Friday, November 30, 2012

Oil tax reform requires all stakeholder support

Deborah Brollini
Alaska Energy Dudes and Divas

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

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

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

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

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

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

Thursday, November 29, 2012

Utilities make first draw from gas storage

Tim Bradner
Alaska Journal of Commerce

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

LNG prices in Pacific markets are now trending downward.

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

ML&P improvements ongoing

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

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

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

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

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

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

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

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

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

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

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

New Chugach plant to fire up in 2013

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

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

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

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

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

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

Read more:

Tuesday, November 27, 2012

LNG project is linked to oil tax change, producers say

Tim Bradner Alaska Journal of Commerce

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Minge encouraged Alaskans to work together to break the divide:

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

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

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

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

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

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

Read more:

Friday, November 23, 2012

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

—Alan Bailey

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

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

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

Tightening supplies

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

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

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

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

Imports planned

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

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

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

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

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

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

Assessing options

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

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

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

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Wednesday, November 21, 2012

Gas line projected to generate thousands of in-state jobs

Elwood Brehmer
Alaska Journal of Commerce

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Elwood Brehmer can be reached at

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Tuesday, November 20, 2012

Investment: Keep your friends close …

Ann Lovejoy
Creative Intermedia LLC

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

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

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

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

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

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

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

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

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

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

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

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

And that’s how to do a deal.

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

Linc building snow road to Umiat, prepping for January drilling

—Eric Lidji

Work is under way at Umiat.

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

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

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

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

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

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

Four-well program

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

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

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

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

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

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

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

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

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

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

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

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

Read more:

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

Kristen Nelson
Petroleum News

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

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

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

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

CD-5 going ahead

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

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

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

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

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

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

Focus on light oil

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

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

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

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

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

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

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

It’s short-term

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

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

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

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

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

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

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

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

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

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

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

Elsewhere, he said, economic theory is used.

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

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

ACES and the gas line

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

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

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

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

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

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

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

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

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

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

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

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

Opportunities for Conoco

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

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

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

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

There are also opportunities south of Kuparuk, he said.

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

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

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

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

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

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

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

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

Read more:

Sunday, November 18, 2012

"Organizing" for Alaska

Deborah Brollini
Alaska Energy Dudes and Divas

So what do you do when you get everything that you ever wanted? No one prepares you for your dreams coming true. Ask Phillip Phillips when he won American Idol. Deborah when hearing “Home” on the radio after the election pulls off on a side of the road and cries. I got everything I wanted for my children. My hard work and the dreams for my children were realized on November 6, 2012.

What most folks do not know is that I played a role in the organizing of Alaska’s Senate, and that “organizing” has been strategic, and has been ongoing since the end of session. Senator Lesil McGuire reached out to me not only as a friend and constituent, but because of my outreach efforts and that I have the pulse of the public and rural Alaska. The Senate needed to represent all Alaska, and those in chairmanships needed to understand that this is not about rural vs. urban Alaska; we are all Alaskans. Alaskans can be proud of our state senate who will work for all Alaskans regardless of party.

I fought hard for Alaska in 2012, and the fight has always been about my children's future. Alaskans won big on November 6th, and we have so much to look forward to. Cheers

Friday, November 16, 2012

Enstar faces second winter shortage as supplies tighten

Tim Bradner
Alaska Journal of Commerce

Colleen Starring, president of Enstar Natural Gas Co., is on the spot this winter.

Her utility supplies natural gas to virtually all commercial buildings and most homes across Southcentral Alaska.

Starring’s problem is ensuring there’s enough gas to supply her customers. Enstar is short 4.2 billion cubic feet of about 33 billion cubic feet it needs to keep the heat on.

This is the second year Enstar has faced a deficit in gas supplies at the start of winter, but last year the gap was only about a billion cubic feet and most of that was made up through a short-term auction system the utility set up for producers to sell small quantities of surplus gas they may have.

The 4.2 billion cubic foot gap this year, however, is too big to make up through the auction system.

Things may yet work out.

A Consent Decree just negotiated by the state with Hilcorp Energy on its pending acquisition of Marathon Oil Co.’s Cook Inlet assets could clear the way toward sales of more gas from the Marathon fields to the region’s utilities.

Alternatively, if ConocoPhillips decides not to ship more cargos of liquefied natural gas from its Kenai LNG plant in 2013, and decides not to renew an export license for the plant that expires next March, the company could make more gas available.

Hilcorp and ConocoPhillips are already major gas suppliers to the region’s utilities.

However, at the root of the problem is declining production from gas fields Southcentral Alaska. For example, the Beluga gas field, long a main supplier of gas to the utilities, is declining at rates of 17 percent to 19 percent per year, said Jim Posey, general manager of Anchorage’s city-owned Municipal Light and Power.

ML&P owns one third of the Beluga field.

By 2014 or 2015, production from fields in the region will fall below annual demand, requiring that gas be imported either as LNG or compressed natural gas. Explorers are busy in the area but it’s considered unlikely that enough new gas can be found and put into production quick enough, said Tom Walsh, managing partner of Petrotechnical Resources of Alaska, or PRA, a consulting firm hired by the utilities to study the gas situation.

On the positive side, there’s a new gas storage facility operating on the Kenai Peninsula that now has gas in storage for peak cold weather demand this winter. The first withdrawals of gas from the Cook Inlet Natural Gas Storage Alaska project have already been made, Enstar spokesman John Sims said.

Beluga budget dispute

But another twist for now, however, is a disagreement among the Beluga field owners about funding a $50 million budget for servicing and other work on producing wells in the field.

ConocoPhillips, Hilcorp and ML&P each own one-third of the Beluga field with ConocoPhillips as the field operator.

Posey, of ML&P, said Hilcorp has declined to fund its full one-third share of the budget.

Hilcorp spokeswoman Lori Nelson confirmed this.

“We certainly recognize the need for enhanced production. Hilcorp did reject the $50 million proposed budget,” Nelson said. “We have a long and successful record with this kind of work and believe it can be done for a smaller price tag.”

Posey doesn’t buy that.

“When they decide to pull in their horns (on spending) it means less gas supply,” he said.

He said he’ll take up the matter with his boss, Anchorage Mayor Dan Sullivan, and the issue may also be appealed to Houston, where Hilcorp and ConocoPhillips are headquartered, Posey said.

Walsh, of PRA, is fairly pessimistic, however.

In terms of the supply gaps, Walsh told the Regulatory Commission of Alaska in an Oct. 24 briefing that, “we don’t believe there is a lot of uncontracted gas (reserves) out there. There’s just not enough drilling. There’s not enough new gas coming into the system,”

Cook Inlet producers’ own information on the extent of their reserves is the best data there is, and while some of this must be shared with the state Division of Oil and Gas, state officials are required to keep it confidential.

Information, supply gaps remain

The lack of having this information available to the utilities, and the public, is a sore point with Chugach Electric CEO Brad Evans, who has pushed unsuccessfully for the state to do a regional Cook Inlet resource plan putting all information into one place.

Walsh said the companies will drill to meet contract commitments, and the fact that there are large gaps in contracted supplies for 2013 and the years following probably means the companies don’t believe there is a lot of untapped gas, or that gas that is there can be profitably produced at least at present prices.

PRA has estimated that the number of new production wells being drilled would have to double for new reserve additions to make up for the annual depletion of the fields, and the increased drilling isn’t happening.

Also, some of the new wells being drilled are not successful. Of three production wells drilled in the Beluga field in 2012 one is not producing as expected.

There is a great deal of exploration planned for Cook Inlet, and although most of it is aimed at oil, some gas will inevitably be found too.

“It’s great to see this, and it’s all due to the state exploration incentives,” Walsh said. “There has been virtually no exploration in Cook Inlet in 40 to 50 years.”

But few, if any, of the explorers will be able to develop their discoveries in time to meet the utilities’ shortfall.

“Their timeline will not resolve this issue,” he said.

As for the needed work in the existing fields, Walsh said, “we are not seeing the kind of activity we need, and based on recent history we don’t expect it to occur.”

Bob Pickett, one of the commissioners of the state regulatory commission, thinks the situation is precarious.

“We’re in a conundrum. We’ve moving out of an era with the ‘legacy’ (older) fields where there was a lot of gas and prices were low. Today Cook Inlet has the nation’s highest gas prices. Now, with discussions of gas imports, we could see those prices double,” Pickett said.

The possibilities of mechanical and geologic failures must also be considered, Walsh said. Mechanical failures could include the malfunctioning of gas field compressors, as has happened, which would impair the flow of gas to utilities — not good if it happens during cold weather — or there could be geologic failure, such as disappointments in drilling or encroachment of water into the gas producing wells.

Enstar’s Starring said her gas utility can’t switch fuels, unlike the electric utilities who can do it to some extent. Enstar’s customers also can’t conserve on heating enough to make a significant difference.

“There are only so many sweaters you can put on,” she said. “Our only option is to go to curtailment (of supply). We have a curtailment plan and we are awaiting an opportunity to present this,” to the regulatory commission.

Starring said a new system Enstar initiated to allow producers to bid small quantities of gas they may have to meet Enstar’s short-term peak requirements worked well last winter.

Enstar spokesman John Sims said the amounts of gas bid under this system for 2012 were about 700 million cubic feet. While this mechanism works well to meet short-term needs during periods of peak demand it will not supply large volumes of gas.

“The gas simply isn’t available,” Sims said.

Alternative power

Chugach Electric Association is in better shape than Enstar in that it has other alternatives than natural gas, such as hydro for a long-term base, wind power as a supplement and, in an emergency, bringing power down from Fairbanks over the Intertie.

Chugach now uses about 25 billion cubic feet per year of gas, and after Homer Electric Association and Matanuska Electric Association stop buying wholesale power from Chugach, the utility’s annual need for gas will drop to about 9.5 billion cubic feet per year, Lee Thibert, Chugach’s senior vice president for planning, told the regulatory commission.

More efficient gas turbines and “combined cycle” (using waste heat) facilities at the new Southcentral Power Plant now under construction in south Anchorage will result in an expected savings of 3 billion cubic feet of gas yearly.

Wind power will help, too. The new Fire Island wind project will allow Chugach to reduce its annual gas need to just under one-half a billion cubic feet. Additional hydro power in the regional grid is also important.

Hydro power from Bradley Lake near Homer is now the least expensive source of power along the Railbelt and additions to its capacity are planned.

Consumer conservation is already playing a role: Consumers are using new, more efficient appliances and lighting systems and the savings in electrical use have translated to an estimated 700,000 thousand cubic feet, or mcf, of gas saved over the last 10 years, a trend which is expected to continue.

Despite these developments, Chugach faces its own gas supply shortfall of about 3 billion cubic feet in 2015 and 6 billion cubic feet in 2016, Thibert told the RCA.

Matanuska Electric Association will be generating its own electricity in 2015 at a new power plant being built at Eklutna, north of Anchorage, MEA’s general manager, Joe Griffith, told the regulatory commission.

The project is under construction now and is ahead of schedule and under budget so far, Griffth said. The plant is to be in operation in January 2015.

MEA has yet to contract for a long-term supply of gas, however, although talks are under way with producers, Griffith said. The plant will need about 5 to 6 billion cubic feet of gas per year when when operating, he said.

Anchorage’s city-owned Municipal Light and Power has agreed to make gas available initially to test the Wartsila engines in the plant, but this supply is only temporary, Griffith said.

However, the Wartsila engines do have dual-fuel capabilities, so MEA could also generate power with diesel if need be, Griffith said. The engines can make the transition seamlessly, he said.

A four-day supply of diesel will be kept on site, and additional fuel can be efficiently brought in by rail if needed. MEA is also investigating the possibility that a propane-air mixture can also be used as fuel, giving the co-op another option for a backup, Griffith said.

Some improvements in the region’s pipeline network are also needed to move more natural gas efficiently to the northern end of the system, Griffith told the RCA. The conversion of two cross-Cook Inlet pipelines, the Cook Inlet Gas Gathering System, or CIGGS, to a two-way flow instead of one-way will ease this, but it may not be the total answer, Griffith said.

Griffith said any discovery of new gas will take time to bring into production. Griffith said his concern is for the next two to three years.

“Getting through the next two to three years will require us to do something heroic,” he told the commission.

Anchorage’s Municipal Light and Power now relies mainly on its one-third share of gas production from the Beluga field for its supply of gas, although ML&P also shares in hydro power as do other regional electric utilities.

However, gas production from Beluga is declining and by 2015 ML&P will need to purchase gas from other sources, its general manager, Jim Posey, told the regulatory commission.

ML&P will need about 3.6 billion cubic feet in 2015 and about 5 billion cubic feet in 2016, Posey said. After 2016 its requirement for new gas may decrease because of the efficiency of the new power plant being built with Chugach Electric, and other improvements in the ML&P system.

Posey said there can be some benefits from energy conservation but there are limits to this for many ML&P customers, who are mainly owners of large commercial buildings in the downtown core of Anchorage.

Still, Posey said ML&P has seen 40 percent reductions of electricity use by homeowners through conservation, and he singled out one large Anchorage building, the Performing Arts Center, which achieved a 20 percent reduction several years ago after a series of efficiency measures.

Read more:

Schlumberger’s Alaska history dates back to first oil well

Tim Bradner
Alaska Journal of Commerce

Schlumberger Alaska Manager Lees Rodionov, at her Anchorage office. Schlumberger has about 850 employees in Alaska and 115,000 worldwide.

Schlumberger, the oilfield service company, is so embedded in the history of the petroleum industry that its proper pronunciation should be on the entry quiz for new oil workers.

If it’s pronounced properly (hint: founders Conrad and Marcel Schlumberger were French) the new employee passes the test. If it’s said improperly (hint: like a hamburger) the boss points the way to the door.

Schlumberger has been in Alaska since 1956. When Richfield Oil drilled its Swanson River discovery well in 1957 — the well that laid the foundation for Alaska statehood — Schlumberger was there doing the well logging.

Fast-forward half-a-century plus five years. A lot has happened in the state, and Schlumberger is still here, logging wells and lot more.

If the oil and gas fields are ever depleted, all the prospects explored and the industry is packing up, Schlumberger will still be here, helping abandon old wells.

That will never happen, of course, because old oil fields continually reinvent themselves — Schlumberger helps with that, too — and creative and entrepreneurial geologists and engineers always find new ways to squeeze more oil and gas out of rocks.

Schlumberger is involved in that, too.

What the company does is use technology to help the oil explorers or producers find out where the petroleum is, figure out how much of it there is, and get it out of the ground.

Schlumberger started in France in the 1920s but is now an international firm, with 115,000 employees worldwide. Schlumberger works most places in the world where there’s oil and gas being produced or looked for. The total now is 85 countries.

In Alaska, the company has at least one of its 17 service and product lines engaged with every major oil producer and every explorer as well, says Schlumberger’s Alaska Manager Lees Rodionov.

Services the company provides, which are vital to the industry, include the “logging” or the mapping of subsurface reservoir intervals using special tools, to providing drilling fluids to control the well during the drilling process and cementing the well casing (the steel tubulars of the well) that make the well stable and safe.

There’s a wide range of other services including work done before a well is drilled (the analysis of geologic information), the measurements of fluid movement during production, to help the operator produce the well most efficiently, work related to remediation of old wells, and much more.

Much of the work is at the leading edge of oil industry technology. For example, Schlumberger helped develop techniques to conduct tests and measurements in the hole while drilling is still under way, a technique called “logging-while-drilling” or LWD. This was a great leap forward for the petroleum industry because it meant logging could be done without having to stop drilling and pull all the drill pipe up out of the hole, a process that takes time and costs money.

LWD not only avoids that but allows for immediate changes in the drilling plan with the equipment still in the hole, which guides the drillers with more precision to the desired spot deep underground. Other products and services that Schlumberger provides during the drilling process include bits, various drilling tools and mudlogging.

Another technology the company helped pioneer and now operates in Alaska is coiled-tubing services, mobile equipment with huge metal coils that are lowered down wells to do repair work, or even used in drilling.

For many types of jobs, using coiled-tubing units is much more economical than using a drill rig. Anything that lowers the costs of drilling and completing wells makes it possible to reach and produce smaller oil pockets that were previously uneconomic. Another technology aimed at accessing bypassed hydrocarbons is Schlumberger’s LIVE Digital Slickline service in which traditional slickline has been coated with a proprietary material and allows for digital two-way communication without being affected by well completions, conditions or fluids.

A “slickline” operation involves a thin cable passing through pressure control equipment, allowing work to be done safely on live oil and gas wells.

(Editor’s note: Schlumberger maintains a widely-used oilfield glossary on its website, at

The company is now at the forefront in developing automated drilling technologies, which allows work to be done with fewer people on the rig. This not only lowers costs, but with less people working around machinery, it improves safety too.

Schlumberger now has nine locations in the state including two in Anchorage, four on the North Slope and three on the Kenai Peninsula. There are about 850 Schlumberger employees in Alaska, 75 percent of them are Alaska residents and a lot of them were recruited in the state, Rodionov said.

“Our corporate strategy is to recruit where we work. We want to be part of the community,” she said.

Schlumberger recruiters pay close attention to the University of Alaska Fairbanks and University of Alaska Anchorage.

“We’re a technology company so we focus our recruitment on the engineering and science disciplines, such as petroleum engineering and other geosciences. We’re interested in any graduate with a technical degree, however,” including fields like computer science and math, Rodionov said.

Business is growing for Schlumberger in Alaska, and that means the company is hiring, and hiring Alaskans. Two hundred employees have been added to the Alaska workforce in the last two years, Rodionov said.

What’s driving the growth is the expanding activity by explorers, many of them small to mid-size independents.

Schlumberger invested $30 million in its Alaska operations in 2012, including a new building on the Slope to consolidate drilling support functions, which will completed in 2013.

The company plans a $50 million investment next year, focusing on bringing new technology to the state and new facilities in Kenai to support the growth there.

“We saw rig activity up 15 percent to 20 percent this year over last, and expect to see similar growth in 2013,” Rodionov said.

That’s good news for Schlumberger, because where there are rigs drilling there is demand for the company’s services.

Read more:

Republished with the permission from the Alaska Journal of Commerce

Thursday, November 15, 2012

Faster horses

Ann Lovejoy
Creative Intermedia

Have you been trapped in a puzzling conversation with someone who believes that innovation is some kind of mystical event unlike real life?

The simple truth is
  • Invention or inspiration is not innovation
  • Innovation is the process that connects inventions in product, process, or services to a public (market) which finds them useful.
And, like any other process – the innovation process can be reproduced with consistent results.

Trust me on this one; using a process is how Thomas Edison’s Invention Factory brought hundreds of inventions to market. Invention Factory products were often not the best or most elegant ideas. But new products were released feasibly, reliably, timely and cost-effectively on a large-scale basis.

Henry Ford once said if he’d asked his customers what they wanted, they would have said, “Faster horses.” Cars had been invented and were in production already. The Model A was not the invention or innovation. Henry Ford’s process innovation adapted meat butchering processes – assembly lines – to building machines. The machines connected to a broader market because the assembly line enabled consistent reproduction of high value products, with an affordable price for customers.

The reproducible innovation cycle can be applied to any human endeavor – even government and society. The steps are:

  • Find the opportunity (identify and define the goals, problem, desire)
  • Connect the definition or problem statement to solutions
  • Select the solution (prioritize the possible solutions to the one most feasible, actionable, sustainable, manageable)
  • Make the solution best-fit (optimized, user friendly, flexible)
  • Bring the solution to the public (implement the solution and stabilize the change)
  • Improve continuously – adapt to changes in the environment, renew and fine-tune

The Alaskan economy is not terribly diverse. We are overly dependent on one industry – oil and gas. The key symptom or measure of this dependency is that most of the state budget comes from oil taxes. Our usual lower-tax-election-drama misses a key economic factor for growth and for sustained economic welfare of citizens. If state revenue came from a diversity of sources – we’d have alternative means to fund incentives. We’d be able to invest and participate in profit-making ventures. This model has been shown to work, for example with Norway and Statoil and in top-tier corporations.

On a philosophical level – the tax-debate is a scarcity mentality and the other stance is an abundance mentality. An abundance mentality reduces waste, increases profit and improves outcomes because knowledge and resources are freely shared.

Why shouldn’t individuals and industries contribute revenue to enable diversity of private and public investment? Diversified revenue generation and investment works best when individuals and industries receive benefits and services in return, and openly acknowledge the exchange.

High-performing corporations use transparent accounting of costs and benefits. Why shouldn’t these proven best practices and measurements be expected -- and demanded -- of our other human institutions?

Not acknowledging the exchange means we don’t measure and hold the right people accountable for results that demonstrate value. What gets measured, gets done. I don’t know about you – I personally like riding horses . However, there are better ways to transport Alaska into the future.

Ann L. Lovejoy is performance consultant who helps organizations be better to do better. She is experienced in operations management, project management, process design and control, measurement systems design for high performance, workforce and leadership talent development, and transformational change. Ann L. Lovejoy lives in Anchorage and may be reached at

Tuesday, November 13, 2012

AIDEA may finance infrastructure at Mustang

Tim Bradner
Alaska Journal of Commerce

The Alaska Industrial Development and Export Authority, the state development corporation, is working on a plan to finance production infrastructure for a small North Slope oil field being developed by Brooks Range Petroleum LLC, an Alaska-based independent company.

It is the first time the state authority has invested directly in oil production support infrastructure, although AIDEA has long invested in infrastructure for mining.

Brooks Range is developing its 44-million-barrel Mustang discovery west of the Kuparuk River field and hopes to have the field in production in early 2014, company COO Bart Armfield said.

The company is jointly owned by Alaska Venture Capital Group, a consortium of U.S. independents, and Ramshorn Investments Inc., a subsidiary of Nabors Industries.

Brooks Range has worked out an agreement with AIDEA to finance and own a 4.1-mile gravel access road and gravel pad for production facilities.

AIDEA’s board has approved initial steps in the financing, which is to be for $20 million. The board will give a final approval to the project at its December meeting, according to Karsten Rodvik, spokesman for the authority.

The road and pad would be built this winter and be ready for construction of field facilities in late 2013 and early 2014, Armfield said.

The plan is for AIDEA to own the road and pad and charge Brooks Range, or other companies working in the area, fees to use the facilities.

The state authority now owns and operates infrastructure that supports mining, such as a port on the Chukchi Sea and a 57-mile access road to the Red Dog lead-zinc mine in northwest Alaska, but this is the first time the state will have invested in oil industry production infrastructure.

AIDEA also owns an ore terminal and loading facility in Sakgway that is used by mining companies shipping ore from Yukon Territory.

In the oil sector, the authority has also invested in a jack-up rig that is now in Cook Inlet, in southcentral Alaska. AIDEA invested 30 million of an $80 million project to purchase and refurbish the Endeavour jack-up rig in a partnership with Buccaneer Energy of Australia and Ezion Holdings of Singapore.

Armfield said a second phase of the Mustang development being discussed with AIDEA that would have the authority finance and own a proposed $180 million oil processing facility that would process oil from the field. Capital expenditures for the total project are estimated at $550 million.

If the project goes ahead, AIDEA’s rules would require it to make the facility available to other companies exploring in the area. Repsol, for example, is now drilling exploration wells nearby. Brooks Range itself will be drilling a delineation well further west this winter to test a discovery made in 2008 at its Tofkat well, Armfield said.

Mustang would produce an estimated 15,000 barrels per day at peak and is located near the existing Alpine pipeline, a common carrier crude oil pipeline. That is convenient for any companies using the proposed plant to process produced oil.

Access by independent explorers to processing facilities has been a major problem on the North Slope for companies. Most of the existing production plants and industry infrastructure on the North Slope is in the large producing fields and gaining access to the facilities has required lengthy and complex negotiations.

This was a particular problem for Pioneer Oil and Gas when it developed its Ooogururuk field near the large Kuparuk field, Pioneer has said previously. ConocoPhillips, operator of the Kuparuk field, has said that making facilities available for third parties makes sense in some cases but it must be gone without causing complications for operations of the plants.

Another company new to the slope, Eni Oil and Gas, opted to build its own small processing facility for Nikaitchuq, another small field, to avoid having to work with owners of the major fields even though spare capacity was available in processing plants in the large fields.

Having AIDEA own a plant and make it available will be a help to independent explorers, particularly small ones. Armfield said that the plant will be designed to be expanded in modular increments.

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GOP takes majority in Senate, ensuring shakeup in 2013

Tim Bradner
Alaska Journal of Commerce

Incumbent Alaska State Senator Hollis French, a Democrat, enjoys good early returns with friend Susan Ridle Nov. 6 in Anchorage. French was holding a 249-vote lead over opponent Bob Bell with all 15 West Anchorage precincts reporting but with absentee ballots still to be counted.

Incumbent Alaska State Senator Hollis French, a Democrat, enjoys good early returns with friend Susan Ridle Nov. 6 in Anchorage. French was holding a 249-vote lead over opponent Bob Bell with all 15 West Anchorage precincts reporting but with absentee ballots still to be counted.

Republicans gained in the state Senate Nov. 6 but whether the margin is enough to ensure solid Republican control, and not a coalition-type organization of its leaders, remains unclear.

The current Senate has a 10-10 split among Republicans and Democrats, and while a Republican was Senate President, Kodiak’s Sen. Gary Stevens, Democrats held many key leadership posts.

It was enough for the Senate to block a controversial change in the state’s oil and gas tax laws in 2011 and 2012.

If current vote tallies hold, the GOP will control 13 seats and the Democrats seven when the next legislative session begins in January.

The oil tax issue will be back before the Legislature in 2013 but many members of the previous coalition in leadership positions survived the election.

Two who did not were two Fairbanks Democrats, Sen. Joe Paskvan and Sen. Joe Thomas. In a bitter and hard-fought race, Paskvan was defeated in his core Fairbanks district by his Republican opponent, Pete Kelly, a former state senator. Thomas had to run in a new district against Republican John Coghill, who defeated him by a hefty margin.

Click Bishop, the former state labor commissioner, easily won his seat in Senate District C as a Republican, defeating his Democratic challenger Anne Sudkamp 71 percent to 29 percent.

For the first time in many years Fairbanks will have no Democratic state senators, although the western part of the Interior city, changed in the 2012 redistricting, is now represented by Sen. Lyman Hoffman of Bethel, a Democrat.

In two hard-fought Anchorage state Senate races, Sen. Hollis French, the Democrat in District J, appears to have narrowly defeated Republican challenger Bob Bell with an edge of just 249 votes among nearly 13,000 ballots. French was a prominent member of the Senate coalition and a strong opponent of proposed oil tax changes.

Another opponent of oil tax changes also survived in Anchorage. Democrat Bill Wielechowski beat back a challenge by Republican Bob Roses, gaining 59 percent of the vote in District G compared with 41 percent netted by Roses. The oil tax issue figured prominently in both of the hotly contested Anchorage races, but French and Wielechowski had substantially more funds available because of heavy contributions to Democrats by organized labor.

In other Anchorage Senate races the outcomes were generally expected, state Rep. Anna Fairclough, a Republican, won handily over Democratic incumbent Sen. Bettye Davis, 60 percent to 40 percent, a result that was generally expected because of changes in the senate district M that favored the Republican.

State Rep. Berta Gardner, a Democrat, won easily over Republican Don Smith, 60 percent to 40 percent, in Anchorage Senate District H. Republican incumbent Sen. Lesil McGuire won reelection easily in Senate District K, beating Democrat Roselynn Cacy 67 percent to 33 percent. Sen. Kevin Meyer, an Anchorage Republican, was easily reelected in Senate District L, defeating Democrat Jacob Hale 73 percent to 27 percent.

As expected, incumbent Democratic Sen. Johnny Ellis easily won reelection in downtown Anchorage senate district I, with 67 percent of the vote over Republican challenger Paul Kendall.

Incumbent Republican Sen. Fred Dyson also cruised to reelection in Senate district F, mainly in the Eagle River/Chugiak area north of Anchorage, defeating Democrat Martin Lindeke, 76 percent to 24 percent. Similarly, incumbent Republican Sen. Charlie Huggins easily beat Democrat Susan Herman in Senate district E, 77 percent to 23 percent.

In the Matanuska-Susitna Borough, Republican Mike Dunleavy was unopposed, as was Peter Micciche on the Kenai Peninsula, a Republican running in Senate district O. Both are newcomers to the Senate. In Senate District N, covering parts of Anchorage and now parts of the Kenai Peninsula, incumbent Sen. Cathy Giessel won reelection, defeating challenger Ron Devon, who was unaffiliated with a party, 57 percent to 43 percent. Organized labor had contributed heavily to Devon.

In Senate District R, incumbent Republican Sen. Gary Stevens easily won reelection over challenger Robert Heinrichs, the Democrat, 69 percent to 31 percent. Incumbent Sen. Lyman Hoffman, a Democrat, was unopposed in Senate District S, encompassing the Yukon-Kuskokwim region and, after redistricting this year, west Fairbanks. In Senate District T, western and northern Alaska, incumbent Democratic Sen. Donny Olson easily won reelection over Republican challenger Al Minish, 77 percent to 23 percent.

In Southeast Alaska, in an outcome that was expected, Republican Sen. Bert Stedman defeated Sen. Al Kookesh, the Democratic candidate, in Senate District Q, which had been reformed by the 2012 redistricting to include two separate senate districts represented by both senators.

The Stedman-Kookesh race in Southeast and the Coghill-Thomas race in the Interior were the only instances where incumbent senators were matched against each other in new districts.

Sen. Dennis Egan, Democrat of Juneau, was the only senator who did not have to stand for election in the 2012 redistricting.

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Thursday, November 8, 2012

BLM nets $898,000 in its annual NPR-A lease sale

Tim Bradner
Alaska Journal of Commerce

The U.S. Bureau of Land Management received 14 bids on 160,080 acres of federal oil and gas leases in the National Petroleum Reserve–Alaska in a lease sale held Nov. 7.

Cash bonus bids totaled $898,900 from two companies, said Ted Murphy, associate state director for the BLM. The agency is responsible for management of the reserve. A state lease sale netted $14.2 million earlier in the day.

Twelve of the bids were submitted by Alaska independent NordAq Energy for tracts in the central part of the petroleum reserve. The other two bids were from Houston-based independent Woodstone Resources in the northeast part of NPR-A.

In a state of Alaska lease sale held earlier Wednesday NordAq acquired 60,000 acres of offshore state leases in Smith Bay, just north of the NPR-A.

Company president Bob Warthen said his company is working on an integrated exploration program for the Smith Bay acreage and the company's onshore federal leases in the

reserve with a target for drilling in 2014.

The Smith Bay state leases are in shallow water. NordAq would build an artificial ice island to support the drilling, Warthen said.

BLM typically holds its annual NPR-A sale orn the same day as the state's North Slope areawide sale, Murphy said. This year the state sale was also help Nov. 7.

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State deal with Hilcorp will cap gas prices, limit sales for LNG

Tim Bradner
Alaska Journal of Commerce

Cook Inlet gas producer Hilcorp Energy LLC has agreed to terms of a consent decree that will cap the price of gas sold to utilities and industrial customers for five years and not allow gas to be sold into LNG export markets until local utility needs are met, a state attorney said Thursday.

The consent decree, if agreed to by an Alaska Superior Court, will clear the way for Hilcorp to complete its acquisition of Marathon’s Alaska assets, most likely in early January.

Assistant State Attorney Ed Sniffen said the decree applies only to Hilcorp and not to Marathon. Even though the decree is not yet in effect, Hilcorp agreed Wednesday to abide by its terms between now and the time it is approved, Sniffen said.

The U.S. Federal Trade Commission meanwhile agreed to drop its own investigation of the Marathon-Hilcorp sale and has deferred to the state of Alaska and the pending consent decree, the FTC said in an announcement Wednesday.

The parallel federal and state investigations have been under way for most of 2012. Sniffen said the state of Alaska is are concerned because Marathon and Hilcorp today produce about 70 percent of the Cook Inlet gas sold to regional utilities, and having that much production controlled by one company could put utilities at a disadvantage in negotiations.

Terms of the proposed decree will be made public when notices are published, probably early next week. The court will take comments from the public and interested parties for 60 days. Following that, a state Superior Court hearing will be held and a decision made on the consent decree he said. Final resolution of the matter will likely come in January, clearing the way for the Marathon asset sale, Hilcorp spokeswoman Lori Nelson said. Marathon disclosed last month to investors that the Cook Inlet assets were sold to Hilcorp for $375 million.

Sniffen said the deal freeze gas prices sold by Hilcorp to utility and industrial customers at prices existing when the decree is official, likey in January, but those prices are expected to be similar to the average price of Cook Inlet gas today, about $6.52 per mcf, Sniffen said.

The deal has an escalator allowing a 4 percent annual increase, he said, and this would likely result in an allowable price of about $7.72 per mcf at the end of five-year period in 2017, he said.

“This was a very difficult balancing act for us because we want to protect the local consumers and at the same time give Hilcorp enough of a price incentive to explore for gas,” Sniffen said.

The provision prohibiting Hilcorp from selling gas for export as LNG until local utility needs are met also applies to sales to companies “who intend to resell the gas for LNG export,” Sniffen said. This issue may be moot if ConocoPhillips, which owns and LNG plant near Kenai, south of Anchorage, fails to renew the LNG export license for the plant that is due to expire next March. Sniffen said the state has not been informed by ConocoPhillips of any plans to apply for a renewal, but if an application is made it would likely come in January, he said.

There is increasing sensitivity to the Cook Inlet gas supply situation because existing fields are declining in production and local utility demand is expected to exceed annual production by the 2014-15 winter, requiring gas to be imported as LNG or compressed natural gas, utility officials told the state regulatory commission in a recent briefing.

Several companies are exploring for oil and gas in Cook Inlet but no major discoveries have been made yet. Even if they are it is unlikely they can be put into production in time to meet the projected 2014-15 shortfall.

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