, president of BP’s Alaska production company, said gas and oil production tax issues are linked because the two are produced out of the same wells and supported by the same infrastructure.

Gas production won’t work economically unless there also oil production that supports the oil field infrastructure, but the present state tax, known as ACES, does not encourage long-term development of known oil resources in the existing fields that are needed to sustain the field infrastructure.

“We are serious about gas to LNG, but fiscal reform for oil and gas is essential to enable this massive investment to happen,” Minge said. “If the state has a short-term 10- to 15-year future mindset, ACES is the right approach. But if you want to take a long-term view and have a sustainable oil business and have a real shot at gas, change is needed. Within that view the legacy (producing) fields are essential.”

Nick Olds, ConocoPhillips’ vice president for North Slope operations and development, agreed: “North Slope gas production will depend on a healthy oil business,” to preserve the producing infrastructure for the big legacy field of the North Slope.

“Over the next four decades we see the potential for developing 4 billion barrels, but to produce those barrels we will need to invest substantially in renewal of the infrastructure, and to maintain it so we will have a platform for gas,” Olds told the RDC.

Gov. Sean Parnell had earlier planned to introduce a bill revamping the state gas production tax but subsequently decided to hold off to give the Legislature time to consider anew the oil production tax adjustment next spring.

A change in the gas tax, mainly establishing a mechanism for tax stability, is essentially unworkable unless the oil tax issue is addressed first, the North Slope companies have said previously.

Under Alaska’s net profits-type production tax, oil and gas production are taxed together because they are produced from the same wells.

In his presentation to the RDC BP’s Minge criticized the ACES tax as short-sighted policy.

“ACES is clearly a short-term going out-of-business policy and it will deliver very predictable results. It is delivering very predictable short-term results and we have a 5-year track record to prove it,” Minge said. “The State of Alaska is doing very well taking mass amounts of the upside (of revenues) at today’s oil price. The long-term (industry) investment is down, especially capital going into production enhancement activities.”

Olds, of ConocoPhillips, said his company has increased its capital investment in Lower 48 producing properties from $1.6 billion in 2009 to $4.8 billion in 2012, mainly because of stronger oil prices.

In Alaska, however, ConocoPhillips’ annual investment remained essentially flat, at about $900 million per year, over the same period. That is mainly because the state tax captured most of the gain of higher prices, leaving the company with little incentive to increase investments.

To illustrate this, Olds said that in 2007 oil prices were at about $70 per barrel, the state earned about $27 in net revenues per barrel and ConocoPhillips earned about $22 per barrel.

In 2011, oil prices had increased to $106 per barrel and the state’s earnings per barrel increased to $51 per barrel, a gain of $23 per barrel. However, ConocoPhillips’ earnings per barrel increased only to $25 per barrel in 2011, a gain of only $3, he said.

Minge, at BP, painted a bleak picture unless something is done: “Decline continues at 6 to 8 percent per year and we can reasonably forecast that in 10 years the production in TAPS will be somewhere around 300,000 barrels per day.”

That is now considered the lowest economic operating limit for TAPS.

For critics of tax reform who question what Alaska “gets” for the tax adjustment, Minge said, “you get a future,” with an industry that could extend for decades.

There are also complaints that the proposals so far have contained no guarantee that the companies will actually invest and produce new oil, but Minge said there are many examples around the world where governments have reduced taxes to encourage new production, and the initiative has worked.

“I’m aware of no other place where people demand guarantees,” he told the RDC.

Alaska should step forward and make the change now, he said.

“You hold the keys, and you also hold the hammer,” Minge said, meaning the state can take the action to enable new investment but also holds the “hammer” to re-impose taxes if the industry does not perform.

Minge said BP is having to take steps now to adjust the company’s plans and strategy to fit within the ACES policy.

“We probably should have done that two or three years ago, but we can no longer wait,” he said. “Today our plans have really been mismatched against the state’s policy. It was built on the hope that a change (to ACES) will come. We’ve been focused on the more challenged resources and we need to take steps to invest in light (conventional) oil. We’re going to stop our heavy oil investment into the heavy pilot project within a few months,” Minge said.

Minge encouraged Alaskans to work together to break the divide:

“Alaskans are very aligned about what they want: a sustainable oil business, a major gas project to go forward, and everyone wants affordable energy for in-state needs and everyone wants jobs,” Minge said. “However, the current policy does not deliver that outcome. Policy decisions are essential to the future. We need to find a way to come together.”

Broiles, of ExxonMobil, said there has been real progress on developing a large natural gas project and also in developing the Point Thomson gas and condensate field, which will involve the first commercial gas production on the Slope.

Broiles praised the state for stepping forward last March to settle long-standing litigation over Point Thomson, and said the settlement was essential to a large gas project going forward.

“The state was not quick or easy in their decision to settle this, but if we can build on this, to keep the momentum, the prize is huge,” he said.

The U.S. Army Corps of Engineers issued its final Record of Decision on the Point Thomson environmental impact statement in October and the company is now working to secure other needed permits, an ExxonMobil spokeswoman said.

Construction on the multi-billion-dollar project is expected to begin this winter. The project will produce gas, strip off liquid condensates, and inject the gas back underground. The liquid condensates will then be shipped to Prudhoe Bay by pipeline and mixed with crude oil in the Trans-Alaska Pipeline System.

Read more:

Friday, November 23, 2012

XTO runs short of fuel gas; utilities plan for tight gas supplies

—Alan Bailey

In a situation that presumably reflects the ever tightening gas supply situation in Alaska’s Cook Inlet basin, ExxonMobil subsidiary XTO Energy had to suspend oil production at its two Middle Ground Shoal platforms in the inlet because of a shortage of natural gas, an XTO spokesman told Petroleum News in a Nov. 15 email.

“The suspension is due to a temporary supply shortage of natural gas needed to power the platforms,” he said. “XTO should shortly have both platforms fully operational.”

At the time of going to press XTO had not provided an update on the situation.

Tightening supplies

As production declines from the aging gas fields of the Cook Inlet basin, gas and power utilities in Southcentral Alaska have been alerting people to the tightening gas supply situation and warning of a pending utility gas shortage in a couple of years’ time.

In September Jim Posey, general manager of Municipal Light & Power, told the Anchorage Mayor’s Energy Task Force that earlier in the year his utility had needed to withdraw some gas from Cook Inlet Natural Gas Storage Alaska’s new Kenai Peninsula gas storage facility following a compressor failure at the Beluga gas field.

“That’s how close we are,” Posey said.

There is new oil and gas exploration and development taking place in the basin, primarily by independent companies attracted to the basin by, among other factors, state tax credits for Cook Inlet exploration. But research commissioned by the utilities has found that no new gas discoveries of sufficient size are likely to come on line quickly enough to fill the initial supply gap; development drilling in existing fields is unlikely to happen fast enough to sufficiently stem the production decline; and there is no practical possibility of constructing a gas pipeline from the North Slope into Southcentral before gas supplies from the Cook Inlet are likely to fall short of local gas demand.

Imports planned

The utilities are planning to import either liquefied natural gas or compressed natural gas to cover the gas supply shortfall, at least until sufficient in-state gas supplies can be brought on line.

On Nov. 19 Colleen Starring, president of Enstar Natural Gas Co., told the Anchorage Chamber of Commerce that Enstar, the main Southcentral gas utility, is already facing a shortfall in firm gas supplies committed under contract, with that shortfall set to grow continuously over the coming years.

“What we’re short right now, going into this winter, is about 4 billion or 4.5 billion cubic feet of (guaranteed) gas,” Starring said.

Enstar does anticipate sufficient gas being available, although not under firm contract, through the coming winter — the utility expects to fill the gap in guaranteed supplies using a daily bidding system, a kind of spot market that it started operating in early 2011.

Starring emphasized the importance of the Cook Inlet Natural Gas Storage Alaska facility in enabling the adequate delivery of gas during high utility gas demand in the winter. The facility, known as CINGSA, made its first winter gas withdrawals on Nov. 9, having been warehousing gas over the summer for winter use, Starring said.

But based on current supply and demand forecasts the utilities foresee having to import at least some gas in the winter of 2014 to 2015, she said.

Assessing options

The utilities have seen presentations from five entities about possible gas import arrangements and have commissioned consultancy firm Northern Economics to assess the relative merits of liquefied natural gas and compressed natural gas for the imports, with the utilities wanting to make a decision in early 2013 on an import option.

The utilities have considered the possibility of trucking liquefied natural gas from the North Slope but have viewed this option as impractical for Southcentral Alaska, Starring said.

“The engineering, the infrastructure and the permitting challenges, and just the scalability of it to meet the demands that we see occurring in Southcentral, are not going to synch up,” Starring said.

Read more:

Wednesday, November 21, 2012

Gas line projected to generate thousands of in-state jobs

Elwood Brehmer
Alaska Journal of Commerce

Alaska Gasline Development Corp. CEO Dan Fauske provided figures estimating a major impact to Alaska if the proposed in-state gas pipeline is built.

“It will be the largest project in North America. It will supply 8,000 direct and 15,000 indirect jobs,” Fauske said Nov. 9 in a presentation to the Associated General Contractors of Alaska annual conference.

The numbers expand on those in the final environmental impact statement released Oct. 26. The estimated $7.52 billion construction cost will involve moving 10 million cubic yards of soil, assembling 335,000 tons of pipe and 4 million miles of truck travel to transport equipment and supplies, according to ADGC statistics.

As previously reported, the 24-inch diameter pipeline will stretch 737 miles from Prudhoe Bay to an extraction plant on the northern edge of Cook Inlet.

In his presentation, Fauske added that state regulation requires an additional facility to be built at mile 458 of the pipeline. That’s where a 12-inch lateral line is planned to supply Fairbanks.

“We must build what’s called a straddle plant to pull impurities, or those rich natural gas liquids out and you must ship utility grade gas down the line.” Fauske said.

A straddle plant will cost $250 million and be paid in a tariff charged to gas customers in Fairbanks. While some in the city aren’t happy with the expenditure, Fauske said the status quo will not hold.

“Fairbanks is in an absolutely chaotic economic situation in terms of energy cost,” he said. “You have people paying more for their monthly heating bill in the dead of winter than for their mortgage payment.”

AGDC projects the Fairbanks tariff to be $10.45 per million Btu worth of gas. Current tariffs for gas trucked to Fairbanks are in the $23 range, Fauske noted. An Anchorage tariff is expected to be slightly lower simply because of dispersal over a larger population.

“You’re going to pay $9.63 (in Anchorage) after you built a $7.5 billion pipeline, put thousands of people to work, and secured energy for the next hundred years and your energy prices are going up less than a buck. That’s pretty impressive,” Fauske said.

The tariff for gas from Cook Inlet, he said, is in the $8 range right now.

A project timeline provided by ADGC forecasts engineering, financing and permitting to continue for several years. Construction is expected to begin in early 2016, with the first gas reaching Fairbanks in late 2018 and a full flow of 500 million cubic feet of gas per day to Cook Inlet beginning in 2019.

The state of Alaska will be expected to cover the first $400 million in design and permitting costs. Fauske said the costs up front will be recovered through gas taxes and royalty fees.

With gas supplies from Cook Inlet dwindling and shortages expected as soon as 2014, Fauske made his feelings about the importance of the gas line clear.

“I joke in speeches we’re going to be in our basements burning our Permanent Fund checks to stay warm,” he said. “I don’t care what project we do, I just want a project.”

He added that the in-state line is not meant to compete against the idea of a much larger commercial export pipeline. It is meant to supply Alaska with its gas needs. If a second gas pipeline is built in the future, Fauske said, it will be done by large oil and gas companies, not by the state. Costs for a 48-inch export line are estimated to be $45 billion to $60 billion.

“If in their work they determine that someday, tomorrow or maybe 50 years from now, it makes sense for them to spend that kind of money to ship gas to either the west coast of the United States or the Far East, they’ll do it,” he said.

Elwood Brehmer can be reached at

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Tuesday, November 20, 2012

Investment: Keep your friends close …

Ann Lovejoy
Creative Intermedia LLC

My Dad was a geologist and mining engineer. He used to say, “Keep your friends close and your enemies closer.” I’ll explain that in a minute.

This post is about the deal. What is a deal? How do you structure one? What is important to remember in a deal? How do you deliver to expectations? How do you make sure you are successful?

The first thing you need for a deal is to be prepared: A good business person invests time and money in equipment and tools. All the branding and promises don’t matter if she can’t deliver on her promises. A good business person thinks about: Who will do the work? Who can be a partner? What expertise can she tap short-term? A good business person has done her research – she knows the data cold. She knows the markets. She knows historical pricing. She’s totally current on trends so she can jump ahead to where the customer will be – not where everyone else is now.

The second thing you need for a deal is a potential customer: Does the customer WANT what she is selling? This is a different question from: Does the customer NEED what she is selling? The customer often wants what’s in front of them and not what they need – what would really help them. This savvy business person is ahead of others – so she educates the customer about the future. The understanding of trends and data comes in handy.

The third thing you need for the negotiation is a really clear idea of the whole deal. She can’t be swept up like a romantic interest in a two star movie. She has got to remember that human beings fall into the trap of WIFOYIATI – What’s in Front of You is All There Is. A deal must be structured so goals are clear for the business person and the customer. This means the goals include now-and-future expected results. The way to evaluate the deal at the end is decided in the beginning.

So, what did Dad mean when he said, “Keep your friends close and your enemies closer?” That’s the WIFOYIATI. When we are socializing with our customers, our competitors, our lobbyists -- they become familiar to us. The human tendency is to think they are friends because they are familiar. Dad’s reminder was that we should never forget that true friends are different from business contacts.

A deal has to be evaluated. Were the goals met? Did the results happen? Was the customer happy? A YES to these questions means future business. If that deal didn’t work out, she figures out what didn’t work and stops doing that. If a deal was so-so, she may continue what worked. If a deal had excellent results – she’ll keep doing that kind of deal.

The fourth thing you need to remember is that ONE deal is not enough. Researchers and consultants say the single reason most small businesses fail is because they don’t send out invoices.

She had a success today – but she has to keep having successes, over and over. She has to keep doing deals from beginning to end. She has to do the deal; do the work; do what it takes to finish the work for results.

The lesson is that long-term-success is based on consistent hard work. She has to approach her life and her business with a bent toward excellence. The next deal bid has to be excellent. The way she treats her workers and partners has to be excellent. The way she eats, rests, exercises her body, and her spiritual life have to be excellent. Because all these factors let her see now-and-future; let her create deals that are good for everyone.

For Alaska – oil and gas tax rebates are a deal – they have to be excellent. Investment has to be in place. Market and cost data must be known. Goals have to be clear for now and the future. Everyone in the deal should expect results they can check out later:

  • Citizens leasing the resource
  • Deal makers who are extracting and selling the oil and gas
  • End-customers who expect a good deal themselves.

And that’s how to do a deal.

Ann L. Lovejoy is a consultant who helps organizations be better to do better.

Linc building snow road to Umiat, prepping for January drilling

—Eric Lidji

Work is under way at Umiat.

In preparation for a drilling campaign scheduled for January, Linc Energy Inc. recently began building a snow road to the North Slope oil field, the company said Nov. 12.

The 100-mile snow road will begin at the Dalton Highway, near Pump Station 2, and continue to Umiat, located on the boundary of the National Petroleum Reserve-Alaska.

Linc is currently pre-packing the road and expects the development to take 30 days.

With the road complete, Linc expects to begin mobilization in mid-December. The mobilization effort involves moving a camp, drilling rig and equipment to the field.

During the mobilization, Linc plans to build in-field ice roads and ice pads.

Between January and April, Linc plans to drill at least four wells at Umiat, starting with Umiat DS No. 1, a Class II disposal well the company plans to spud around Jan. 18.

Four-well program

Using the Kuukpik No. 5 rig, Linc would move uphill, to the northwest, to drill Umiat No. 16, a vertical well into the Lower Grandstand. The program calls for collecting four 60-foot core samples from the formation and flow testing the well after completion.

From there, Linc plans to skid the rig approximately 10 feet to drill Umiat No. 16H, a horizontal well into the same interval. The side-by-side test is “important for assessing the performance of the horizontal production well in contrast to the vertical producer.”

While government expeditions drilled 12 wells at Umiat between 1946 and 1979, the current program would be the first to test horizontal drilling techniques at the field.

After drilling the side-by-side wells, Linc plans to move the rig to the east to drill Umiat No. 23, targeting natural gas in the deeper horizons below the Lower Grandstand.

The natural gas would be used for reservoir maintenance, according to Linc. Specifically, the company plans to inject cold gas into the Upper and Lower Grandstand to maintain reservoir pressure for production, a solution also proposed by previous lessees at Umiat.

Because at least part of its oil horizons are embedded in shallow permafrost, the Umiat field creates challenges for secondary recovery and pressure maintenance operations, Renaissance Umiat LLC explained in a January 2010 article in Oil & Gas Journal.

Aiming to figure out why early Umiat wells failed to produce as expected, a 1960 U.S. Bureau of Mines study found that warm drilling mud might have thawed the permafrost, allowing water into the reservoir sands. When this water inevitably froze, it plugged the formation. To combat this problem, Renaissance and others had proposed cold gas injections as a way to maintain reservoir temperature and therefore improve permeability.

After targeting and potentially producing natural gas from the well Linc plans to plug Umiat No. 23 back to the oil sands in the Lower Grandstand for an additional flow test.

In addition to those four wells, Linc is permitting two alternate locations — Umiat No. 18 and Umiat No. 19 — and said “one or both” could be drilled this winter, “if time allows.”

Previously, Linc outlined a five-well program for Umiat this winter, including a disposal well, two shallow vertical wells, one deep vertical well and one deep horizontal well.

Earlier this fall, Linc staked seven potential well locations with the U.S. Bureau of Land Management, the six previously mentioned wells and an Umiat No. 23H horizontal well.

This summer, Linc outlined an “aggressive timeline” to bring Umiat online within five to seven years. The company estimates peak production could be 50,000 barrels per day.

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1 step forward, 2 back; Conoco goes ahead with CD-5; BP halts heavy oil trials, won’t increase viscous

Kristen Nelson
Petroleum News

BP Exploration (Alaska) and ConocoPhillips Alaska, the North Slope’s major operators, delivered similar messages to the Resource Development Council’s annual conference Nov. 14 in Anchorage: The state’s oil and gas tax system needs to be changed.

It’s not a new message, but Nick Olds, ConocoPhillips Alaska’s new vice president, North Slope operations and development, said a better business climate in Alaska is necessary to draw the investment needed for continued development of legacy fields, including high-risk satellite opportunities.

John Minge, president of BP Exploration (Alaska), called ACES — Alaska’s Clear and Equitable Share — a good short-term fiscal policy for the state, but said because it’s short-term, BP will have to “adjust our plans and our strategy to shorter term, to fit within the ACES policies.”

Minge said if the state wants to see a long-term sustainable oil industry, and a gas pipeline, it needs to consider a policy to encourage long-term investment.

CD-5 going ahead

Olds said ConocoPhillips will be going ahead with CD-5, and will start construction in 2013.

CD-5 will be the first development in the National Petroleum Reserve-Alaska, and crude oil from that drill site will tie back into the Alpine production facilities on state lands. Development was held up for years in disputes over how oil, and personnel, would cross the Nigliq Channel of the Colville River, which lies between Alpine and CD-5. The Corps of Engineers approved a bridge proposal earlier this year.

Olds cautioned that ConocoPhillips moved CD-5 forward “before the current tax regime,” spending a lot of time and money to advance technology for the project, but before ACES was put in place.

Olds didn’t provide details on CD-5 development plans, but ConocoPhillips Alaska spokeswoman Natalie Lowman told Petroleum News in an email that plans remain as the company described them a year ago, starting with completion of engineering design work, ordering of materials and equipment and beginning of fabrication next year and construction “over two years to coincide with the ice road access to Alpine.” Lowman said first production is expected in late 2015.

Olds said the company sees other opportunities in NPR-A, but they are farther from infrastructure, with smaller accumulations and higher risk.

ConocoPhillips has two federal units — Greater Moose’s Tooth and Bear Tooth — farther west in NPR-A.

Focus on light oil

Minge said that in adjusting its plans to fit with the state’s policies, BP is going to stop, within the next few months, its heavy oil pilot investments and stop further investments in viscous oil.

He said the company’s plans “have really been mismatched against the state policy” and “probably a little too focused on some of the more challenged resources and we’ve got to take some steps to invest into the easier light oil.”

He also said BP will focus on making dollars go further.

Efficiency and technology will be a focus, and Minge said the company will “take some significant steps to make our business more efficient.”

That includes increasing investment “into the easiest oil, the light oil” in order to “put off the decline as much as we possibly can to grow the cash flow.”

He said that includes de-bottlenecking facilities and “looking at taking infrastructure out of service so that we don’t have to pay to maintain that.”

Money will be moved, Minge said: “Our capital’s about the same — but we’re going to move it into short-term, easier oil.”

It’s short-term

What the new plan does, Minge said, is takes “more oil out of the tank faster and you’re not actually progressing resources for the very long term.”

If the State of Alaska has a short-term, 10-to-15-year mindset, “ACES is perfect.” In the short term, it’s the right approach, he said.

“But if you want to take a long-term view and have a sustainable oil business and have a real shot at gas, change is needed.”

Minge said he finds real disagreement among Alaskans he talks to on whether oil taxes should be changed, but no disagreement on the goals: “Everyone wants a sustainable oil business; everyone wants a major gas project to go forward in the state; everyone wants affordable energy for in-state needs — and it couldn’t be any more dire than it is in the Interior of Alaska; and everyone wants jobs.”

Minge called ACES a “short-term going-out-of-business policy” and said it has delivered predictable short-term results: “The State of Alaska is doing extremely well, taking vast amounts of the upside in oil prices.”

“It’s also clear that the long-term investment is down, especially capital going into production enhancement activities,” Minge said, with production decline continuing at 6 to 8 percent a year.

“And ACES is a major impediment to a major gas project,” Minge said.

He said a change in tax policy would make Alaska more competitive and draw more investment, slowing production decline and creating “a healthy long-term oil business with a long-term future to generate revenue” to the state and the producers, while creating jobs and allowing “for legacy infrastructure to be maintained for the very long term,” increasing odds of a major gas project going forward.

“So what do Alaskans get for the X-billion-dollars-a-year giveaway? They get a future,” Minge said.

One big argument against changes in taxes has been the lack of guarantees, he said.

The state’s tax and royalty system is similar to those in many places BP works, and “I’m not aware of any tax and royalty regime in the world where there is this debate: What will you promise me to get a reduction?”

Elsewhere, he said, economic theory is used.

“The sovereign government determines the policy; investors respond to this policy.”

If taxes are changed in Alaska and there is no investment increase, “the taxes can always be changed back,” he said.

ACES and the gas line

Minge argued that a tax change is needed to move the gas project forward.

Physically, the oil and gas are in the same reservoir, come out of the same wells, go into the same flowlines and pipelines and are processed in the same infrastructure, he said.

Then there is the length of a gas project, Minge said, with the timeline submitted to the governor showing a final investment decision by 2016, five or six years of construction and a project life of about 40 years.

Combined, that’s out to 2062-63, he said.

“That means at that time Prudhoe Bay infrastructure is 90 years old and it needs to look a whole lot better than most people do at 90 years old if it’s going to enable this gas project to go forward.”

Then there is the huge investment, $45-$65 billion, “slightly less than the total capital budgets of ExxonMobil, BP and ConocoPhillips combined in 2012,” he said.

As the companies look at cash flows from the project they ask if they could write off the capital investment against oil taxes.

“And the fact of the matter is we know there’s no way — the State of Alaska can’t afford it; the State of Alaska would go broke,” Minge said.

Which means the producers would have to invest the money upfront, “10 years of investment before we get one dime of revenue.”

And there’s something else about that $45-$65 billion, Minge said. “We assume that the project economics start at the fence line of Prudhoe Bay and Point Thomson,” so no gas project investment is required at Prudhoe Bay.

“But we also say the operating cost on the slope is essentially zero — we look at the operating cost of the project from the fence line down,” he said.

Prudhoe Bay facilities were designed for 30 to 35 years, and if “it needs to be 90 years old, we need to be investing today into that infrastructure so that it will last out to 2065,” Minge said. “The tax policy of ACES does not support that.”

Opportunities for Conoco

ConocoPhillips’ Olds discussed some of the opportunities that the company sees in Alaska.

At Kuparuk, he said, the company is looking at designed wells.

Over the last few months the company has implemented “what we call an octa-lateral, four laterals going out one way, four going out the other way.” That’s complex, he said, and requires a technology investment.

And at Kuparuk “the targets are smaller, they’re higher risk and so we need to continue to use innovation and technology to go after them,” which also requires a good business climate, Olds said.

There are also opportunities south of Kuparuk, he said.

“They are some small satellite developments that are years in front of us,” but require the company to ask if the size is there, if the risk is acceptable and if the business climate is there to support the work.

Viscous oil, being produced at West Sak, needs technology for more development.

And heavy oil, with a billion barrels at Kuparuk, will require “significant technology to advance it. Currently there’s not a commercial application to unlock that potential,” he said.

“We’ve got opportunities, but it needs the right business climate to continue to advance these,” Olds said.

While there may be big Chukchi discoveries in the future, they would be at least a decade from production, he said, and legacy fields are the immediate source of production, with 4 billion barrels of potential recoverable over that decade.

But that production will require “substantial investment” in new wells and infrastructure tie-ins, “and that’s on top of the renewed infrastructure investment that we’re doing.”

It requires investment, he said, and while ConocoPhillips increased its investments in the Lower 48 from $1.6 billion in 2010 to $4.8 billion in 2012, “in Alaska, we’ve remained flat at $900 million.”

There is opportunity to invest in Alaska, he said, “we just need the business climate to do so.”

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