Sunday, June 23, 2013

Oil Patch Insider: Is price of North Slope gas going up? Depends on how you measure

—Eric Lidji

A line in a Fairbanks Natural Gas regulatory filing caught the eye of Petroleum News.

While questioning the ability of a competitor to secure a natural gas supply contract from the North Slope producers, Fairbanks Natural Gas told the Regulatory Commission of Alaska: “The price of North Slope gas has increased substantially in the last few years.”

If North Slope natural gas is stranded, how can it have a price?

And if does have a price, is it “substantially” increasing? And if so, why?

The answer to the first question is simple: stranded gas is still useful gas.

The natural gas on the North Slope may be stuck on the North Slope, but a small portion of it is needed for field operations, utility needs and fuel for pipeline pump stations.

“If gas use takes place off the lease or production unit boundary then the gas will generally have been sold to the user,” University of Alaska Fairbanks and former state economist Antony Scott wrote in a report on natural gas prices earlier this year.

While some of these sales are between affiliated companies, some are considered “arm’s length” and give some sense of the “going rate” for natural gas on the North Slope.

Which leads to the second and third questions.

The contracts with the most publically available information are those between the distribution utility Norgasco and its two major suppliers: ConocoPhillips and BP.

Although the two contracts use slightly different formulas to determine their price, both use the delivered price of Alaska North Slope crude oil as a starting point (specifically the monthly oil price of the prior year, as reported by Platts.) Considering that the price of oil has generally been rising “in the last few years,” the price of gas in those contracts should be rising, too. According to Scott, each $10 change in North Slope oil prices increases gas prices in the contracts by about 44 cents and 46 cents, respectively.

Which means Fairbanks Natural Gas would be correct.

But the Norgasco contracts with ConocoPhillips and BP cover a period from 2012 to 2020, which means they don’t include “the last few years.” And while the price of oil has risen considerably since its lows during the recession, it has been stable recently, and even dropped occasionally, which means pieces may have risen, but not “substantially.”

A longer view

So perhaps the Fairbanks Natural Gas observation refers to contracts.

Way back in 1989, Norgasco bought gas from Exxon Corp. at a flat rate of $1.62 per thousand cubic feet, or about $3.04 per mcf today, when adjusted for inflation.

The ConocoPhillips and BP contracts each include a floor price of $2.50 per million Btu, but with oil prices at $110 per barrel the formula put the current price at roughly $5.10 and $4.85 per million Btu, respectively. So in that sense, the Fairbanks Natural Gas observation is correct: Because of the switch from flat pricing to indexed pricing, the price of North Slope natural gas has “increased substantially in the last few years.”

Of course, while the ConocoPhillips and BP contracts are similar, they are not identical, and the differences are telling. Specifically, the BP contract includes a multiplier making its price slightly less than the price ConocoPhillips is charging. Seeing as how the BP contract came second, one could say the price of North Slope gas is actually going down.

To summarize: Because North Slope gas prices were once fixed, but are now indexed to oil prices, they have increased in the past decade. But because North Slope oil prices have been relatively stable, North Slope gas prices have been, too. And because each new contract responds to the state of the market created by all the other contracts currently in effect, the available data shows the price dropping slightly from contract to contract.

Don’t forget FNG and GVEA

There are two other North Slope natural gas supply contracts worth mentioning.

The first is the one Fairbanks Natural Gas signed with ExxonMobil in 2008, but cannot put into effect until it launches a liquefied natural gas trucking operation to the Interior.

While the specific terms are proprietary, the contract is also based on North Slope oil prices, and Scott believes it is similar to the ConocoPhillips contract, but perhaps with some unknown but unique peculiarities that keep it from being entirely identical.

The other contract is the one Golden Valley Electric Association signed with BP Exploration (Alaska) Inc. in 2012, and also cannot use without a transportation solution.

Because even less is publically known about the GVEA contract than the Fairbanks Natural Gas contract, it’s nearly impossible to discern a trend among the four contracts.

So in the end, Fairbanks Natural Gas is right and wrong and everything in between.

Read more:

Friday, June 21, 2013

New Alaska reality TV pilot to highlight independent oil and gas explorers


Contact: BEACON Media + Marketing (907) 563-6008

Anchorage, AK (June 21, 2013) – A new reality special/series tentatively titled “Wildcatters of the Last Frontier: Chasing Oil and Gas in Alaska” will take a close look at the people and companies who explore and drill in Alaska.

Showcasing the Davids and Goliaths of the oil and gas industry, the TV special/series will follow “wildcatters” (independent oil prospectors) as they acquire, explore, develop, drill and produce oil and gas in the 49th state. The show will use contemporary and vintage footage and display modern day technologies as these prospectors develop Alaska’s natural resources.

Now that Alaska has passed oil and gas tax reform, independent prospectors with determination and perseverance have a chance to earn a living and make a profit in the state’s oil and gas business.

Award-winning Executive Producer Gregory Micallef has 30 years’ experience in all aspects of the Alaska oil industry. “Oil has peaked around the world,” said Micallef, “and Alaska is truly the Last Frontier. The state has the potential to become the number one oil and gas producer in the US – again.” Micallef is very proud to showcase Alaska’s beauty and natural resources.

“The most exciting part of the pilot is showing that Alaska’s oil and gas can be developed responsibly,” says producer Deborah Brollini, a 37-year Alaskan.

Alaskan State Senator Lesil McGuire says “This is an exciting project that will bring the kind of attention we want to Alaska. We remain an important supply point for America’s energy needs.”

The show will focus on exploration around the Kenai Loop Field, the majestic Cook Inlet and the North Slope and will take a positive look at investments by individuals and corporations and show the world that Alaska is open for business.

BP reviews statistics; Unintended consequences with strange shifts masked by continuing trends

Eric Lidji
For Petroleum News

The BP Statistical Review of World Energy 2013 shows the far reach of unintended consequences when the context is the globally interconnected energy marketplace.

Those Iranian sanctions? They helped keep oil prices high despite a huge imbalance between production and consumption. All that shale gas? It flooded Europe with coal.

The big picture for 2012 continued to follow several recent trends. There was lower growth in energy demand globally, and the United States saw the largest increases in both oil and natural gas production. But “as soon as you go beneath the surface, all sorts of adaptation processes emerge which are quite interesting,” BP group Chief Economist Christof Ruehl said in introducing the 62nd annual edition of the reference guide.

The oil conundrum

The oil markets presented a puzzle in 2012.

Globally, oil production increased by almost 2 million barrels per day, or 2.2 percent, while oil consumption grew by less than 1 million bpd, or 0.9 percent, the weakest growth rate of the three major fossil fuels for the third year in the row.

And yet, during this same time, nominal oil prices remained stable, and relatively high.

“And so the big question is how can this be that prices stay up and production exceeds consumption by so much?” Ruehl said. “The answer lies in inventory build.”

To compensate for the political uncertainty of the Iranian sanctions, countries in the Middle East and non-OECD countries such as China built up their inventories.

“That’s where the missing barrels actually went and kept prices up,” Ruehl said.

Without the United States, those countries may not have been able to accommodate the stockpiling. The 1 million bpd increase in domestic production, primarily from tight oil sources, allowed the U.S. to back out imports. OPEC also increased production, partially to offset Iranian sanctions and partially to offset ongoing slowdowns in Libya.

More gas means more coal?

The natural gas market also caused some unexpected shifts.

Globally, gas is flowing into Asia to accommodate the shift from nuclear power in Japan following the Fukushima disaster and high economic growth in China. In the U.S., a massive increase in shale gas production is leading power plants to switch from coal.

The movement of global liquefied natural gas supplies to Asia, and the increased prominence of gas in the U.S. are making a lot of coal available for use in Europe.

On top of the environmental consequences, the shift is causing geopolitical consequences for Europe’s historic supplier. “Russian exports of gas into Europe declined massively as a result of Europe replacing gas with coal, and of course also because of weak economic growth in Europe,” Ruehl said. “So in that way one could say that Russian exports also became a victim, to some extent, of the shale revolution in natural gas in the U.S.”

Renewables slowing down

As has been common recently, the small percentage of renewable energy in the marketplace continues to grow at the fastest rate, although it has slowed down some. Renewable energy remains a small component of the energy sector — some 2.4 percent of all consumption and 1.9 percent of all power generation — but it grew by more than 15 percent last year. The growth came largely from wind and solar, though. Biofuels declined for the first time since 2000, mostly driven by a decline in the United States.

Generally speaking, Ruehl said, renewable energy use is slowing down in those countries where the penetration rate is highest, particularly in the United States and Europe.

The decline in renewable energy is causing one of the most surprising unintended consequences of the past year, according to Ruehl. With Europe having met its targets for renewable energy and energy efficiency, the price of carbon fell considerably on the European Union Emission Trading Scheme, which allowed coal to flood the market.

“Because these targets were followed and reached, the carbon emissions were so low that the carbon price was not meaningful anymore, not high enough to prevent the influx of coal into the system,” Ruehl said. In other words: renewable energy and coal squeezed gas out of the power production mix. “And that’s certainly not what was intended.”

Globally, there was a 1.9 percent increase in CO2 emissions from energy use last year, primarily from developing countries. While emissions fell “quite rapidly” in the U.S. because of the shift to natural gas, according to Ruehl, they fell much slower in Europe.

“It is a little bit ironic, one could say cynically, that in the U.S. carbon emissions have declined quite rapidly because of the innovation taking place in the fossil fuel sector, particularly the replacement of coal with shale gas, whereas in Europe, CO2 emissions haven’t decreased as much as they should have because of inconsistency of regulation, because of the inability to combine rising targets for renewables and for energy efficiency with a positive volume target which would allowed for positive carbon prices,” he said.

Read more:

2nd ANWR push coming; Alaska to apply to Interior for approval of exploration for coastal plain

Wesley Loy
For Petroleum News

Back in May, Alaska Gov. Sean Parnell pitched Interior Secretary Sally Jewell a $50 million offer to conduct oil and gas exploration on the coastal plain of the Arctic National Wildlife Refuge.

As of June 19, Parnell hadn’t received a response, the governor’s spokeswoman, Sharon Leighow, told Petroleum News.

Soon, however, the state will intensify pressure on the federal government by putting forward a follow-up proposal to the Interior Department.

It will take the form of an application for approval of an “exploration plan,” as provided for under a section of ANILCA, the Alaska National Interest Lands Conservation Act of 1980.

Alaska’s natural resources commissioner, Dan Sullivan, discussed the forthcoming application during recent testimony before Congress.

Miffed over wilderness alternatives

Parnell, in a May 18 letter to Jewell, proposed a seven-year 3-D seismic acquisition and drilling program for the ANWR coastal plain, which currently is off-limits to oil and gas activity.

The governor pledged to ask state legislators for $50 million to help fund the program.

He offered the proposal essentially as an extra alternative for the Interior Department to consider as it prepares a new “comprehensive conservation plan” for managing ANWR.

State officials were upset that the Interior Department failed to include an oil and gas alternative in a draft of the plan, yet included alternatives to possibly recommend wilderness status for the coastal plain. Such status would need the approval of Congress, and would bar drilling permanently in the 1.5-million-acre area.

The U.S. Fish and Wildlife Service, the Interior Department agency that manages ANWR, is now overdue on finalizing the comprehensive conservation plan.

Terms of ANILCA

The coastal plain is also called the 1002 area, after a section in ANILCA.

In testimony May 22 before the House Natural Resources Subcommittee on Energy and Mineral Resources, Sullivan said the state was “not confident” the Interior Department would adopt the governor’s seismic and drilling proposal as part of the ANWR comprehensive conservation plan.

And so, the state will “directly apply” to the Interior Department for acceptance of an exploration plan, as provided for in Section 1002(e) of ANILCA.

The section is titled “Exploration Plans.”

It says “any person including the United States Geological Survey may submit one or more plans for exploratory activity ... to the Secretary for approval.”

Upon receiving an exploration plan, the secretary “shall promptly publish notice of the application and the text of the plan in the Federal Register and newspapers of general circulation.”

The secretary “shall determine” within 120 days whether the plan can be approved, the section says.

Before making a determination, the secretary “shall hold at least one public hearing in the State for purposes of receiving the comments and views of the public on the plan.”

Forcing the issue

Sullivan told the subcommittee that, if certain criteria are met, the secretary is mandated by law to approve the exploration plan.

He noted the potential for the coastal plain to produce a great deal of oil, as well as many jobs and substantial government revenue.

An updated resource assessment is essential for confirming the area as “a major national asset” for energy, he said.

A spokeswoman for the Alaska Department of Natural Resources indicated to Petroleum News on June 19 that the state would submit its exploration plan in the coming weeks.

Opening the coastal plain to drilling is a long-held economic development goal for Alaska’s elected leaders.

The governor’s efforts to force the issue, however, clearly face tough odds in Congress, and in the Obama administration.

In congressional testimony on June 6, Jewell said: “The president has made it clear that it is not part of his agenda to do oil and gas exploration in the Arctic National Wildlife Refuge, and I support that position.”

Read more:

State awaits key decision from producers on large LNG export project

Tim Bradner
Alaska Journal of Commerce

State officials are hoping to hear any day, perhaps as soon as June 20, from companies working on a large natural gas project that they are ready to go to the next stage of preliminary engineering on the project.

Earlier this year in his State of the State address, Gov. Sean Parnell laid out a series of milestones for the project including a commitment to undertake a preliminary Front End Engineering and Design, or “pre-FEED” in the first half of 2013.

The deadline for that, June 30, is fast approaching.

Companies involved are producers BP, ConocoPhillips, ExxonMobil and independent pipeline company TransCanada Corp.

So far the companies have met other milestones, such as reaching agreement on a scope of the project, and key design parameters of the gas treatment plant, the pipeline and a large liquefied natural gas plant at an as-yet undesignated Southcentral Alaska port.

Moving to “pre-FEED” is significant because it would be the first substantial financial commitment to the latest version of the project, and would require an expenditure of several hundred million dollars.

Meanwhile, the project manager for the industry-led group, Steve Butt of ExxonMobil, told a state legislative committee in a briefing on May 30 that part of the gas project is actually under construction.

These are the facilities at Point Thomson, a large gas field 60 miles east of Prudhoe Bay, now being built. While this will initially produce a liquid gas condensate with the produced gas injected back underground the long-term plan is for it to be part of the larger gas project.

Butt said 1,200 people were working last winter on the Point Thomson project. Work is continuing through this summer, with about 550 people working, be said.

ExxonMobil, which is leading that project, achieved a 90 percent Alaska-hire rate through the 35 contractors employed last winter, Butt said.

State Sen. Click Bishop, R-Fairbanks, one of the legislators being briefed May 30, said the local-hire rate was impressive.

“A 90 percent local hire on the project of that size is almost unbelievable,” Bishop said.

Butt said a lot of progress is also being made on planning for the larger gas project. The industry group is now spending about $3 million per month in its work with more than 300 people employed from the companies and contractors.

The overall project would involve an investment of between $45 billion and $65 billion, and would ship between 16 million tons and 18 million tons of LNG annually. It would be operating after 2022, if it is built.

Expenditures in the last year and a half, since work began on the latest pipeline/LNG version of the project, have totaled about $35 million. This is on top of about $700 million spent by the companies on a previous project to build an all-land pipeline to Alberta so that Alaska gas would be shipped to the Lower 48 states.

The fast buildup of shale gas at low costs have taken away the Lower 48 market for now, however, so the companies shifted to an LNG export project partly at the urging of Parnell.

Most of the LNG would be shipped to Asia.

Project progress

In the latest effort the companies have pooled information gathered by the Denali pipeline project, which was pursued by BP and ConocoPhillips but then ended, and the Alaska Pipeline Project, which was being pursued by TransCanada Corp. and then joined by ExxonMobil.

Technically, the project that is continuing is still the Alaska Pipeline Project with its new plan for a pipeline to an LNG project, with BP and ConocoPhillips in support of that. Those companies have not yet formally joined the APP.

One impediment to that, which will eventually be resolved, is that TransCanada is committed to special terms under the state’s Alaska Gasline Inducement Act, or AGIA, under which the state is also paying up to $500 million to support the companies’ work.

AGIA requires that the companies agree to certain terms on tariff structures and financing to which the three producers have objected.

ExxonMobil, BP and ConocoPhillips have said they cannot agree to AGIA’s terms and that the agreements will have to change if the project were to eventually move forward.

Parnell has said he is open to changes in AGIA once the companies are all in agreement to move forward with the project.

Meanwhile, Butt said May 30 that in achievements so far the companies have completed an integrated design for the gas treatment plant, pipeline and LNG plant, have finished needed hydraulic modeling, and have worked out the heat and materials balancing.

“This assures us that the project can work, from a technical standpoint,” Butt said.

Each of the major components is a mega-project on its own, with the Gas Treatment Plant requiring about 270,000 tons of steel and five sealifts of equipment and materials to the North Slope, he said.

Alaskans have seen previous efforts on large pipeline projects, all failing to advance for various reasons, but what is different now is that all parties are working together, including the state.

Coordination has also been established with the Prudhoe Bay field operators, which comprise the same three producers but in a different organization. This is important because the gas treatment plant is being integrated with the existing Prudhoe field gas processing facilities, Butt said.

There is agreement that 42-inch pipe will be used on the main pipeline.

“This is a standard size of carbon steel pipe that can be sourced from a lot of steel mills in different places. It really opens up the market,” in terms of procurement, Butt said.

Previous efforts have included plans to use larger pipe sizes including more than 50 inches that would have drawn from a very limited pool of suppliers.

The LNG plant in Southcentral Alaska would have three LNG process trains, or production modules, taking an average of 2.5 billion cubic feet a day of gas although the pipeline is being designed to transport up to 3.5 billion cubic feet daily so as to allow for increased seasonal production.

Gas plants are more efficient in cold weather, Butt said, so production might be ramped up in winter, which also coincides with periods of peak demand from customers.

“Our core challenge is to reduce the uncertainties and risks for the project,” Butt told the legislators May 30.

He didn’t mention it, but the uncertainties include the state’s fiscal terms on gas production, on taxes and administration terms of the royalty.

Tax terms

Now that legislation has passed adjusting the state oil production tax, in Senate Bill 21, state officials have said they are ready to discuss special terms on gas production taxes for the big gas project. Talks on those are believed to be underway now.

The oil tax change is important because it will help ensure that oil production will continue and that the infrastructure of the North Slope will be maintained, and paid for by oil production, for the gas project.

Meanwhile, there are still other uncertainties for the gas project itself, Butt told legislators. A big one is a stretch of several hundred miles of discontinuous permafrost soils extending through Interior Alaska. Continuous permafrost, or permanently frozen soil, that exists on the North Slope creates a stable soils environment for a buried gas pipeline, which will be cold.

However, discontinuous permafrost that freezes and thaws, which exists in the Interior, creates challenges is that it may cause the pipeline to move.

The soils south of the Brooks Range, “are a little messy,” Butt said.

A buried 42-inch pipeline is heavy, so it is believed that this problem can be handled, but it will still be an area of special focus for state and federal regulators.

Last spring, in a previous legislative briefing by the pipeline and LNG group, the possibility that parts of the pipeline might have to be built above ground, similar to the Trans-Alaska Pipeline System, was mentioned.

“TransCanada (a member of the industry consortium) has a lot of experience in building Arctic pipelines and has been in discussions for three years with government agencies about this,” Butt said.

Permitting itself is a challenge, particularly with a special federal permit now required for Arctic pipelines.

“We’re just starting to talk with the regulators about this,” Butt said.

Above-ground construction at selected points is also a concern for the state-owned Alaska Gasline Development Corp. in its work on a separate 36-inch pipeline that is a contingency in case the industry-led project fails to advance.

Frank Richards, a senior AGDC manager, told the legislators May 30 that seismic hazards from potential earthquakes at the Denali Fault in the Alaska Range and the Castle Mountain fault in Southcentral Alaska, in the Matanuska-Susitna Borough, may require special construction above-ground so as to allow the pipeline to move in the case of an earthquake.

The Trans-Alaska Pipeline System survived an earthquake in 2002 on the Denali Fault because of a special design incorporated by engineers when TAPS was built in the mid-1970s, Richards told the committee.

The design allowed the oil pipeline to move laterally without breaking in an earthquake. Similar design concepts may have to be built into AGDC’s plan, Richards said.

Butt didn’t mention seismic hazards but the large 42-inch pipeline would also cross the Denali Fault and, if it comes to Mat-Su-Anchorage region instead of Valdez, the Castle Mountain fault as well.

Read more:

Friday, June 7, 2013

No LNG needed? Hilcorp says there’s gas in Cook Inlet, will develop it to meet contracts

Kristen Nelson
Petroleum News

Does Southcentral Alaska need to import liquefied natural gas?

That’s been a growing concern in recent years as production of Cook Inlet natural gas declined.

But Hilcorp Alaska — now the region’s major oil and gas producer — says the gas resource exists to meet expected demands.

Hilcorp assumed a dominant role in crude oil production in Southcentral when it acquired Chevron’s Cook Inlet assets at the beginning of 2012 and since closing on acquisition of Marathon’s Cook Inlet assets early this year it has also become the dominant producer of natural gas.

The company’s crude oil production helps feed the Tesoro refinery in Nikiski, and can be supplemented by North Slope and imported crude oil. But natural gas, used for both heating and electric power, cannot be easily supplemented because Southcentral Alaska is not connected to any outside sources of gas.

With declining gas production and the possibility of pipeline gas from the North Slope a long way off, concerns about deliverability of Cook Inlet natural gas have grown.

Contracts through 2017

But Hilcorp officials say that based on gas which is either available or available to develop they are in discussions with customers for contracts to meet local needs through 2017.

John Barnes, Hilcorp Alaska’s vice president for exploration and production and Kurt Gibson, vice president of the company’s Alaska midstream division, told Anchorage Mayor Dan Sullivan’s Energy Task Force at a June 5 meeting that Hilcorp is working with customers to identify natural gas needs, develop contracts to meet those needs, produce that gas as needed and get out in front of the issue by identifying further reserves in the area.

The company has been touting its increased oil production, and Barnes shows a graphic illustrating a 36 percent increase at Hilcorp-operated fields from January 2012 through May of this year — with the largest increase at Swanson River, 412 percent, followed by Trading Bay at 157 percent.

Natural gas production saw a dramatic spike beginning in February after the Marathon acquisition closed.

Hilcorp doesn’t operate the Beluga River field, which it is a one-third owner, and decline there continued.

But at fields which Hilcorp now operates the uptick was dramatic.

Barnes said after they closed on the Marathon acquisition they took advantage of the remaining winter window to turn the wells all the way up and see what they could do. Hilcorp’s presentation showed production up from some 65 million cubic feet per day at the end of January to almost 180 million cubic feet per day in February.

At Deep Creek, where production had already increased 96 percent prior to the Marathon acquisition, Barnes said the field was “making more now than it was shortly after Unocal discovered and developed it.”

While Hilcorp hasn’t yet had as much of a chance to drive performance on the gas fields as it would like, the gas asset is there and the strategy is to drive production, getting both rate and cash flow up, Barnes said.

Illustrating the potential, Barnes said Hilcorp has done a 3-D seismic program at the Deep Creek unit and estimates that the resource at Happy Valley within that unit is “probably three to four times larger than the current participating area.”

Moving fast

Urgency is one of Hilcorp’s core principles, Barnes said, and they’re trying to move fast following the Marathon closing. Two onshore drilling rigs started loading out this week, he said, and two fit-for-purpose pulling units will arrive for the offshore platforms this summer.

Hilcorp has already been able to go back onto the Trading Bay unit platforms and reactivate gas production there, he said.

The company spent $238 million in Alaska last year, Barnes said: 2 percent “getting rid of old junk,” 38 percent “fixing broken stuff,” 8 percent on non-operated projects and 52 percent “executing new projects.”

The 2013 spend is $300 million, and while Barnes said he wouldn’t break out how that would be spent, he expects some 70 percent will be on new projects.

Hilcorp will be addressing costs, Barnes said, and will be going from gas lift to electric submersible pumps on all the platforms. It will cost money, but in the long run Hilcorp will produce more oil at a lower cost, he said.

Gas marketing local

Gibson, head of the company’s new Alaska Midstream Division, said oil marketing was handled out of Houston but gas marketing is being handled out of Anchorage.

With “boots on the ground,” he said, Hilcorp has reached out to the customer community in Alaska and invited them in to hear the company’s plans in Cook Inlet, its timing and how Hilcorp might be able to provide for their gas needs.

Gibson said Hilcorp has a business to run and has to plan that business in a way that makes sense as far as capital allocation is concerned.

He said that requires candid conversations with folks that burn gas, with customers telling Hilcorp what they need and Hilcorp telling customers whether it can meet those needs. Gibson said the discussion has been productive.

But Hilcorp doesn’t plan to go back to the way things were in Cook Inlet when there was an abundance of natural gas found while looking for oil, which produced numbers like 20 to 1 reserves to production ratios, held prices down and required industrial facilities like the LNG export plant and the fertilizer plant.

“The world has changed such that we’re going to have a just-in-time inventory world for natural gas,” Gibson said.

Hilcorp thinks it can “meet the needs of the local community but it’s going to require direct engagement ... repeated engagement.”

That engagement is taking place, Gibson said, conversations about what the needs are, what Hilcorp can do, and how it needs “to invest to provide line of sight” for the company on where it needs to deploy its resources “and provide line of sight as well for the folks who are burning gas to keep their houses warm and keep the lights on so that they can make rational decisions on what their alternatives might be.”

And what about a line bringing gas from the North Slope?

If there is such a line, Barnes said he wants access, because if Hilcorp can put gas in that line, it creates opportunity.

Consent decree terms

Hilcorp is operating under a consent decree negotiated with the attorney general’s office for the Marathon acquisition.

Gibson said that consent decree has provided something Cook Inlet hasn’t had — visible gas prices. While the Lower 48 has publications which tell you what the gas price is, the gas price in Alaska “has been a bit of a black hole,” he said.

The consent decree, which runs through the end of 2017, provides a signal to the market on prices, and when the Regulatory Commission of Alaska sees contracts “you’ll see prices through 2017.”

Hilcorp is telling local gas consumers that it has, “a conservative view of what we see as the available resource,” Gibson said.

Some of that gas is behind pipe already, he said, “but not much. Some of it can be found very quickly if we need to. ... And still another tranche of it is going to require ... more of an effort.”

The principle, he said, is “having a cooperative business relationship” with customers.

“What we’re saying is, the gas is there and we’ll go get it if you tell us to.”

But, he said, Hilcorp is not inclined to develop a surplus of natural gas.

“We will go develop what’s necessary and in fact we’ll probably over develop a little bit because we’re making fairly firm commitments to our customers and we absolutely are committed to meeting those under our contracts.

“The gas is out there,” Gibson said, “but it’s not just lying around the warehouse.”

Two-pronged strategy

Barnes said it is really a two-pronged investment strategy: identifying “a reserve base that we can continue to market” with some investments “geared more towards reserve definition” and the “just-in-time delivery ... focused on developing deliverability as supply meets the market.”

The goal, Barnes said, “is not to have a lot of investment waiting for the market to develop our deliverability.”

But whether gas is needed for the Donlin Creek mine or other possibilities, “we know we need to start getting a line of sight on reserves.”

Gibson said Hilcorp’s objective is contracts through 2017 “with all those interested in buying gas from Hilcorp so they can plan their business rationally for the next several years and we can plan our business rationally over the next several years and everybody can kind of sleep at night and go about their regular day jobs without their hair on fire because there’s a lot of concern and fear, frankly, in regard to where we are in the Cook Inlet on natural gas supplies.”

Hilcorp wants to turn the gas it finds into revenue, but it also wants it customers “to make rational decisions about how they need to plan their long-term business so that they don’t feel like they need to pull the trigger on something that may be irreversible today and they’ve got line of sight on how and when they need to make critical decisions in regard to the long-term future.”

Gibson said Hilcorp is “currently in discussions with buyers and everybody who’s interested is getting as much of our time as they would like.”

Read more:

Parnell sets $425 million LNG trucking project on its way

Tim Bradner
Alaska Journal of Commerce

Alaska Gov. Sean Parnell chats at Fountainhead Antique Auto Museum in Fairbanks on May 29 after signing Senate Bill 23 to provide a package of $362.5 million in state financing to begin trucking LNG from the North Slope to Fairbanks.

Alaska Gov. Sean Parnell chats at Fountainhead Antique Auto Museum in Fairbanks on May 29 after signing Senate Bill 23 to provide a package of $362.5 million in state financing to begin trucking LNG from the North Slope to Fairbanks.

Gov. Sean Parnell signed a bill May 29 committing the state to finance $362.5 million of a proposed $425 natural gas liquefaction plant on the North Slope as well as facilities in Fairbanks to “re-gasify” and store LNG trucked from the slope and to distribute gas to residential and business customers.

Private parties are expected to finance the rest of the $425 million total, mostly for the LNG project, according to a presentation given by the Alaska Industrial Development and Export Authority, the state’s development corporation, to state legislators in late March.

A feasibility study of the project is expected to be completed in late June or early July, AIDEA spokesman Karsten Rodvik said.

Meanwhile, two gas utilities are vying to build out the distribution system for Fairbanks. One is now serving a small core area of Fairbanks; the other is a newly-formed public utility that does not yet have pipe in the ground.

The project is expected to deliver LNG for a wholesale price of about $10.15 per thousand cubic feet, or mcf, according to AIDEA’s preliminary estimates. That is expected to translate to a delivered retail price of gas in the Fairbanks area for $13.42 to $17 per mcf.

On an energy-equivalent basis that is about half what Fairbanks consumers now pay for fuel oil.

Other customers are expected to include Golden Valley Electric Association, the Interior electric co-op, and Flint Hills Resources, owner of a refinery at North Pole, east of Fairbanks. Both now use fuel oil, which is very costly.

Propane would also be available as a part of the project for use in the Fairbanks area or in rural communities.

The legislation signed by Parnell is Senate Bill 23, passed by the state Legislature in April. It commits AIDEA and another state entity, the Alaska Energy Authority, to finance and develop the LNG project with private partners.

AIDEA would own part of the North Slope LNG project, with a $50 million direct investment with a yet-unidentified private partner.

The state investment would give the state a share of the expected 9 billion cubic feet per year of processing capacity, amounting to about 6.5 billion cubic feet per year.

AIDEA’s share of the plant’s LNG output, amounting to about two-thirds, would be sold to public utilities in the Fairbanks area at cost, with no return charged on the state’s investment.

If AIDEA sells LNG to non-utility customers it can include charge for return on investment, however.

The state authority would also issue up to $150 million in authority revenue bonds to finance the gas distribution system. The gas utility would repay the bonds with fees charged to consumers.

The tentative plan developed by the authority envisions an interest rate of 3 percent to 4.5 percent on the bonds, depending on the tax-exempt component of the bond issue and the rates in the market when the bonds are sold.

Bonds will also carry the state’s “moral obligation” that the state itself would back the bonds if the Fairbanks gas utility did not make payments.

In addition, the plan calls for AIDEA to make $125 million available from the authority’s sustainable energy investment fund for financing for private parties on parts of the LNG plant and the gas distribution system. Senate Bill 123 set the interest rate for this financing at 3 percent.

Finally, the LNG storage tanks built for the project in Fairbanks, which would be constructed or owned by a local utility or private parties, would be eligible for state tax credits up to $30 million.

The project plan contemplates an LNG plant at Prudhoe Bay with LNG tank trucks carrying liquefied fuel down the Dalton Highway to Fairbanks, but a variation of this being studied by AIDEA, the state Department of Natural Resources and private firms would have the LNG plant built farther south along the highway, according to sources familiar with the discussions.

There is a small fuel gas pipeline built parallel to the Trans-Alaska Pipeline System that carries gas for fuel to pump stations north of Atigun Pass. The pipeline is now underused, and an idea being considered is using spare capacity to supply an LNG plant.

The plant could be built either at Galbaith Lake, just north of Atigun Pass, where there is a TAPS pump station reached by the pipeline, or it could be built at Chandalar, south of the pass, where the state has an existing highway maintenance camp.

Using state land adjacent to the camp could simplify permitting, but it would also require a short extension of the gas pipeline, according to the sources familiar with the idea.

Slope investments may top $5B with BP plans

By Tim Bradner
Alaska Journal of Commerce

A caribou browses along oil transit pipelines on the North Slope in this file photo. BP Exploration Alaska announced a billion-dollar investment plan for the Slope involving several new rigs and additional development of the Prudhoe Bay field in response to the signing of Senate Bill 21 lowering state oil taxes.

A caribou browses along oil transit pipelines on the North Slope in this file photo. BP Exploration Alaska announced a billion-dollar investment plan for the Slope involving several new rigs and additional development of the Prudhoe Bay field in response to the signing of Senate Bill 21 lowering state oil taxes.

BP announced June 3 it is planning $1 billion in new investment on the North Slope and possibly $3 billion more due to changes in the state’s oil tax policy signed into law May 21 by Gov. Sean Parnell. ConocoPhillips is also planning new projects, and while no figures have been given those could easily increase the total of pending new projects to $5 billion.

BP said it will add two drilling rigs to its Alaska North Slope fields over the next five years and will ramp up “workovers” on existing wells to increase production later this year, the company said.

ConocoPhillips’ announcement of new work, made in late April, included putting another “workover” rig to work late this year in the Kuparuk River field, where it is operator. ConocoPhillips also said it would be working on additional developments in the Kuparuk field as well as in the National Petroleum Reserve-Alaska, where the company has made discoveries.

BP’s investments will be in the Prudhoe Bay and Milne Point fields, which it operates. The company’s plan overall calls for an increase in drilling and well-work activity, the upgrading of existing facilities and the addition of up to 200 new jobs in the state, giving a boost to both the company’s operations and the state’s economy.

The two new rigs will bring BP’s drilling fleet on the North Slope to nine rigs, company spokeswoman Dawn Patience said.

In addition, BP said it has secured support from ConocoPhillips and ExxonMobil Corp., the other major working interest owners at Prudhoe Bay to begin evaluating an additional $3 billion worth of new development projects.

These projects, located in the west end of the Greater Prudhoe Bay Area, could continue for nearly 10 years, further increasing the state’s oil production and providing additional jobs, according to the announcement.

BP will issue a request for proposals beginning this summer for the two additional rigs for Prudhoe Bay, the press release said. The first rig is expected to be in place by 2015 and the second in 2016.

BP also said it expects to increase well work as soon as the fourth quarter of 2013, a move that should improve the performance of existing wells at the Prudhoe Bay and Milne Point fields.

This would involve more activity by specialized workover rigs and coiled-tubing well units to do technical work on producing wells that typically results in greater production.

The additional Prudhoe Bay developments being evaluated by BP and its partners, ConocoPhillips and ExxonMobil, are in the west end of the Prudhoe Bay field.

They include the expansion and “de-bottlenecking” of field production facilities to improve the handling of natural gas and water from that area, the construction of a new drilling pad, expansions of existing pads, and the drilling of more than 110 new wells.

The appraisal phase of this will take two to three years and will include engineering work and regulatory approvals for multiple development projects, BP said in its announcement.

ConocoPhillips’ has meanwhile identified the additional workover rig slated for the Kuparuk field as the Nabors rig 7ES unit. In its late April announcement ConocoPhillips also said it is evaluating a new pad in the southern part of the field following the drilling of an exploration well in that area in 2010.

“We hope to sanction the Kuparuk drill site DS-2S in late 2014 or early 2015,” ConocoPhillips spokeswoman Natalie Lowman said.

In the NPR-A, ConocoPhillips hopes for the same timing for a project in its “Greater Moose’s Tooth Unit”, with possible sanction of a project in late 2014 or early 2015 Lowman said. In the April announcement ConocoPhillips said it was beginning engineering and permitting work for the NPR-A project following the Legislature’s approval of the tax bill.

ConocoPhillips is operator in the Moose’s Tooth Unit for itself and its minority partner Anadarko Petroleum. The developments in the Prudhoe and Kuparuk fields require the consent of all three major North Slope producers, BP, ConocoPhillips and ExxonMobil Corp.

All three companies own a share of the fields, along with others with small percentages, but one or another company would be designated as operator.

“Now that an improved tax structure is in place, oil and gas projects can once again move forward, keeping Alaska competitive in the midst of America’s recent energy renaissance,” BP’s president Weiss said.

BP, ConocoPhillips and ExxonMobil are also working with other companies and the state of Alaska to commercialize Alaska North Slope natural gas as part of a joint concept selection group focused on a South Central Alaska LNG project.

All three companies have previously said that keeping the oil production business on the North Slope economically healthy through changes in the state oil tax are important to the gas project. That’s because oil production is needed to help pay for the infrastructure that is also needed for gas production.

“We believe it is the right time to focus on how we move this project (the gas pipeline) forward,” Weiss said.

Read more:

Saturday, June 1, 2013

AJOC EDITORIAL: ACES works...for North Dakota

Andrew Jensen
Managing Editor

Here’s a headline from Bloomberg you won’t see the Juneau spendaholics touting as they run their dishonest campaign against the recently signed oil tax reform bill: “Alaska North Slope Premium Drops to Lowest Level in 16 Months.”

Because West Coast refiners lack access to the more extensive pipeline infrastructure of the Midwest and rely heavily on imports, Alaska North Slope crude has long traded at a premium compared to West Texas Intermediate, or WTI, crude.

However, as Bloomberg reporter Eliot Caroom documented, that premium spread is shrinking. On May 28, the premium between Alaska North Slope crude, or ANS, and WTI was down to $8.90. That’s the lowest it has been since Jan. 4, 2012.

A few months ago, on Feb. 25, the premium between ANS and WTI was $18.75.

What’s going on is simple, and it’s not good for Alaska in more ways than just the drop in prices.

“ANS has weakened against WTI and Bakken this year as refiners including Phillips 66 announced they would move more oil to their West Coast refineries from North Dakota,” Caroom wrote.

Caroom then quotes Andrew Lebow, a senior vice president at Jefferies Bache LLC in New York: “The rail movement from the midcontinent west is competing with ANS,” Lebow said.

“With the additional rail capacity, it makes sense that WTI-ANS has tightened.”

Well, it makes sense to anyone with a basic working knowledge of global markets, supply and demand, or math.

So don’t bother telling Les Gara, Bill Wielechowski, Hollis French, or any of the other economic illiterates who don’t understand anything except playing political games with Alaska’s future and who are recklessly injecting at least another year of uncertainty into our state business climate with their foolhardy drive to repeal SB 21.

While Gara and the Gang mug for cameras and spread their horse pucky, the Bakken fields in North Dakota that now surpass the North Slope in daily production are not just taking jobs and investment away from Alaska anymore.

Now the cheaper Bakken crude is taking away Alaska’s market share on the West Coast.

But don’t worry, I’m sure Wielechowski will have a press release out soon explaining why all this is proof ACES works. Yeah, ACES works great, if you’re a senator from Bismarck.