Monday, October 29, 2012

Southcentral utilities plan to import gas to meet projected shortfall

Tim Bradner
Alaska Journal of Commerce

Utilities in Southcentral Alaska have asked for proposals for liquefied natural gas or compressed natural gas imports to help ensure local gas supplies, a utility group told the Regulatory Commission of Alaska Oct. 24.

Gas fields in the region, which date from the 1960s, are being depleted, and production will be inadequate to meet local demand for space heating and power generation by as soon as 2014, said Lee Thibert, vice president for strategic planning for Chugach Electric Association, the state’s largest electric utility.

Thibert was speaking for group of five regional Alaska utilities and Donlin Gold, a mining company which needs natural gas to power a large gold mine the company plans in Southwest Alaska.

Besides Chugach and Donlin Gold, the group includes the regional gas utility, Enstar Natural Gas, and three other electric utilities, Homer Electric Association, Matanuska Electric Association and Anchorage’s city-owned Municipal Light & Power.

There is new exploration drilling under way in south Alaska and some gas discoveries are being made, but permitting requirements and lead-times for construction, particularly offshore, will prevent gas being available to meet the projected 2014 shortfall, said Colleen Starring, CEO of Enstar, the gas utility.

The electric utilities have some ability to switch to oil but Enstar is totally dependent on gas.

“If gas is not available our only choice is curtailment,” she said, a gloomy prospect if it happens during the Alaskan winter.

Assuming no substantial reserve additions the gas supply gap in the region begins at about 10 percent of current demand in 2014 and grows to a 50 percent shortfall in 2019, according to an analysis by Petrotechnical Resources Alaska, a consulting group hired by the utilities. Total gas use is about 110 billion cubic feet per year, with utilities using about 70 billion cubic feet annually. Gas is also used as fuel for a Tesoro Corp. refinery near Kenai and offshore oil producing platforms in Cook Inlet.

Even with an optimistic reserve additional assumption of 20 million cubic feet per day of new production added per year the gap is still 25 percent of demand by 2019, according to the PRA study.

New exploration in the region could result in more substantial new supply by 2017, however, and a state corporation working on a 24-inch gas pipeline from the North Slope could meet the shortfall by 2020, but a gap between 2014 and 2017 remains under almost any scenario.

Thibert said the utilities working issued Solicitations of Interest for LNG or CNG supplies two years ago and have already met with one group of potential suppliers, he said. The utilities have hired an Alaska economic consulting firm, Northern Economics, to help them decide between LNG or CNG.

They will make the decision by the end of the year and are planning to spend $5 million next spring on engineering for facilities in Alaska needed for LNG regasification or CNG depressurization. The utilities will ask permission from the Regulatory Commission of Alaska to include that expense in their rate base, Thibert said, along with, eventually, an undefined larger amount for construction of facilities.

The group has also been in discussions with ConocoPhillips on converting its LNG plant at Kenai to a regasification and import facility. The plant is still making LNG and shipping it to Japan, but the LNG export license for the plant expires next March.

ConocoPhillips has made no statements on its plans for the facility, but in their planning the utilities assume exports will cease.

Thibert said gas imports would likely be in small increments at first so as to not disrupt exploration efforts underway. If those are unsuccessful the imports can be expanded.

The group has been working on import options for some time but did not seriously consider compressed natural gas until recently because of the lack of a licensed vessel for transporting CNG as well as an ability to get gas to tidewater in the Pacific Northwest.

Recently, however, the group has been in contact with three shipbuilders who are able to build CNG vessels, Thibert said. Once built, the vessels would have to be licensed by the American Bureau of Shipping as well as the U.S. Coast Guard if they are to operate in U.S. waters.

Citing confidentiality, Thibert said he could not identify the shipbuilders.

The utility group has also been in contact with Pacific Northern Gas in British Columbia, which currently delivers gas from Canadian producing areas to two ports, Prince Rupert and Kitimat, B.C.

Thibert said the LNG options being considered include conventional ships like those now carrying LNG from the Kenai plant, LNG vessels with ship-mounted regasification and LNG barges that would be towed by tugs.

Ironically, there are large resources of stranded gas on Alaska’s North Slope, about 800 miles north of Anchorage, which is on the state’s south coast. Unfortunately, there is no pipeline now available to bring gas south from the slope, although producing companies and the state are working on a pipeline plan.

Tim Bradner can be reached at tim.bradner@alaskajournal.com

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/October-Issue-4-2012/Southcentral-utilities-plan-to-import-gas-to-meet-projected-shortfall/#ixzz2AljkO2fd

Sunday, October 28, 2012

CD-5 is alive; Conoco sanctions Alpine West; now needs partner approval; first oil by 2016

Eric Lidji
For Petroleum News

After years of permitting delays, ConocoPhillips Co. is moving ahead on CD-5, the fourth satellite of its Alpine field on the North Slope, the company announced Oct. 25.

The ConocoPhillips board sanctioned the project in October, Executive Vice President Exploration and Production Matt Fox said during a third quarter earnings call. “The project is now pending partner approval, which is expected in November,” Fox said.

ConocoPhillips expects CD-5 production to begin in 2016, Fox said. The company previously estimated construction would begin in 2014 with first oil in late 2015.

After bringing the Alpine field at the Colville River unit into production in 2000, ConocoPhillips and its partner Anadarko brought three Alpine satellites online over the following decade: Fiord in August 2006, Nanuq in December 2006 and Qannik in 2008.

Also known as Alpine West, the CD-5 satellite would be the first development in the National Petroleum Reserve-Alaska, located just across the Colville River from Alpine.

The plans for how best to cross the river caused major delays.

In 2005, ConocoPhillips applied for a permit to build a utility bridge across the Nigliq Channel of the Colville, but withdrew the application in early 2008 after officials in Nuiqsut and the North Slope Borough questioned the proposed location of the bridge.

Once the parties agreed on a new location, ConocoPhillips resubmitted its application in 2009, but the U.S. Army Corps of Engineers denied the permit in early 2010, suggesting that ConocoPhillips use horizontal directional drilling to go under the Nigliq Channel.

Backed by state and congressional leaders, ConocoPhillips appealed the ruling. In late 2011 the Corps approved the bridge “with special conditions to ensure that all appropriate and practicable steps to minimize potential adverse impacts to the aquatic ecosystem have been taken, and to ensure the project would not be contrary to the public interest.”

Earnings up over 2011

ConocoPhillips Co. reported net earnings of $535 million from its Alaska operations in the third quarter, up 6.5 percent year-over-year but down 3 percent quarter-over-quarter.

With its effective tax rate down year-over-year, Alaska’s largest producer saw its earnings increase over last year despite declining production, steady or falling commodity prices and increased spending. However, ConocoPhillips notes it is currently paying more than twice as much in state and federal taxes in Alaska as it earns from operations in the state.

Therefore, the quarterly figures are likely to re-ignite a long-running debate about the competitiveness of the Alaska fiscal regime compared to other oil-producing regions. The Alaska Legislature has been tangling over revisions to that system for years and is almost certain to keep tangling over them again when it convenes its regular session in January.

“We hope that the 2013 state legislature will enact meaningful severance tax reform to attract more capital investment in key legacy fields,” Bob Heinrich, vice president of finance for ConocoPhillips Alaska, said in a prepared statement. “It will take more investment than we see today to stem the North Slope’s continuing decline.”

Companywide, ConocoPhillips earned nearly $1.8 billion in the third quarter, down considerably from nearly $2.6 billion earned during the same period last year.

Before income taxes, ConocoPhillips earned $820 million from its Alaska operations in the third quarter, up 4 percent from $789 million earned during the same period last year.

Those revenues place Alaska fourth in the ConocoPhillips upstream portfolio, following the Asia Pacific and Middle East ($1.1 billion), other international projects ($963 million) and Europe ($962 million). But Alaska brought in more than the Lower 48 and Latin America ($250 million), and Canada (which posted a $39 million loss in the quarter).

After taxes, the $535 million in adjusted earning ConocoPhillips reported for Alaska during the third quarter placed the state second only to the Asia Pacific and Middle East segment ($802 million). ConocoPhillips reported adjusted earnings of $145 million from its Lower 48 operations and reported a $31 million loss from its operations in Canada.

The Alaska unit said “inventory sales” added some $120 million in earnings this quarter.

The tax burden

Taxation provides another point of comparison.

ConocoPhillips paid some $917 million in taxes and royalties to Alaska and the federal governments during the third quarter, including $651 million for “severance taxes, royalties, property taxes and state income tax” in Alaska, according to the company.

Those payments are down $332 million from the second quarter, a drop ConocoPhillips attributed to a production decline of 39,000 barrels of oil equivalent quarter-to-quarter.

Comparing this year to last year, ConocoPhillips paid an effective income tax rate of 34.8 percent in Alaska in the third quarter, compared to a 36.3 percent tax rate during the same period in 2011. Including non-income taxes, ConocoPhillips paid a 56.7 percent tax rate in Alaska in the third quarter compared to 64.4 percent during the same period last year.

ConocoPhillips points to the difference between its earnings and its obligations in Alaska.

While the company has paid $3.7 billion in state and federal obligations on its operations in Alaska through the first nine months of the year — including $2.8 billion in state taxes and royalties — it has earned only $1.7 billion in profits, according to the company.

In 2011, ConocoPhillips paid $5 billion in state and federal taxes on its Alaska operations — including $4.1 billion in state taxes and royalties — and earned $2 billion in profits.

Companywide, ConocoPhillips reported a 51.8 percent effective income tax rate in the third quarter, down from 58.5 percent during the same period last year. In Europe, ConocoPhillips paid an 86.3 percent tax rate during the quarter. In the Lower 48 and Latin America, the company paid a 26.9 percent and in Canada it paid 19.2 percent.

Increased spending

The rising profits and falling tax rate came as ConocoPhillips increased spending in Alaska, reporting a $208 million capital program for the third quarter, up from $194 million in the third quarter of 2011 and $202 million in the second quarter of 2011.

The spending in Alaska, though, is the smallest for any ConocoPhillips business unit. Of its nearly $3.7 billion capital program for the quarter, ConocoPhillips spent $1.3 billion in the Lower 48 and Latin America, $738 million in Europe and $493 million in Canada.

ConocoPhillips’ quarterly depreciation, depletion and amortization expenses in Alaska fell to $117 million from the third quarter of this year, down from $134 million during the same period last year and down from $133 million during the second quarter of 2012.

Declining production

The financial figures mask increased production declines. ConocoPhillips produced some 176,000 barrels of oil equivalent per day in Alaska during the third quarter, down some 32,000 barrels of oil equivalent per day from the same period last year. This 15 percent year-over-year drop reflects “normal field decline and increased turnaround activity in the current quarter,” according to the company.

The declines hit all products. Crude oil production fell 16 percent year-over-year to 157,000 barrels per day, while natural gas liquids production fell 17 percent to 10,000 barrels per day and natural gas production fell 9 percent to 51 million cubic feet per day.

As Alaska production falls it also continues to lag behind other units. During the third quarter, ConocoPhillips produced 462,000 boe per day in the Lower 48 (up 6 percent year over year) and 197,000 boe per day in Canada (down nearly 3 percent year over year).

In the Lower 48, ConocoPhillips produced 124,000 barrels per day of crude oil during the quarter, up from 95,000 barrels per day last year, an increase credited to the ramp up of activities in the Bakken play of North Dakota and the Eagle Ford play of south Texas.

Commodity prices dropped as well.

ConocoPhillips reported an average realized price of $106.53 per barrel for Alaska liquids in the third quarter, down from $107.26 during the third quarter of 2011. Over the same period, Alaska natural gas prices fell to $3.97 per thousand cubic feet from $5.04.

In the Lower 48, ConocoPhillips reported an average realized price of $90.06 per barrel for oil, $31.40 per barrel for natural gas liquids and $2.64 per mcf for natural gas.

Read more: http://www.petroleumnews.com/pntruncate/617464300.shtml

Friday, October 26, 2012

Time for action is here; Southcentral Alaska utilities are moving forward on options for gas imports

Alan Bailey
Petroleum News

With natural gas supplies from Cook Inlet set to fall short of local gas demand by 2014 or 2015, the time has come to move ahead with arrangements to supplement those local supplies with imports from elsewhere, Southcentral power and gas utility executives told the Regulatory Commission of Alaska during a public meeting on Oct. 24. Southcentral residents and businesses depend on gas both for power generation and for the heating of buildings.

“I’m personally done wringing my hands,” Bradley Evans, CEO of Chugach Electric Association, told the commissioners, saying he takes responsibility for ensuring continuity of gas supplies for his utility. Chugach Electric currently generates about 90 percent its power using gas-fueled power plants.

“I’m not comfortable. I’ve lost a lot of sleep. But we’ve got to move forward,” Evans said, responding to a question from one of the commissioners about the utilities’ commitment to spending money on the engineering required for a final decision on a gas import project. “We need to get to where we have a business model — less study and more action, actually defining how would you get the job done to avert the problem. … We’ve got to move down this path. We’ve got to spend this money.”

Gas shortfall

Consulting firm Petrotechnical Resources of Alaska, or PRA, has been assessing and monitoring the Cook Inlet gas supply situation for the utilities and has reported that there is little likelihood that development drilling in existing fields will significantly defer a gas shortfall. At the same time, new fields discovered from an upsurge in Cook Inlet exploration are extremely unlikely to bring sufficient new gas online quickly enough to remedy the situation, PRA says. So, the utilities are now looking at two options for supplementing local gas supplies: the import of liquefied natural gas from overseas or the import of compressed natural gas from the west coast of North America.

Lee Thibert, senior vice president of Chugach Electric, said that the utilities have asked potential shippers of imported gas for expressions of interest in the import arrangements. Consultancy firm Northern Economics will analyze the relative merits of the two import options and will likely present the results of its analysis by the end of the year. The utilities will then decide in the first quarter of 2013 which option to progress, a decision that will subsequently lead to the negotiation of contracts for the various necessary arrangements, including gas supplies and the shipping of the gas. Before making a final decision on implementation, the utilities expect to have to spend somewhere around $5 million on the preliminary engineering of the gas importing facilities, Thibert said.

High fuel oil cost

Thibert explained that without the option to import gas from out of state, the only feasible way of keeping power plants running continuously would be to use of fuel oil instead of natural gas. But with fuel oil being much more expensive than gas, the use of oil would cause Southcentral energy prices to increase much more rapidly than would be the case with imported gas.

However, it will be important to bring in external gas quite slowly at first, importing minimal quantities that will not disrupt the Cook Inlet gas industry.

“We have to avoid discouraging new Cook Inlet production,” Thibert said.

The import arrangements also need to be scalable and flexible, allowing imported volumes to increase or decrease, depending on the health of Cook Inlet gas production.

LNG versus CNG

For several years a group of utilities and other stakeholders in the Southcentral gas industry has been studying the potential gas supply shortfall and has tended to lean towards the import of liquefied natural gas, or LNG, rather than compressed natural gas. LNG enjoys a well-developed market, as well as economies of scale in its shipping arrangements, Thibert said. There has been much talk about the possibility of converting an LNG export facility on the Kenai Peninsula into an LNG import terminal, although people have also been looking at several other options and sites for bringing LNG into the state.

With no access to pipeline capacity for delivering North American gas to a suitable port, and with no ships licensed or approved for transporting compressed natural gas, or CNG, the compressed gas option seemed the poor relation to its more mature LNG brother, Thibert said.

But the situation has changed in the past year, Thibert explained. There is now a shipbuilder with a permit to build ships for carrying CNG. And Pacific Northern Gas, the company that has recently taken over ownership of Southcentral utility, Enstar Natural Gas Co., operates a pipeline system for delivering Canadian gas to tidewater at Prince Rupert and Kitimat, British Columbia.

Pacific Northern Gas has expressed its willingness to support a CNG project, either through the use of existing pipeline capacity, or possibly through additional capacity, Thibert said.

CNG offers the advantage of tapping into supplies of cheap North American gas, while LNG purchased on the Pacific Rim would be much more expensive. And, while CNG is much more costly to transport than LNG, the shipping distance from British Columbia would be less than 1,000 miles. CNG is easier to load and offload than LNG, and does not require expensive handling and regasification facilities.

While the concept of importing gas is an anathema to many Alaskans, the utilities say that their duty to reliably provide energy leaves them with no alternative to this course of action.

“We have to keep the lights on and the homes heated, so we don’t really have any other option,” Thibert said.

In-state gas line meets milestone with final EIS

Tim Bradner
Alaska Journal of Commerce

The U.S. Army Corps of Engineers is scheduled to publish the final environmental impact statement for a 737-mile, 24-inch in-state gas pipeline from the North Slope to Southcentral Alaska on Oct. 26, according to the Alaska Gasline Development Corp., or AGDC, the state corporation planning the project.

Notice of the FEIS will appear in the Federal Register Oct. 26.

It is an important milestone for the project, said Leslye Langla, spokeswoman for ADGC, although it is not a guarantee that the project will be built.

So far AGDC has spent $64 million on the project, mostly in engineering and permit-related work, Langla said, The group will be coming to the Legislature next year with a request for $300 million for engineering and other work, she said, that will take the project through an “open season” for solicitations to ship gas, and to the point where a construction decision can be made.

Two years ago the Legislature set aside $200 million for the project but an appropriation of funds is still needed.

The pipeline is planned to be 737 miles in length and would parallel the trans-Alaska Pipeline System to Alaska’s Interior and then follow the Parks Highway to Southcentral Alaska, terminating near Anchorage. It would operate at a pressure 2,500 pounds per square inch so as to be able to transport natural gas liquids like propane along with methane, the main component of natural gas.

“We will also receive a 100-mile right-of-way across federal lands as soon as the FEIS is issued. We already have an unconditional right-of-way across 604 miles of state-owned land,” Langla said.

The pipeline must also cross a small amount of private land.

Langla said that once the FEIS is published, the Corps can be expected to issue a final Record of Decision in about 30 days. The next milestone would be a Corps of Engineers Section 404 permit to cross wetlands along the pipeline right-of-way. One area of wetlands that would be crossed is Minto Flats, west of Fairbanks. AGDC expects to receive the Section 404 permit in the first quarter of 2013, Langla said.

At this point the project cost is estimated at $7.52 billion in 2011 dollars with about a 30 percent confidence in the number, Dan Fauske, AGDC’s CEO, has said in previous briefings. The estimate will be refined and the uncertainty reduced as engineering work proceeds.

Decisions on the project final ownership and financing have yet to be made, but one possibility is state ownership and financing through state revenue bonds, with construction and operation would be contracted to private firms, Dan Fauske has said.

That form of organization would result in the lowest cost for moving gas through the pipeline because the tariff structure would not contain an equity component with a profit paid to an investor.

Another possibility is for one or more private firms make take an equity ownership in the project and finance and own the pipeline privately, which would take the state out of ownership but also have the tariff structured to allow for profits for the investor.

There are also combinations of the two, one being some form of joint-venture between the state and private parties, with the state providing financing through bonds.

There are precedents for this: The Alaska Industrial Development Corp., a state development corporation, is allowed to invest in a project in partnership with private firms and to provide financing.

Alaskans shouldn’t be wary of state ownership of a large infrastructure project if they are done right, Fauske has said.

There are many successful examples of this including state ownership of large hydro projects like the Bradley Lake project near Homer through the Alaska Energy Authority; the Red Dog Mine road and port, through AIDEA; the Skagway ore terminal and Ketchikan shipyard owned by AIDEA; or smaller projects like the Federal Express hanger at Ted Stevens Anchorage International Airport, which is owned by AIDEA but leased to Federal Express Corp.

AGDC will be asking the Legislature to decide on the most appropriate organization for the in-state pipeline as the project moves forward, Langla said.

The current design capacity for the 24-inch pipeline is for 500 million cubic feet per day, which is based on a commitment the state has made in a contract with TransCanada Corp. under the Alaska Gasline Inducement Act.

This limits the amount of gas the state can take for a state-sponsored project other than the larger project TransCanada is working on, which is designed to move about 4 billion cubic feet per day. The state is also supporting that with a $500 million grant under the AGIA contract.

The limit on gas volume has caused some heartburn among state legislators who believe larger amounts of gas being shipped are needed for the pipeline to be viable.

Fauske said he agrees that a higher volume would be better but the state is currently limited by the AGIA contract.

AGDC began work on the 24-inch pipeline as an alternative three years ago when there was great uncertainty about a large-diameter pipeline. The goal would be to move at least some North Slope gas south to the state’s Interior and Southcentral communities in case the large project encounters long delays or is not built.

TransCanada has already encountered one setback when its plan for a 48-inch pipeline from the North Slope to Alberta had to be shelved because of the glut of inexpensive shale gas in North American markets. The pipeline company is now working with North Slope producers BP, ConocoPhillips and ExxonMobil on a large-diameter pipeline to a south Alaska port and a large liquefied natural gas export project, but that is in a very early stage of conceptual planning and is highly uncertain.

ADGC hit a setback itself earlier this year when the state Legislature failed to appropriate all funds requested by the corporation for advanced engineering, although $21 million was made available. ADGC was hoping to have its project in construction by 2016 and in operation by 2018 but that has now been set back a year, and possibly more.

The large gas project being considered by TransCanada and the gas producers, estimated to cost from $45 billion to $60 billion, couldn’t be operational until 2024 at the earliest.

If that project is built the smaller AGDC pipeline could be used as a spur line to carry gas to Anchorage, Fauske said, or converted to other uses.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/October-Issue-4-2012/In-state-gas-line-meets-milestone-with-final-EIS/#ixzz2AUWMIl77

Tuesday, October 23, 2012

More new wells needed; Analyst says rate of drilling insufficient to head off Cook Inlet gas shortage

Alan Bailey
Petroleum News

A new revision to a study by Petrotechnical Resources of Alaska, or PRA, into Cook Inlet gas supplies makes sobering reading for anyone living in Southcentral Alaska. Essentially, the revised study has found that, in the absence of a fairly dramatic increase in the amount of gas well drilling or the discovery of a significant new gas field close to the existing gas infrastructure, supplies of gas from the Cook Inlet basin will start to fall short of gas demand perhaps as early as 2014.

Southcentral residents depend on natural gas for the heating of buildings and for about 90 percent of the region’s power generation.

“Without some really large discoveries that can be brought on quickly, the current pace of development activity, even if it continues or increases, could still mean a shortfall in Cook Inlet supplies to meet our demands as early as 2014, but more likely 2015,” PRA consulting petroleum engineer Pete Stokes told a meeting of the Alaska Support Industry Alliance on Oct. 11.

An earlier incarnation of the PRA study, published in 2010, had predicted that without new development drilling there would be a gas shortfall in 2013. And, although some new gas wells and new gas compression in gas fields have boosted gas supply levels since 2010, these infrastructure additions have only moved the time of the predicted shortfall by about a year, Stokes said.

Short-term gap

Stokes said that although heightened levels of gas development and exploration in the Cook Inlet basin will likely lead to an eventual improvement in the gas supply situation, the lead time in bringing new sources of gas on line, coupled with rates of drilling below what is required to stave off the gas production decline, make it unlikely that new gas can come on stream in sufficient quantities before perhaps 2019. That leaves a supply gap in the intervening period.

“I am concerned about the short term,” Stokes said.

And, with no realistic possibility of bringing North Slope gas by pipeline to the Cook Inlet region before 2020, should proposals for such a pipeline come to fruition, the import of liquefied or compressed natural gas from out of state has to be considered to bridge the gas shortfall gap, Stokes said. Stokes likened the import option to an insurance policy: It might not ultimately be needed, but without the work to enable it to happen, the option will disappear.

“There is ongoing work towards this goal,” he said, referring to actions that the Southcentral utilities have been taking to find some way of importing gas. Although there has been much talk of importing gas in liquefied form, the import of compressed natural gas from the Lower 48 may be a better option, given the price differential between cheap North American gas and expensive liquefied natural gas on the Pacific Rim, Stokes said.

Decline trend

In conducting its study into Cook Inlet gas supplies PRA has investigated the production decline rates of the Cook Inlet gas fields and the decline characteristics of individual gas wells. The outcome of this work has been a predicted decline curve for the entire Cook Inlet basin, if no new wells come on line. With the export license for the LNG export facility on the Kenai Peninsula expiring in March 2013, PRA has assumed a fairly constant level of gas demand from 2014 onwards, with that demand essentially coming from Southcentral gas and power utilities; from the use of gas by the oil refinery on the Kenai Peninsula; and from gas used as fuel in the operation of the Cook Inlet oil and gas fields.

PRA’s predicted gas supply decline curve drops below the anticipated demand level in 2014, with the supply shortfall increasing year-on-year after that.

But this prediction of gas shortfalls is pessimistic because it assumes that no new gas wells will be drilled and that no new compression will be added to fields, Stokes explained.

Required drilling

In 2010 PRA tried to figure out the drilling rate required to avoid the supply shortfall and concluded that 13 to 14 new wells per year would be needed. Unfortunately, since then there have only been around five or six new wells drilled per year, so that gas supplies have continued to decline.

PRA has found that the drilling of three to four wells per year, perhaps adding 10 million cubic feet per day to gas production, would still leave a supply shortfall in 2014. Upping that drilling rate to six to eight wells, increasing production by around 20 million cubic feet per day, would delay the shortfall into 2015, Stokes said.

Development activity

And significant recent changes in the Cook Inlet gas industry do give some cause for optimism about development drilling activity in the near future. Hilcorp Energy, the company that has taken over Chevron’s Cook Inlet assets and is in the process of acquiring Marathon’s interests in the region, is planning major capital expenditures on Cook Inlet oil and gas projects. ConocoPhillips has just completed two new wells in the Beluga River field, Buccaneer Energy is drilling in its Kenai Loop development and Armstrong Cook Inlet has permitted two new wells in its North Fork gas field in the southern Kenai Peninsula.

But, taken together, these new actions still only seem in total to amount to five to six new wells per year, a level of activity below what is needed to boost gas supplies to required levels in 2015 and beyond, Stokes said.

Exploration

So, what about the heightened level of exploration activity around the inlet? Nordaq Energy plans to delineate its discovery at Shadura on the Kenai Peninsula and is exploring at Tiger Eye on the west side of the inlet; Buccaneer has announced new exploration near Anchor Point on the Kenai Peninsula; Cook Inlet Energy is exploring the west side of the inlet; and Apache Corp. has been shooting a major 3-D seismic program, with plans to drill its first well on the west side of the inlet later this year. Offshore, both Furie Operating Alaska and Buccaneer now have jack-up drilling rigs in the inlet and Apache has shot some offshore 3-D seismic. Furie is drilling its second well from its jack-up rig.

But exploration is a risky business with uncertain outcomes, and unless there is a significant find near the existing infrastructure, sufficient gas from exploration discoveries is unlikely to come on line in time to prevent a gas supply shortfall. In particular, it would likely take three to five years after an offshore discovery to bring a new offshore gas field into operation, Stokes said.

Deliverability The other crucial gas supply issue is ensuring that the gas deliverability — the rate at which gas can be delivered through pipelines — is adequate to meet peak demand levels, especially in the depths of winter. And Cook Inlet Natural Gas Storage Alaska’s new gas storage facility on the Kenai Peninsula will play a key role in ensuring that utilities can meet their gas deliverability needs. Essentially, the facility can warehouse gas during the summer when demand is low and then release the gas in the winter when demand is high.

The storage facility can help meet about 50 percent of the average peak monthly demand level while also eliminating the need to overstress gas wells by running them flat out during severely cold weather, Stokes said.

Small market

Stokes also commented that the small size of the local Southcentral gas market is a particular concern. It would take relatively few large new gas discoveries to flood that market with gas, he said. Then, without a market to sell into, companies might leave the region, ultimately causing a recurrence of the current gas supply problems. An industrial consumer, such as the current liquefied natural gas plant on the Kenai Peninsula, can create the type of larger market that drives long-term market stability, but can also bring conflicts over competing gas demands in the short term, he said.

Read more: http://www.petroleumnews.com/pntruncate/476798313.shtml

Sunday, October 21, 2012

Enough is enough with "its our oil"

Deborah Brollini
Technical Writer & Social Media Consultant
Alaska Energy Dudes and Divas

It is unfortunate that because it is an election year that this past legislative session was nothing but an exercise in regards to oil tax reform. The majority of the oil and gas consultants who testified before the Senate this past session were in Anchorage last November and December 2011 for legislative learning sessions organized by Legislative Budget and Audit. Legislators and the public did not learn anything new during the legislative session other than take testimony from the producers and industry groups like the Alaska Oil and Gas Association (AOGA), and the Resource Development Council (RDC).

There has been no change in movement towards oil tax reform that would entice 30-year investment commitments by the producers in Alaska. In addition, the producers were pretty clear in their letter to the Governor on October 1, 2012 that they needed fiscal certainty before moving forward with an LNG gasline project to tidewater. That would be like asking me to commit to my 30-year home loan when the mortgage holder was going to toy with the interest rate from year-to-year. I would have never have made the 30-year commitment to purchase my townhome without certainty, and it is unreasonable to ask the producers to invest billions blindly. Alaskans have a lot to look forward to with all the opportunities before us. However, we need leadership and long-term oil tax reform yesterday because the state is flat out of hail Marys.

It has been years of “groundhog day” legislative sessions with no new North Slope production projects in the queue. Not promising for Alaskans who have become accustomed to a lifestyle that does not include a state income tax, or a requirement of skin in the game by our citizens because we have become spoiled by “our oil.” Is it really in the best interest of the state to have the oil producers moving assets, talent, and their investment dollars to other oil provinces in the world? I know my limits, and I draw the line when "its our oil" legislators, and union backed political action groups mislead, and confuse the public with election year rhetoric. Alaskans deserve the truth.

The “its our oil” crowd would like to have the public believe that all this oil exploration has resulted in new production and new oil into the Trans Alaska Pipeline (TAPS). Investment by the state in oil exploration has not resulted in any new oil production for the past five years, and is that a good use of state dollars with no return on our investment, or no new oil into TAPS? Is it the role of our state government to be picking winners and losers because the “its our oil” believers would like to demonize the oil producers in the eyes of the public?

Alaska's ACES oil tax policy has been on a treadmill going nowhere with no new North Slope financial investment, or new projects on the horizon that will result in adding new oil into TAPS to stem the decline. Money out the door directed by the “its our oil” legislators with no new oil into TAPS, or new tax dollars into state coffers seems “backwards” oil tax policy, and a total lack of regard for the 710,000 Alaskans who have come to rely on the oil industry to fund our state government.

Oil exploration, and shale oil plays should be part of the mix. However, stemming the decline in TAPS and keeping TAPS operational for years to come must be priority number one. Especially, when Shell needs TAPS in year 2025. Contrary to the "its our oil" rhetoric the oil producers have testified they would move forward with several projects they have tabled within existing fields if the investment and tax climate improves for the long-term. I'd rather not participate in the election year rhetoric war. I would prefer we get off the treadmill and get busy with a long-term plan moving Alaska forward.


Alyeska Pipeline Service Company - Alaska Native Program

Tuesday, October 16, 2012

Cosmo drilling first; State OKs deferral of Buccaneer’s Southern Cross, Northwest Cook Inlet wells

Kristen Nelson
Petroleum News

With delays in arrival of the jack-up drilling rig Endeavor — Spirit of Independence, Buccaneer Energy Ltd. said Oct. 5 that the first drilling the jack-up will do in Cook Inlet will be at the Cosmopolitan prospect.

Endeavour was scheduled to drill this year at the Southern Cross and Northwest Cook Inlet units, but those wells have been deferred to next year.

In Oct. 1 letters to Buccaneer Alaska, the Alaska Division of Oil and Gas said it found the company in default under its Southern Cross and Northwest Cook Inlet unit agreements for failure to drill at the two offshore Cook Inlet units this year. The division set conditions for the company to cure the defaults, including completing the first wells at both units by Oct. 31, 2013.

The company requested an extension on the Southern Cross well in July and on the Northwest Cook Inlet well in September.

The company’s plans of exploration had called for beginning wells at both units by Sept. 30, 2012.

Division Director Bill Barron said in the Oct. 1 letters that while the units are in default, failure to drill the wells this year will not result in unit termination, the penalty proposed by Buccaneer in its plans of exploration.

Jack-up the issue

Barron said the state’s approval of the units was based not only on the work commitments, but also “on the exploration and development benefits of Buccaneer bringing a jack-up rig to Cook Inlet that would not only serve Buccaneer in drilling its prospects, but could also create a unique circumstance where the rig could be shared with other operators, thereby promoting exploration and development of other offshore Cook Inlet fields and providing increased potential for economic growth and employment opportunities.”

In requesting a delay for the Southern Cross unit well, Barron said Buccaneer cited the delayed arrival of the Endeavour jack-up, the unavailability of another jack-up drilling rig in upper Cook Inlet and the requirement to discontinue drilling by Oct. 31. He said Buccaneer provided a schedule of costs and additional shipyard work that resulted in the delay of arrival. The upgraded Endeavour arrived in Cook Inlet Aug. 24.

In requesting the delay for drilling at Northwest Cook Inlet Buccaneer cited the delayed arrival of the Endeavour, delays due to additional work required on the rig in Homer and severe weather in September that prevented Buccaneer from beginning drilling operations on or before Sept. 30.

Remaining jack-up work

In its Oct. 5 statement Buccaneer said final work and regulatory inspection on the Endeavour has been ongoing since the jack-up arrived in Homer Aug. 24. Buccaneer listed three “critical path items” which need completion for Endeavour to receive permits to operate in Cook Inlet.

• Fast rescue craft: Buccaneer said the fast rescue craft purchased and installed in Singapore was approved for Arctic service, but the manufacturer issued a recall notice on the craft due to undetected manufacturing deficiencies, requiring replacement with a factory-provided upgrade.

• General alarm system: Buccaneer said the general alarm system was repaired and certified in Singapore but failed during testing upon arrival in Homer. Repairs have been ongoing since, but the company said it is an old system and availability of parts has delayed repairs, resulting in a decision to order and install a new system.

• Firefighting system: The firefighting system installed and certified in Singapore developed a valve leak during transit which was discovered upon arrival in Alaska. The special fire suppressant refill and replacement valve have been ordered but delivery has been delayed. The company said that while delays have been frustrating, “and largely outside of Buccaneer’s control, our priority is to have a fully operational and efficient jack-up rig that ensures the safest possible working conditions for crews and the sensitive environment in which it will operate.”

Requirements to cure

Barron set similar requirements for each unit to cure the default. By Oct. 31, 2013, Buccaneer must have drilled, logged, and completed, suspended or abandoned wells in block A of each unit.

At the Northwest Cook Inlet unit the well must be drilled to the base of the Beluga formation; at the Southern Cross unit the well will be drilled to the pre-Tertiary interval stratigraphically equivalent to the Jurassic interval from 9,042 feet measured depth to a total depth in the Shell MGS SRS State No. 1 well.

For both units second plans of exploration will be submitted by Sept. 1, 2013, with plans to drill the second unit exploration wells in block B of the units.

Barron said the state recognizes “the significant investment” Buccaneer made in acquiring and refurbishing the jack-up and mobilizing it to Cook Inlet, allowing “the potential to create numerous economic benefits” for the state.

By drilling the two wells in 2013, the unit operator and the units “will remain in good standing,” Barron said.

Buccaneer Energy and Ezion Holdings Ltd. formed Kenai Offshore Ventures in 2010 to acquire a jack-up for work in Cook Inlet.

Read more: http://www.petroleumnews.com/pntruncate/826861209.shtml

Sunday, October 14, 2012

Alaska's oil companies are not Satan











Deborah Brollini, Technical Writer
Alaska Energy Dudes and Divas

There is nothing like corresponding with Alaskans who are working in North Dakota begging me to come home. In the past my head would be exploding. However today, these types of correspondence only fill my heart up with sadness. One Alaskan mentioned that he is returning to Alaska for the Thanksgiving holiday to visit and not to live and work in a state that he loves. He asked me on Friday “is the state going to get it together this session?” All I can do anymore is to promise these Alaskans that there are people like myself who are working for long-term oil tax reform, and to bring Alaskans home.

It is unfortunate that Alaska’s oil tax debate has turned into a long painful episode of the Real Housewives of New Jersey while the whole world is watching, and it is downright embarrassing. We live in a world-class oil province and you would think that Alaska would start acting like it, think more maturely, strategically and with vision in order to provide future generations the same opportunities the rest of us have enjoyed due to our oil wealth.

Senators Hollis French, Wielecowski, and Paskvan have made statements that the oil companies will never leave Alaska. That is a pretty arrogant thought process, and a huge gamble with the lives and livelihoods of 710,000 Alaskans. Especially, when these Senators have only proposed oil exploration giveaways to exploration companies whom are non-taxpayers, and have not delivered one new drop of new oil into the Trans Alaska Pipeline (TAPS), or one new penny into state coffers since 2007. Not exactly what one would call a long-term plan to sustain our state financially for years to come. Exploration is important and should be supported. However, exploration should not be the priority. The priority should be increasing oil production within existing fields today, and keeping (TAPS) above 500,000 barrels per day.

Alaskans are being led down this road to think that the oil companies are Satan, not hiring Alaskans, and not producing oil; not true. The oil producers are not exploring for oil because they already know where the oil is, and they are sitting on billions of barrels of it. However, this next generation of oil which is viscous and heavy oil is hugely expensive to extract, and will take billions of dollars of oil company dollars to invest in new technology and talent to bring this oil to market. BP has invested over the past several years in a heavy oil pilot project, and there is no guarantee that that this project will be funded in the future if Alaska does not get its act together. Alaska’s future is heavy and viscous crude. However, the priority needs to be bringing more light oil online through projects within existing oil fields while continuing to invest in viscous and heavy oil to make this next generation of oil economic for the oil companies, the state of Alaska, and our citizens.

Alaskans need to understand that Alaska's oil companies, and the state of Alaska's futures are linked, and how are we going to work together so all parties benefit. I was watching an old 1992 Presidential debate, and one of the lines that resonated with me (in regards to the future of Alaska) was "are we in it to win it?" I think with the right leadership we can all win.


Saturday, October 13, 2012

Consent decree reached to restart Healy Clean Coal Plant

Tim Bradner
Alaska Journal of Commerce

A deal to restart the Healy Clean Coal Plant requires Golden Valley to invest $40 million in additional emissions controls and another approximately $5 million in emissions improvements at an adjacent, smaller and older 25 megawatt coal plant.

Golden Valley Electric Association of Fairbanks and the Alaska Industrial Development and Export Authority, Alaska’s state development corporation, have worked out a consent decree with federal attorneys that could allow for a restart of a mothballed 50-megawatt new-technology coal power plant at Healy in Interior Alaska.

The plant has been idle for almost 12 years, although critical operating systems have been maintained.

The agreement is highly unusual because the Healy Clean Coal Project, or HCCP, is not operating and no violation of the Clean Air Act has occurred, sources familiar with the deal said.
However, the federal Clean Air Act does allow the government to file for an injunction to block a violation that is pending. In this case the U.S. Justice Department filed for an injunction in federal court to block the restart of the Healy plant but filed the Consent Decree at the same time.
The deal requires Golden Valley to invest $40 million in additional emissions controls in the HCCP and another approximately $5 million in emissions improvements at an adjacent, smaller and older 25 megawatt coal plant.

Golden Valley and the state authority, or AIDEA, made the deal with the U.S. Department of Justice and the Environmental Protection Agency after extended negotiations with environmental groups to forestall litigation failed.

Golden Valley spokeswoman Corinne Bradish said the consent decree will be published in the Federal Register soon and will be subject to a 30-day public review period before going to a U.S. District Court for approval. If the court approves, a decision that could come by the end of the year, Golden Valley hopes to have the plant operating in 18 to 24 months, Bradish said.

Having access to inexpensive coal-fired power is important to the Interior Alaska utility because most of its power is now generated with costly fuel oil. Coal is much less expensive than oil, and power can be generated with coal for 5 to 6 cents per kilowatt hour compared to a range of 20 to 50 cents per kilowatt hour in the utility’s oil-fueled plants depending on which unit is operating, said Kate Lamal, a consultant to Golden Valley.

The $305 million plant was built by AIDEA in 1996 and 1997 and was to be operated by Golden Valley, which was also to purchase power from the plant. The U.S. Department of Energy contributed $120 million to the project costs to demonstrate new coal combustion and emissions control technologies, with AIDEA and the State of Alaska funding the remainder of costs.

The facility operated for one year under a contract with DOE to test the technologies with different types of coal but was shut down after operating problems, unrelated to the new environmental systems, developed during a 90-day commercial operations test.

A decade of litigation followed between Golden Valley, the plant operator and regional electric utility, and AIDEA, which owned the plant and had built it.

In settling the dispute AIDEA agreed to sell the plant to Golden Valley, but when the State of Alaska issued a renewed air quality permit for an operating plant, environmental groups objected, arguing Golden Valley should initiate a more complex type of air permit as if the plant were new construction.
EPA agreed but urged the utilities to negotiate with the environmental coalition led by the Sierra Club.

Extended negotiations spanning two years included a proposal for the added environmental controls, which Golden Valley has agreed to as part of the Consent Decree, but also that the utility agree to phase out its coal plants in 20 years. Golden Valley balked at this, and the negotiations ended.
The utility then proposed the Consent Decree to EPA as a way of forestalling a lawsuit from the environmental groups, and EPA agreed to the approach.

Cory Borgeson, Golden Valley’s acting president, said, “We chose to pursue the Consent Decree option with EPA because, otherwise, there was no defined end to the air permitting process,” with almost certain appeals of the Clean Air Act’s Prevention of Significant Deterioration permit procedure.

“Very important, the Consent Decree avoids what we believe would have been lengthy and costly litigation,” Borgeson said.

Environmental groups had targeted the plant restart as part of a national effort to force the closure of coal-operating electric power plants.

In addition to new combustion and emissions systems in the original plant design, aimed at reducing sulfur dioxide (SO2) and nitrous oxide (NOX), Golden Valley agreed to install a Selective Catalytic Reduction, or SCR, system in the plant’s exhaust system to further reduce SOX and NOX, Lamal said.

The utility will spend an additional $5 million at a smaller, older 25 MW coal plant, Healy 1, that is adjacent to the 50 MW HCCP. Another $250,000 will be contributed to a wood stove change-out program operated by local municipalities, and that would reduce particulates from wood smoke, a major contributor to human health problems that occur locally during certain winter air conditions.
“A couple of things need to happen before we have the keys to the plant. One is the judge’s final approval following the 30-day public review. Second is the approval of the Regulatory Commission of Alaska,” Borgeson said.

Lamal said EPA made significant concessions in recognition of special conditions.
One is that Golden Valley will be allowed to restart the plant and operate it for 18 months without the SCR being installed.

“This will allow us to get the plant operating in a stable condition,” Lamal said. Secondly, plant shutdowns for the modifications will be done during the summer, a period of low power demand in Alaska.

Friday, October 12, 2012

Alaska’s Future Begins Now

Ann Lovejoy

Your car goes where your eyes go. If you look at the wall beside the roadway, you crash. So, what’s the solution? Look at the route to get back on the roadway and away from the wall, of course. From a business perspective, this means we must move away from declining product or service lines toward new service or product lines. We sometimes call this innovation, responding to the market, staying current, focusing on customer needs. All these buzzwords simply say we are externally focused on product cycles. We make decisions like the country western song tells us: “know when to hold ‘em, know when to fold ‘em.”

A typical product cycle looks like a bell curve. In the early part of the cycle, the company researches, designs, and pilots the new product. There’s an upward slope as sales increase; the product passes break-even point. Near the top of the curve, the product is said to be “mature.” After the peak, product sales decline when customers don’t replace, buy from competitors, or find alternatives in the market.











  



Inflection point screams decline = time to take action!
  • As an organization’s product or service cycle moves up the curve during expansion -- opportunity and revenue are abundant.
  • New or improved offerings must be released to match competitors’ cycles.
If the organization does not continuously create new opportunities, the down side of the curve is the loss of customers, revenue and inability to sustain the business. Skillful leaders ramp up investment and design for the next product cycle. We overlap product or service cycles. As one product declines, the next one is starting to be profitable. That way, we are less likely to fall into crises, there’s always a way to get revenue. We make a diverse portfolio of ways to stay in business. One point is really important: no one can invest in everything all at once – there’s not enough money or people to do it. Resources are scarce. We use the decline to give us cash to fund the next cycle.

Think about Apple computer, for example – they deliberately cycle product release windows so break-even from the new product overlaps the next product cycle:












We achieve more when we don’t blast buckshot at the wall. As a product cycle begins to decline, we honestly admit that’s happening. Then we research, design, and implement the next one, then the next! This perspective holds for a single human being, a company or a state. The difference is merely scale. If I decide to complete a single task or learn a new skill – it doesn’t take very long. If I thrash around with many skills or tasks, I get overwhelmed and give up.

For the past decade Alaskans have listened to tax-debate arguments about a single product. What if we looked at the declining light-crude oil product curve differently? What if we said, “Ok, that’s our declining cash source?” In 5 years, what is the next product if we planned and invested starting now?

Alaska has multiple opportunities which appear to be starved for money and attention. Extraction and resource product cycles are 50 years long! The next cycle may be heavy crude, coal, gas. After that, energy product cycles may include one, some or a mix of hydroelectricity, wind, geo-thermal, tidal cycles. These are sustained and supported by money from the historical, declining products.

The future begins now. Ask your legislators to list alternatives they are truly committed to championing. Ask, “how’s that single declining product cycle working for you?” Help change the direction we are traveling and do what passionate, positive, future-focused Alaskans know will work.
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Ann L Lovejoy has been an organizational transformation consultant, process leader and officer in Fortune 500 companies for over 20 years. She currently lives in Anchorage and may be contacted via Linkedin.com or all@creativeintermedia.com

I Pad progress uncertain; state partially approves development

—Eric Lidji

The Alaska Division of Oil and Gas has partially approved a pair of BP Exploration (Alaska) Inc. development plans for the western edge of the Prudhoe Bay unit, a region at the center of recent debates over how to spur North Slope oil industry investment.

The plans concern the Borealis and Orion participating areas, overlapping jurisdictions targeting reservoirs at different depths in the northwest corner of the Prudhoe Bay field.

While the southern and central portions of these participating areas have been drilled or are already in production, the division claims BP “has failed to follow through with the development commitments” for the northwestern portion of both participating areas.

These commitments primarily concern I Pad.

BP originally expected to build the pad in the northwest portion of the participating areas and bring the region into production by 2006. It later deferred those plans until the 2010 timeframe, but now, according to the state, the schedule is closer to 2017 to 2020.

According to state estimates, I Pad could access between 69 million and 144 million barrels of recoverable oil at Orion and between 2.7 million and 3.9 million barrels of recoverable oil at Borealis. In 2011, BP President John Minge said I Pad would “result in drilling some 50 new wells to access about 80 million barrels of additional reserves.”

Because of this discrepancy in resource size, and because the reservoirs sit one atop the other, BP believes it is best to develop Borealis in conjunction with Orion. And because Orion is the more technically complex reservoir, it feels the need to defer both projects.

In its most recent development plans, BP proposed facility work needed to bring northwest Orion into production, but deferred development at northwest Borealis. The state called the Orion program a “significant step,” but said there was “no justification” for allowing BP to hold the tracts at Borealis without a plan for development.

As such, the state approved the entire eighth Orion plan of development through the end of 2013, but only partially approved the eleventh Borealis plan of development, rejecting the plans for the northwest portion. And the state “encouraged” BP to contract the northwest portion out of both participating areas until it is ready to begin development.

I Pad proposed in 2004

The western region of Prudhoe Bay first became a priority for the working interest owners of the field starting in the late 1980s, around a decade after the field came online.

After BP became sole operator of Prudhoe Bay in October 2000, it combined various interrelated efforts under way into the Prudhoe Bay West End Development Project.

The region produced from three pads at the time: W Pad, L Pad and V Pad.

The state approved the Borealis participating area in August 2002 to include numerous wells already drilled and producing from L Pad and V Pad. But in April 2004, BP requested an expansion, including initial discussions of the proposed I Pad to the north. BP proposed bringing I Pad online by 2006, drilling between five and 15 wells. In its fourth plan of development for Borealis, submitted October 2004, BP said it was already permitting I Pad and expected to drill appraisal wells in 2005. But when BP submitted its fifth plan of development in October 2005, the company did not address the I Pad area.

For that reason, the state rejected the plan as incomplete. But BP countered, claiming recent changes to the Economic Limit Factor — the dominant mechanism in the state oil production tax code at the time — jeopardized the economics of the I Pad project.

The state asked for more details. In January 2006, BP gave a technical presentation detailing plans to drill the I-100 well in the northwest portion in March 2006 and to develop the northwest portion of Borealis and Orion participating areas simultaneously. The explanation sufficed, and the state approved the fifth plan of development.

Economic Limit Factor

Over the same period of time, BP also pursued Orion development.

The state approved the Orion participating area in February 2004. In its initial plan of development, BP proposed a three-phase development plan, the final phase of which would include between 30-60 wells drilled from the proposed I Pad starting in 2006.

But in its second plan of development, submitted in October 2005, BP said I Pad was still being evaluated. The state rejected the plan as incomplete because BP failed to describe any development activities for the northwest portion of the participating area. As with Borealis, BP claimed changes to the Economic Limit Factor challenged the project.

The Economic Limit Factor lowered the tax rate for smaller fields, but in his January 2005 state of the state address then-Gov. Frank Murkowski said it “was never the intention of the Legislature which crafted revised ELF legislation in 1989 to have to reduce taxes close to zero in situations in which satellite fields are administered as one field with the Prudhoe Bay field.” He subsequently proposed to treat Prudhoe Bay satellites Borealis, Midnight Sun, Orion, Polaris, Point McIntyre, Aurora and the original Prudhoe Bay participating area “as one field for purposes of the economic limit factor.”

At Meet Alaska, shortly after the announcement, the heads of BP and ConocoPhillips said the decision forced them to defer the $600 million to $700 million Orion project, but in subsequent information given to the state over the following year, BP presented a “best case” schedule to drill the I-100 well in 2006 and bring I Pad into production by 2010.

Although the state questioned this delay, it ultimately approved the plan of development, but the state also told BP that its third plan of development should set out a firm timeline for I Pad construction and, if the timeline extended beyond 2007, an explanation for the delay. And the state asked for detailed results from the I-100 well drilling program. When BP next submitted plans of development in October 2006 — the sixth for Borealis and the third for Orion — it again delayed I Pad drilling until 2009, saying the still unthawed ice pad for I-100 prevented it from laying gravel until summer 2008.

The state approved both plans for another year.

According to the state, the I-100 well “confirmed 13 feet of reservoir quality sand in the Kuparuk C1 interval and identified an oil-down-to-depth of 6,634 feet.” A lateral off that well, the I-100PB, “confirmed net pay in the Schrader Bluff (Orion Reservoir) Nb-sand, OA-Sand and Oba-Sand,” but three other sands tested in the reservoir were unattractive.

ACES-related deferral

In October 2007, BP said engineering work had uncovered a “large subsurface ice lens” at the original I Pad location and the company said it was looking for a new location to the north. The state approved both plans — the seventh for Borealis and fourth for Orion.

Around the same time, Frank Paskvan, Prudhoe Bay western region subsurface development manager, told Petroleum News BP estimated an I Pad installation by 2011.

In early 2008, just a few months after the passage of a new production tax code called Alaska’s Clear and Equitable Share, BP said it had deferred around $1 billion from its Western Region Development Project, including its planned investment on I Pad.

In October 2008 — the eighth plan for Borealis and fifth for Orion — BP said it had completed engineering for the revised I Pad location and was focusing on how existing infrastructure would handle viscous oil in the region. The state approved both plans. HB 110 revival: 50 wells For the next two years — the ninth and tenth plans of development at Borealis and the sixth and seventh plans at Orion — BP said it had deferred I Pad operations. The state approved all four plans, but when BP deferred the project again in September 2011 — in its eleventh and eighth plans, respectively — the state rejected the plans as incomplete.

Earlier in the year, I Pad emerged as a crucial point of discussion in debates over House Bill 110, a revision to the existing oil production tax promoted by Gov. Sean Parnell.

In hearings in early 2011, BP Exploration (Alaska) CFO Claire Fitzpatrick said the bill could make the I Pad project economic, leading to some 50 new wells accessing about 80 million barrels of oil. After the Alaska Senate made clear it wouldn’t pass the changes before the end of the 2011 regular session, ConocoPhillips CEO Jim Mulva called for a better investment climate during an April 2011 speech before the Resource Development Council. Among the short-term investments ConocoPhillips might be able to make with lower taxes, Mulva pointed first and foremost to the $1.5 billion-2 billon I Pad project.

In December 2012, BP told the state the resources in the northwest portion of Borealis were minor compared those in the overlying Orion reservoir. BP wanted to defer Borealis development to proceed in conjunction with Orion, but also said technical challenges around viscous Orion oil production forced it to defer the I Pad project indefinitely.

The state and BP met numerous times in early 2012. Eventually, the state told BP the participating areas might contract if the company did not develop the northwest area.

By August, BP supplemented its eleventh and eighth plans of development, respectively.

For Borealis, BP included plans for the northwest region, but only in conjunction with other regional activities. The state ultimately approved the plan of development partially: blessing all the proposed activities except those outlined for the northwest portion.

For Orion, BP said it needed to address some challenges facing I Pad. Those included upgrading the Gathering Center 2 processing facility to handle viscous oil and studying an alternative for developing the viscous oil reservoir in the Schrader Bluff N Sand.

The alternative involved using electronic lift pumps instead of partial gas processing and gas lift. If successful, BP said, the alternative would reduce the scope of the project.

In its supplement to the eighth plan of development for Orion, BP committed to upgrade GC-2 to handle more solids and to continue studying options for the N-Sand reservoir.

Shell drilling in OCS

—Kay Cashman
Petroleum News

After six years of battling political and logistical obstacles, Shell is drilling top holes in the federal outer continental shelf of the Chukchi and Beaufort seas.

The top sections of wells, scheduled to be drilled this year, bring the drill bit down to depths of 1,400 to 1,500 feet, some distance above any hydrocarbon zones.

The idea is to save a significant amount of time in subsequent drilling seasons, Pete Slaiby, Shell’s vice president in Alaska, told Petroleum News Sept. 28.

In the Chukchi, three top holes are expected to be completed this year for Burger A, J and B wells.

In the Beaufort Sea, where a different drilling unit is being used, one top hole each is being drilled in the Sivulliq and Torpedo prospects.

Read more http://www.petroleumnews.com/pntruncate/946224547.shtml

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Monday, October 8, 2012

Senator McGuire Calls for “Thoughtfulness about Alaska’s Oil Wealth”


FOR IMMEDIATE RELEASE

ANCHORAGE- Senator Lesil McGuire, R-Anchorage, is asking Alaskans to take a moment to be thoughtful of how and why Alaska’s Permanent Fund was created. This past week hundreds of thousands of Alaskans received their $878 Permanent Fund Dividend through direct deposit and thousands more will receive their checks by mail in the upcoming weeks.

Continuing concerns; Southcentral utilities tell task force about latest gas supply situation

Alan Bailey
Petroleum News

Termed by some a “Cook Inlet renaissance,” the upsurge in exploration activity coupled with some new gas finds in Alaska’s Cook Inlet basin has perhaps led to a sense that what had appeared to be a growing crisis over utility gas supplies for Southcentral Alaska is turning instead into a new era of plentiful and cheap energy in the region.

Unfortunately, however, the region still faces potential gas supply shortfalls in the next few years, with the possibility of power cuts or worse, should the flow of gas from Cook Inlet gas fields fall short of peak gas demand, especially during the winter. That was the overriding message from a Sept. 26 meeting of the Anchorage Mayor’s Energy Task Force, in which some Southcentral utilities presented their analyses of the short- to medium-term gas supply and demand situation, as projections of available gas supplies show continuing declines.

Short of time

While expressing satisfaction with new, heightened levels of gas exploration and development in the Cook Inlet region, utility executives pointed out that the lead time involved in finding new resources, developing new fields and bringing new gas to market renders it highly unlikely that sufficient new gas will come online before currently dwindling supplies drop below demand levels. And so, while there may be reason for cautious optimism about the gas supply situation a few years into the future, the short- to medium-term situation is worrying and requires decisive action.

Consulting firm Petrotechnical Resources Alaska, or PRA, has been monitoring the Cook Inlet gas supply situation on behalf of several utilities. PRA has recently changed its prediction of when annual gas supplies are likely to fall short of demand from 2013 to 2014, with that shift in the forecast resulting from the drilling of new gas wells and the addition of new gas compressors to gas fields.

But that potential gas shortfall is just two years from now.

James Posey, general manager of Municipal Light & Power, or ML&P, told the task force that the usual timeline for developing a new field and bringing new gas online is anywhere from two to seven years, especially for the size of field required to have a major impact on the Cook Inlet gas supply decline curve.

“There is no one-year miracle for a large amount of gas,” Posey said. “There are no miracles out there within the two-year timeframe.”

Declining delivery


And Posey cautioned that as more and more wells are drilled into existing fields, to boost both gas production and the rate at which gas can be delivered, the production decline rates for new wells become progressively higher — it’s a bit like pushing an increasing number of straws into a deflating balloon.

Whereas production from most of the Cook Inlet gas fields is declining at a rate of 19 percent or more per year, production from new wells now typically declines at rates of between 25 and 30 percent, Posey said.

And then there’s the question of deliverability: the rate at which gas can be flowed from the fields, especially to meet peak utility gas demand on cold winter days.

Posey said that a recent gas compressor failure in the Beluga gas field had caused ML&P to request 2 million to 3 million cubic feet of gas from Cook Inlet Natural Gas Storage Alaska’s new gas storage facility on the Kenai Peninsula, to enable the power utility to meet its gas supply needs for a day.

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

Cook Inlet Natural Gas Storage Alaska, or CINGSA, brought its new gas storage facility online in April and since then has been filling the facility’s underground reservoir, in preparation for the coming winter.

Plan B

The utility executives said that they are working on “plan B,” a contingency plan to keep the lights and heating on in Anchorage and other Southcentral communities, should local gas supplies drop below needed levels. And, given the short timeframe available to put a contingency plan into place, the only feasible options seem to be the import of liquefied natural gas or compressed natural gas from elsewhere into the region, to supplement local gas resources. Should these two options fail to materialize, the only other possibility would appear to be a periodic switch over to the use of liquid fuels such as diesel, rather than gas, for power generation.

But liquid fuels have become increasingly expensive in recent years, as anyone in the habit of fueling a motor vehicle knows to their cost. Electricity generated using liquid fuels might be five times as expensive as natural gas fueled power, Lee Thibert, senior vice president of Chugach Electric Association, told the task force.

For some time the utilities have been investigating the possibility of importing liquefied natural gas, or LNG, into Southcentral Alaska, perhaps by converting the LNG export facility at Nikiski on the Kenai Peninsula into an import and regasification terminal. The utilities have been looking into LNG markets, pipeline transportation, shipping opportunities and the question of the optimum import point, including the Port of Anchorage, Kenai and Whittier, Thibert said. The concept of importing compressed natural gas, or CNG, has also gained some traction — this option would offer the advantage of the ability to purchase gas at relatively low prices on the U.S. West Coast.

“The problem is the transportation component is very expensive and, to do that, it’s a long term commitment,” Thibert said.

24 months

Thibert cautioned that the timeline to establish CNG or LNG imports “at the very best is 24 months,” while also adding that he couldn’t disclose any potential cost data, given the confidential nature of negotiations with potential suppliers. Given the short time window for establishing the supplies the utilities are not looking to the state for financial assistance, other than perhaps for the engineering for an LNG regasification facility, he said.

“We are at the point where we cannot wait for another legislative session for this to happen. We have to move forward,” Thibert said.

Brad Evans, CEO of Chugach Electric Association, said that Chugach Electric anticipates passing the cost of contingency gas on to its customers through the electricity rates, although the utility is a “bit skittish” about this, given past experience of recovering costs through rates. The utility’s balance sheet does not accommodate the millions of dollars that would be required for the out-of-state fuel supplies, he said. Evans also commented that the development of transportation routes presents the biggest hurdle in negotiations over the supply of LNG or CNG from out of state.

CINGSA role

During presentations from the utilities it became apparent that the new CINGSA storage facility now plays a pivotal role in Southcentral gas supplies, accepting gas produced during the summer and then delivering that gas during the winter, when gas demand is high, keeping winter gas supplies up to required levels at least for the time being.

Mark Slaughter, Enstar Natural Gas Co.’s manager of gas supply, told the task force that although the CINGSA facility has been accepting gas all summer, the facility still does not have as much gas stored as planned — CINGSA is working on that issue and anticipates continuing to build up its gas stockpile until the end of October. The goal is to obtain an additional 2.4 billion cubic feet of “base gas,” the gas used to maintain the facility’s reservoir pressure, Slaughter said, adding that CINGSA may have to pay more than originally planned for that gas. The rate of gas injection over the summer fluctuated quite widely, mainly because the storage facility has been competing for gas with the Nikiski LNG export facility, Slaughter said. In its original plans CINGSA had envisaged the LNG plant shutting down, but in the aftermath of the 2011 tsunami in Japan there has been a resurgence of LNG demand, enabling the LNG plant to continue to operate.

Enstar

Slaughter presented a graph of Enstar’s estimated gas deliverability for the coming winter and the winter of 2013-14, showing that gas demand on a peak possible winter day at temperatures around minus 20 F could only be accommodated by withdrawing gas from the CINGSA facility. And a graph of Enstar’s annual gas supply forecast shows a growing unmet gas supply need from the end of this year — in other words a shortfall in gas supplies that are needed but not currently available under firm contract. A Marathon gas supply contract ends on Dec. 31 and contracted gas supplies from Hilcorp Alaska LLC are set to drop after that same date. Slaughter emphasized that, although these contracted gas supplies drop out at the end of the year, the gas that is potentially available does not suddenly disappear: The problem is that the supplies are no longer guaranteed and the price of the gas is uncertain.

As a gas utility “that is not where we would like to be,” Slaughter said.

One complication in the gas supply contract situation is the Hilcorp purchase of Marathon’s Alaska assets — negotiations over that purchase are still in progress, thus making it difficult for Enstar to negotiate a new supply contract for gas that Marathon would produce, Slaughter said. If the company merger is delayed, there should be enough gas available but the gas will be sold in a spot market and prices will likely rise.

“It’s a free market and oil companies are very good at making profits,” Slaughter said.

On the other hand, Enstar feels encouraged by Hilcorp’s aggressive development plans in the Cook Inlet basin and the utility is building a new gas pipeline to Hilcorp’s Red Pad on the Kenai Peninsula, Slaughter said.

Chugach Electric


Thibert said that Chugach Electric has enough gas under contract to meet its needs until 2015, at which point it currently starts to see a growing shortfall in supplies under contract, despite a drop in demand in 2015 when it stops supplying power to Matanuska Electric Association, and despite an earlier drop in demand when a new highly efficient gas-fired power station in Anchorage comes online in the first quarter of 2013. Currently, none of Chugach Electric’s gas needs are under contract from 2017 onwards.

In the longer term, the utility is trying to diversify away from its high dependence on natural gas for power generation, and energy conservation has been playing a significant role in damping down electricity demand, Thibert said.

Posey said that ML&P is increasing its generation efficiency by participating with Chugach Electric in the new Anchorage power plant and by installing more efficient turbines in its existing plant. But, following the results of recent drilling, ML&P now anticipates the Beluga gas field, the utility’s main source of gas, to cease operating much sooner than the 2027 date originally anticipated, he said.

Matanuska Electric Association

Donald Zoerb, chief financial officer for Matanuska Electric Association, or MEA, said that MEA would not require gas until 2015, when the utility will stop obtaining power from Chugach Electric and start operating MEA’s new gas fired power station, currently under construction at Eklutna, north of Anchorage. The gas required for the Eklutna power plant represents a displacement of gas demand from Chugach Electric and is, therefore, not incremental to the existing gas load, Zoerb said.
“We are aggressively pursuing all credible options” for gas supplies for the new plant, which is also capable of using diesel fuel or heating oil, he said.

One point not discussed during the task force meeting is the possible impact on a power utility of Enstar experiencing a shortfall in gas deliverability during the winter, even if the power utility has all of its needed gas under contract. In that case the power utility would probably have to divert some of its gas supplies into Enstar’s system, to ensure the maintenance of adequate gas pressures in Enstar’s transmission and distribution pipelines. The consequence could be rolling power cuts in Southcentral.

http://www.petroleumnews.com/pntruncate/872912384.shtml





9th Circuit stops work at Port MacKenzie; 200 workers idled

Molly Dischner
Alaska Journal of Commerce

Work on the Port MacKenzie rail extension was stopped Oct. 1 by a panel of judges from the U.S. 9th Circuit Court of Appeals.

A 2-1 decision granted an emergency motion for stay until a review is completed of the Surface Transportation Board’s November 2011 order allowing the project to move forward.
The 32-mile rail extension would connect Houston and Port MacKenzie at a cost of about $272.5 million. Port MacKenzie is a deepwater port, with about 9,000 acres, or 14 square miles, of industrial staging and storage.

Alaska Survival, Cook Inletkeeper and the Sierra Club filed the petition for review in January, and the emergency motion for stay Sept. 21. The Surface Transportation Board, a federal regulatory body for railroads, and U.S. government are respondents in that case, and the Alaska Railroad Corp., Matanuska-Susitna Borough, and the State of Alaska are listed as respondent-intervenors.
According to the motion, the court finds a “serious question” regarding whether the Surface Transportation Board, or STB, complied with the National Environmental Policy Act, or NEPA, in determining the “purpose and need” of the project in the final environmental impact statement, or EIS.

The Oct ruling states: “The court further finds that the balance of hardships tips sharply in petitioners’ favor, that petitioners are likely to suffer irreparable harm in the absence of a stay, and that a stay is in the public interest.”

Oral argument for the case, which has now been expedited, is scheduled to begin Nov. 8 in San Francisco.

Mat-Su Borough Public Affairs Director Patty Sullivan said the stay likely means the borough can’t proceed with a bid that was out for work on a third segment of the project.
“We’re definitely disappointed,” Sullivan said.

Sullivan said the borough is considering an appeal of the stay, but could also wait and argue the full case in November.

Stopped work means a loss of about 200 jobs, about 70 on each of three different contracts. Those range from jobs out in the field, to associated office work. Work on three segments was planned for this fall: a section of rail at tidewater, one near the Parks Highway at Houston, and a segment running north from Ayrshire Avenue to just south of Papoose Twin Lakes.

In total, the project is supposed to create about 3,000 construction jobs and 4,000 mining jobs. The project was scheduled for completion in 2016, but Sullivan said she didn’t know exactly how the stay will affect the project’s timing. Some right of way and permitting work can continue despite the stopped of on-the-ground efforts.

The STB allowed the Alaska Railroad to construct and operate the rail extension from Port MacKenzie to Houston as long as it completed certain environmental mitigation measures and used the environmentally-preferable route.

On Sept. 10, the U.S. Army Corps of Engineers issued a permit authorizing the railroad to fill 95.8 acres of wetlands as part of its effort to create the rail extension.

Cook Inletkeeper Executive Director Bob Shavelson said the nonprofit is still considering appealing that decision as well. Much of the nonprofits’ concerns center around wetlands impacts.
The nonprofits contend that the STB decision allowing the project to move forward violated NEPA and the statutes authorizing that body to waive certain requirements for some projects.

The alleged NEPA violations were in the framing of the EIS for looking too heavily at the Railroad’s corporate objectives rather than a balance of corporate, governmental and public objectives, lack of evaluation of a project design without the road component, and an EIS that didn’t have enough ground-level studies.

Judges Stephen Reinhardt and Kim Wardlaw wrote the majority opinion, with Carlos Bea dissenting. Reinhardt was appointed to the court by President Jimmy Carter in 1979. Wardlaw was appointed by President Bill Clinton in 1995, and Bea joined the court in 2003, an appointee by President George W. Bush.

In his dissension, Bea said there is no “serious question” regarding NEPA compliance raised in the complaint, and that petitioners did not exhaust their ability to get a stay from the Surface Transportation Board, as is the usual protocol.

The majority opinion said a federal rule means that requesting a stay from the STB is not a prerequisite for the court to issue one, and that the petitioners demonstrated that a stay from the STB would have been “impracticable.”

Bea’s dissenting opinion counters that the petitioners did not submit evidence that getting a stay from the STB would have been “impracticable,” and had no grounds other than speculation.
Bea’s opinion also asserts that the STB did consider the alternatives preferred by the nonprofits that they say were not fully considered as part of the EIS process.

Shavelson said the stay bodes well for the November hearing.

Sullivan, however, said that because the stay was issued by just three judges, the case could still fare well when considered by the full court.

Molly Dischner can be reached at molly.dischner@alaskajournal.com.