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.

Funding

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: http://www.petroleumnews.com/pntruncate/778506065.shtml



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: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/December-Issue-5-2012/Pivotal-year-ahead-for-oil-and-gas/#ixzz2GN9vj1fN



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: http://www.petroleumnews.com/pntruncate/608185410.shtml

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: http://www.petroleumnews.com/pntruncate/605396253.shtml

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 dnr.alaska.gov/commis/pco.

http://www.petroleumnews.com/pntruncate/136295526.shtml

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.

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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: http://www.petroleumnews.com/pntruncate/940939672.shtml