Sunday, July 20, 2014

Explorers 2014: Repsol feeling ‘positive’ about Alaska exploration

Eric Lidji
For Petroleum News

Having completed its initial three-season exploration program the Spanish major is eying development

Repsol E&P USA Inc. recently finished its most important season in Alaska to date.

After announcing three discoveries last year, the Spanish major completed a three-well program this winter - a pair of appraisal wells in the Colville River Delta and an exploration well south of the Prudhoe Bay and Kuparuk River units. Those wells “finished with positive results,” Chief Financial Officer Miguel Martinez said at a first quarter earnings call on May 12. “We are working toward defining the most economical way to develop the area,” he added, saying it was too soon to comment further.

With the two appraisal wells, Repsol attempted to alleviate uncertainties around the earlier discoveries with the goal of sanctioning a major development, Repsol Alaska Project Manager Bill Hardham told the Alaska Support Industry Alliance on Jan. 23.

While declining to offer a timeline for development, Hardham said, “I feel confident it’s coming. It’s not a matter of if, but when.” But Hardham also warned, “The predictability of the regulations and tax structure is key to making these big investment decisions.”

It’s certainly no surprise to hear an oil company advocate for low and stable taxes over high and shifting taxes, and Repsol has never given a straightforward ultimatum about what might happen if voters overturn the new fiscal system in a referendum this summer, but Hardham listed taxation alongside geophysical analysis and stakeholder engagement as the major “uncertainties” Repsol must resolve before it could sanction development.

To the west, to oil

Repsol started as a state-owned monopoly created before the Spanish Civil War, but reorganized over the following decades and became a private company in the late 1980s.

Repsol was primarily a European downstream company before it acquired the Argentinean company YPF in 1999 and created the multinational Repsol YPF S.A. After that, the company began rapidly expanding, particularly across Latin America.

Today, Repsol maintains assets in more than 50 countries around the world.

The growth made Repsol a major player, but over the past decade the company decided to take a different approach by focusing on the West and on increasing its oil production.

With its portfolio weighted toward South America and Africa, Repsol decided to grow its presence in developed economies. In a four-year plan announced in early 2008, the company set a goal to have at least 55 percent of its assets in OECD countries by 2012.

Global events subsequently supported the move. Repsol temporarily lost its largest source of production during the recent uprising in Libya. The company cancelled plans for a $10 billion investment in an Iranian natural gas venture because of the threat of sanctions over the Iranian nuclear program. Argentina essentially nationalized the YPF portion of the company, and several other South American countries changed their fiscal terms.

The strategic plan also favored oil production

Over the 2000s, Repsol had invested heavily in liquefied natural gas, becoming the third largest LNG company in the world. Of the 2 billion barrels of oil equivalent in total reserves the company reported in 2009, only 890 million barrels came from oil.

With import terminals in Spain and eastern Canada, and export terminals in Trinidad and Tobago and Peru, Repsol’s LNG assets were focused in the Atlantic Ocean, where there was talk of surpluses. By placing a priority on oil in its strategic plan, Repsol could diversify its portfolio and take advantage of the historic, decade-long rise in oil prices.

First steps north

This strategic plan is why Repsol first dipped its toe in Alaska waters. It started in 2007, when Repsol partnered with Shell and Eni on a block of federal leases in the Beaufort Sea. (Shell operated the joint venture.) Repsol said “exploration activities” could begin as early as 2009-10, but lawsuits delayed any activities.

At the time, Repsol stayed quiet about its larger intentions in Alaska, which allowed rumors to swirl. Given the outreach efforts of the Palin administration, some thought Repsol might invest in a North Slope natural gas pipeline under the Alaska Gasline Inducement Act, which had recently become law and was then accepting applications.

Ultimately, Repsol did not submit an AGIA application, but the company still invested in Alaska. In early 2008, Repsol bid $15.6 million on 104 tracts in the record-breaking federal lease sale in the Chukchi Sea, including $14.4 million in high bids on 93 tracts.

The leases were clustered into three groups. The first was north of the Popcorn well that Shell drilled in 1990. The second was between the Popcorn well and the Burger well to the east. The third was to the north, in a region thought to contain Brookian potential.

A big joint venture

Even with those bold moves into the Arctic, Hardham insisted that Repsol remained cautious about the state, saying that the company “turned down several opportunities to come in further into Alaska, largely because of the uncompetitive tax structure.” In March 2011, though, Repsol acquired a 70 percent working interest in North Slope leases held by the Armstrong Oil & Gas subsidiary 70 & 148 LLC and its fellow Denver-based independent GMT Exploration LLC. The joint venture covered 494,211 acres in the White Hills region south of the Kuparuk River unit and near the Oooguruk unit.

The $768 million deal earmarked some $750 million for exploration, according to Petroleum News sources, suggesting that all three parties wanted to get to development.

Why was Repsol skeptical about Alaska in 2009 but ready to invest heavily in 2011? It was a combination of the right opportunity and the winds of change, according to Hardham. “Repsol felt that this was the right time, things were changing, it was a good opportunity - they don’t come along very often. It fit with the strategy,” he said.

Less than a month before announcing the deal, Armstrong Vice President Ed Kerr had submitted a letter to state lawmakers in favor of House Bill 110, which was the legislative vehicle under discussion at the time for changing the fiscal system for oil production.

“The improved fiscal terms as proposed by HB 110, particularly the portions of the bill that apply to activities outside of existing units, will give us the needed incentive to not only drill multiple new wildcat and delineation wells, but the motivation to drive certain projects to development,” Kerr wrote, saying his company had “more than a dozen ideas outside of existing producing units” that it was eager to explore in the coming years.

What about gas?

Alaska provided a unique opportunity for Repsol.

“This deal is a perfect fit in our efforts to balance our exploration portfolio with lower risk, onshore oil opportunities in a stable environment. We are confident that our worldwide experience combined with a partner with an extensive local knowledge is going to deliver value in the near future,” Chairman Antonio Brufau said at the time.

As a politically low-risk onshore oil opportunity, the Alaska leases offset Repsol’s large liquefied natural gas trade and also its exploration in prolific but technically challenging oil-rich basins such as the deepwater Gulf of Mexico and the Santos basin off Brazil.

Even so, some still wondered whether Repsol might also be interested in natural gas.

Chevron drilled five shallow wells across the White Hills region in 2008 and 2009. The company never released well results, but the state of Alaska believed the region to be both oil and gas prone, and Alaska Oil and Gas Conservation Commission well logs suggested Chevron was targeting oil and natural gas prospects in the Brookian formation.

A poster child

Just as Pioneer Natural Resources Alaska Inc. became a poster child during debates over Alaska’s Clear and Equitable Share in 2007, Repsol E&P USA is getting stuck in a tug-of-war over the More Alaska Production Act, which replaced the ACES system last year. The debates over ACES often featured Pioneer Natural Resources.

The large independent operated under three tax systems during the five years it took to reach first oil at its Oooguruk unit, but also earned considerable tax credits in the process.

While much bigger than Pioneer, Repsol also falls in the middle of the spectrum for international oil companies. It is smaller than Shell, Exxon, BP, ConocoPhillips or even Eni, but much larger than the smaller independents working on the North Slope, like Brooks Range Petroleum Corp. or Savant Alaska LLC. As such, some consider it a bellwether: if Repsol wants to invest in Alaska, the investment climate must be good.

When Repsol arrived on the North Slope in March 2011, the company promised to spend it initial exploration budget over “several years.” Lawmakers such as Sen. Bill Wielechowski, an Anchorage Democrat, believed that the deal vindicated ACES, which expanded tax credits for exploration but also increased the tax rate when oil prices rise.

To some, the deal suggested that even with higher taxes, the developed world might be more attractive because of its lower political risks. “They want to enlarge their portfolio (in areas) that are politically stable,” Rep. Paul Seaton, a Homer Republican, told Petroleum News in March 2011. “Even as we, Norway and other countries have higher tax rates than some Third World countries, the political stability is very beneficial.”

Those comments came as lawmakers were beginning to debate changes to ACES. By the time Repsol announced its discoveries in early 2013, those changes had become the law.

Did SB 21 help?

In announcing the discoveries, Repsol called the recent tax changes “a critical factor in ensuring the development of this project,” a claim that Gov. Sean Parnell proudly touted.

“Can you say they made this investment because of the tax change?” House Speaker Mike Chenault, a Kenai Republican, told Petroleum News in May 2013, referring to Repsol. “I don’t know if you can really say that, but it’s going in the right direction. We are hearing about projects that have a chance of coming online versus where they were pulling projects off the board because they didn’t make economic sense under ACES.”

As the passage of Senate Bill 21 prompted a voter referendum to repeal it, Rep. Les Gara, an Anchorage Democrat, questioned drawing any link to the development plans. “Repsol announced two years ago they were going to invest at least three quarters of a billion dollars in Alaska, and if they found oil, more than that,” he told Petroleum News in August 2013. “Well they found oil in the spring and the governor said, hey this is because of SB 21. Folks who are going to try to stop the referendum will say anything they can.”

Today, Repsol claims that its decision to invest so heavily in Alaska in early 2011 was more of an informed risk than vote of confidence. “It was really about timing. … If you wait too long you can’t get the opportunity,” Hardham said. “So Repsol took a bit of a risk. They saw that there was change afoot. There was an opportunity, so we came.”

According to Hardham, Repsol believes the current system brings Alaska closer to the Lower 48, where it maintains operations in the Gulf of Mexico and in the Midcontinent.

“If you’re not competitive it gets really tough to develop these projects,” he said.

The Qugruk unit

The Repsol leasehold is spread across three chunks of the central North Slope.

The first is a T-shaped bundle running up the fairway between the Kuparuk River and Colville River units and spreading along the state waters of the Beaufort Sea. The second is a diagonal swath running south from Kuparuk nearly to the Brooks Range. The third is a smaller bundle hugging a bend in the Colville River south of the village of Nuiqsut.

In October 2011, Repsol and its partners applied to form the 98,852-acre Qugruk unit over 49 leases in the T-shaped bundle and proposed a four-well plan of exploration.

The region had been home to considerable exploration in previous decades, including six wells within the proposed unit boundaries going back to 1966 as well as 2-D and 3-D seismic, according to Repsol. The company described the primary objectives for the proposed unit as “sands within the upper portion of the Jurassic Kingak Shale, the Cretaceous Kup ‘C’ sand and several sands within the Cretaceous Nanushuk Group.”

In January 2012, the Alaska Department of Natural Resources approved a 12,065-acre unit over six leases just east of the Colville River unit, required Repsol to post a $20 million bond that would be returned if the company completed the Qugruk No. 4 well by June 30, 2012, and increased the rental rates on four leases set to expire in August 2012.

The smaller unit, the large bond and the relatively quick drilling commitment was meant to protect the state. The state felt that Repsol had “identified numerous high quality prospective targets over a large area in multiple stratigraphic intervals which will need to be drilled in order to prove up, which they propose to do in part during the proposed initial unit plan,” but also believed that unitization was “not technically supported.”

In mid-2013, Repsol asked the state to extend the primary terms of five un-unitized leases in the Qugruk area by three or four years. The request came after lawmakers passed House Bill 198, which gave state regulators additional authority to extend lease terms.

The law was designed to accommodate exploration companies that had spent considerable time and money exploring, but needed additional time to bring leases into production. Repsol had spent some $200 million exploring the leases since 2011, according to estimates from the company and the Department of Natural Resources.

The state ultimately gave Repsol an additional two years on the leases, but required the company to drill an additional well, post a $100,000 bond and collect new seismic. The decision made Repsol the first company to benefit from the law.

A three-year program

Repsol initially planned a five-well program for early 2012, but narrowed its efforts to four wells to alleviate local concerns. Those wells were the Qugruk No. 1, Qugruk No. 2 and Qugruk No. 4 along the Colville River Delta and just offshore and the Kachemach No. 1 much further south, near the Meltwater satellite of the Kuparuk River unit.

For the work, the company built 48 miles of ice roads in two segments. The first started at the Kuparuk River unit Drill Site 3S (or Palm satellite) and ran over the frozen coastal waters of the Beaufort. The other ran south from Drill Site 2S (or Meltwater satellite).

After a blowout at the Qugruk No. 2 well delayed its operations for several weeks, Repsol was only able to complete two wells: Qugruk No. 4 and Kachemach No. 1.

For early 2013, Repsol planned a three well program. Those wells were a second attempt at Qugruk No. 1, a Qugruk No. 2 re-drill called Qugruk No. 6 and Qugruk No. 3.

The company built an ice airstrip near Kuparuk Drill Site 2M and 38 miles of ice roads snaking north to Qugruk No. 1 and Qugruk No. 6 and south to Qugruk No. 3.

All three wells encountered hydrocarbons. Repsol performed drill stem tests on Qugruk No. 1 and Qugruk No. 6 and performed some early geotechnical work for development.

This winter, Repsol appraised those earlier discoveries with the Qugruk No. 5 and Qugruk No. 7 wells. Repsol also built a four-mile ice road south from Kuparuk to drill the Tuttu No. 1 exploration well on a lease just south of Prudhoe Bay and Kuparuk.

To bolster those activities, Repsol also contracted two 3-D seismic surveys. SAE Exploration conducted the Niglik Fiord survey covering some 222.39 square miles just offshore of the Colville River Delta, including the Repsol-operated Qugruk unit.

And Global Geophysical Services conducted the Schrader Bluff survey covering some 293.45 square miles south of Prudhoe and Kuparuk, including the Tuttu No. 1 well.

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Clock stopped for Shell in Chukchi Sea

By Tim Bradner
Alaska Journal of Commerce

Shell’s Arctic Challenger oil containment barge at the Port of Bellingham International Dock in Bellingham, Wash., seen in February 2013. Shell did not continue its plans for Arctic drilling in 2013 and 2014. The clock is still ticking on the company’s leases in the Beaufort Sea, although the Chukchi leases are on hold.

Shell’s Arctic Challenger oil containment barge at the Port of Bellingham International Dock in Bellingham, Wash., seen in February 2013. Shell did not continue its plans for Arctic drilling in 2013 and 2014. The clock is still ticking on the company’s leases in the Beaufort Sea, although the Chukchi leases are on hold.

The clock is ticking on Shell’s Outer Continental Shelf leases in Alaska’s Beaufort Sea. A large number of the company’s leases are set to expire in October 2017, federal officials said, although the leases on Shell’s two top prospects, Sivulliq and Torpedo, have been extended to July and October 2019.

Meanwhile, the U.S. Bureau of Ocean Energy Management, or BOEM, has stopped the clock on federal offshore leases held by Shell, ConocoPhillips and Statoil in the Chukchi Sea due to an ongoing lawsuit.

The Chukchi Sea has been Shell’s top priority in the Alaska OCS since 2013. ConocoPhillips and Statoil only have leases in the Chukchi Sea, and not the Beaufort Sea.

Shell drilled two partially-complete exploration wells in 2012, one in the Chukchi Sea and one in the Beaufort Sea, and had planned to return to both exploration areas in 2013 until the specialized drilling vessel Shell used in the Beaufort, the Kulluk, was damaged in a grounding near Kodiak in December 2012.

The Kulluk had been designed for Beaufort Sea conditions and had been given air quality permits by the U.S. Environmental Protection Agency. Partly because it lacked a suitable vessel that had its permits, Shell put the Beaufort Sea on the back-burner for its proposed 2013 drilling, and focused on the Chukchi Sea. The company was unable to return to the Chukchi for the 2013 and 2014 open-water drilling seasons because of pending new federal regulations on drilling.

OCS leases have 10-year terms and the Chukchi Sea sale was in 2008, but the lease clock for all three companies with leases in the Chukchi has been frozen until BOEM completes a supplementary environmental impact statement, or SEIS, for the 2008 Chukchi Sea OCS Sale 193, according to U.S. Bureau of Ocean Energy Management officials.

The revamp of the original environmental impact statement for the sale was challenged in court by environmental groups who argued the assumed size of a discovery, and the size of a possible oil spill, were underestimated in 2008 by the U.S. Minerals Management Service, the predecessor agency to BOEM.

The agency is now redoing the estimates. A draft SEIS is expected this fall and a final document by next March, BOEM has said.

“All of the Chukchi Sea leases, including the (Shell) Burger prospect, were put into suspended status. This status will remain in effect until the Bureau meets its obligations to correct the Sale 193 EIS consistent with the U.S. Ninth Circuit’s opinion and the direction of the (federal) district court,” said a BOEM official, who asked not to be identified because of agency procedures.

The revamp of the 2008 EIS, the more recent development, was ordered by a U.S. District Court judge in Anchorage after the U.S. Ninth Circuit Court of Appeals agreed with the environmental plaintiffs.

The U.S. Mineral Management Service had originally used an assumption that a 1 billion-barrel discovery could be made in the Chukchi, and further assumptions on a possible oil spill were based on that. Environmental groups said the figure was too low, and that the assumptions for the oil spill were also too low.

With the standard 10-year term leases sold in Sale 193 would have expired in August 2019. The new expiration date is unknown and will not be established until the SEIS is issued and approved, the BOEM official said.

The delay in drilling Shell’s top prospects in the Beaufort Sea has implications for Alaska. Oil from any discoveries in the Beaufort could be brought ashore to bolster Trans-Alaska Pipeline System, or TAPS, oil “throughput” much more quickly than oil from any Chukchi Sea discoveries.

The Sivulliq and Torpedo offshore prospects are in the eastern Alaskan Beaufort Sea about 15 miles north of the Point Thomson onshore oil and gas development east of Prudhoe Bay. A pipeline to shore could be built more quickly than a 60-mile Chukchi Sea pipeline to shore, and once ashore the Beaufort Sea oil could be shipped to TAPS through the existing Point Thomson and Badami liquids pipeline.

Chukchi Sea oil, once ashore, would still require a new pipeline across the National Petroleum Reserve-Alaska to the TAPS line.

It would take more than a decade for Chukchi Sea oil, once drilled and discovered, to be brought into TAPS, state officials have said. Beaufort Sea oil, once discovered, could possibly be brought to TAPS in about half the time, they said.

Getting more oil into TAPS is important because TAPS throughput has been declining to the point that there could be operating problems during very cold winter conditions. More oil volumes, no matter from what source, will ease these.

Also, although OCS oil pays no royalty or production tax to the state of Alaska it indirectly increases state revenue because the higher volumes in TAPS lowers the pipeline’s per-barrel tariff for shipping oil. Since that applies to all oil shipped in the pipeline it results in a higher value of oil from state leases on the North Slope, resulting in higher royalties and production tax payments.

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Fairbanks legislator suggests Interior gas pilot project

Elwood Brermer
Alaska Journal of Commerce

A Fairbanks legislator is pushing state officials to market the benefits of converting home heating systems away from fuel oil to Interior residents.

Rep. David Guttenberg said representatives from the Alaska Industrial Development and Export Authority and its sister group the Alaska Energy Authority involved in the Interior Energy Project have expressed concerns over the prospect of a market for North Slope gas in the Fairbanks area at recent meetings.

The Interior Energy Project is the state’s plan to truck liquefied North Slope natural gas to Fairbanks and North Pole as a way to relieve high energy costs and poor winter air quality caused by the region’s dependence on home heating oil.

“It’s the same old dialogue about there’s no gas because there’s no market — no market because there’s no gas,” Guttenberg said in an interview with the Journal.

Fairbanks Natural Gas, which already supplies more than 1,100 customers in the core of Fairbanks with natural gas, and the Interior Gas Utility, or IGU, estimate they will combine to make gas available to about 13,600 new residential customers by 2024. With a much larger distribution build out plan, IGU will be able to supply less than 2,000 residences when first gas is available in late 2016, according to presentations by the utility.

The utilities and the state agencies have said that voluntary residential conversion from fuel oil to natural gas home heating is critical for the project to create demand and a market for gas to hit AIDEA’s stated goal of a final “burner tip” price of $15 per thousand cubic, or mcf, of gas.

Conversion is expected to be slow in the first years of the project and increase as gas becomes available to more homes. Depending on the type of boiler system a home has, conversion could cost anywhere from $2,300 to more than $10,000, according to a January 2014 study conducted by the environmental consulting firm Cardno Entrix for the Interior Energy Project.

“I proposed that (AIDEA) simply start a pilot program to create enthusiasm for the market,” Guttenberg said.

While his plan would leave the details to the experts, Guttenberg said, for example, the IEP team could choose 100 Fairbanks homes to retrofit and subsidize the changeover. It would be a way to assure people the state is not “spending hundreds of millions towards more studies, more projects that are never going to happen,” he said.

Doing so would also create an anticipation and enthusiasm amongst Interior residents for a cheaper energy supply when gas finally starts rolling down the Dalton Highway, Guttenberg said.

“Get gas to them, make it a very visible project and get people motivated (and asking) ‘Why don’t I have gas?’” he said.

AIDEA and AEA have responded that they are discussing ways to encourage conversion, according to Guttenberg.

The Cardno Entrix study projects 10 percent of residential customers will convert in the first year of each build out phase. In year two, another 40 percent will make the change to natural gas and by the fifth year gas is available 90 percent of eligible homes will be hooked up to the gas distribution system, the study claims.

Another key to the project is what kind of large commercial or industrial demand there is for gas. Golden Valley Electric Association President and CEO Cory Borgeson has said the utility would purchase up to 2.5 billion cubic feet of gas annually as soon as it is available for power generation. That commitment has shrunk since Golden Valley’s Healy clean coal power plant has become a reality.

The likelihood of finding other large customers to make the project viable is unknown, but AIDEA’s team says it is something they are continually working on.

While a plan like the Interior Energy Project has been discussed for years, it came together at the end of the 2013 session when the Legislature passed $332.5 million in bonds, loans and grants to get North Slope gas to the region in Senate Bill 23.

If Guttenberg’s suggestion of a marketing plan with the easiest gas available, likely trucked Cook Inlet gas, takes shape, another funding source would probably be needed as SB 23 specifies all the funds from the legislation must be used to get North Slope gas south.

A Democrat, Guttenberg said Gov. Sean Parnell could make subsidized conversions a reality if he wanted.

Spending up front to market a product is something done successfully in the private sector every day, he said.

“Act like a normal entity. Act like someone who is trying to create a market for your product,” he said. “Get the enthusiasm going; that’s basically it.”

The fact that Interior’s energy crisis hasn’t yet been solved should be blamed on Alaska’s recent leadership, he said, and is one of the “failings” of the Parnell administration.

“When oil hits $100 and above and you’re in that neighborhood and you’re getting billions of dollars of extra revenue as far as I’m concerned you have an obligation to build an economy,” Guttenberg said.

“You hear from the (Fairbanks) Chamber of Commerce and everybody the one thing holding down development is the cost of energy.”

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Sunday, July 13, 2014

Producers erase decline for FY 2014

Tim Bradner
Alaska Journal of Commerce

In a dramatic development, North Slope oil producers have essentially erased a long-term decline trend that has existed for all but one year since 1989 when two new oil fields began producing in 2002.

An intensive effort in “workovers” of producing wells, to stimulate production, and drilling of new producing wells in the large producing fields, has hiked production over what was expected by the state Revenue Department.

The estimated daily average for fiscal year 2014, which ended June 30, is 530,939 barrels per day compared with the average of 531,639 barrels per day in fiscal year 2013.

With production through May confirmed for eleven months of fiscal year 2014, and preliminary data from June based on daily production tickets, the estimated decline for the North Slope for the fiscal year is calculated at 0.13 percent, or essentially zero, said John Tichotsky, chief economist in the Department of Revenue. The 2013 fiscal year had a decline of 8.2 percent.

The 0.13 percent decline estimate is the second-best annual performance since 1989. There was a 2.6 percent increase in fiscal year 2002 when the Alpine field operated by ConocoPhillips and North Star field operated by BP began producing.

Passage of a change in the state’s oil production tax in 2013, in Senate Bill 21, is being credited for increased activity on the Slope, but a leading critic of the tax change, State Sen. Bill Wielechowski, D-Anchorage, dismissed the new data.

“While the industry may be successful in slightly increasing production before the referendum vote (to repeal the new tax) in August, the fact is that the long-term projections by the (Gov. Sean) Parnell administration show a 45 percent decline in oil production over the next decade,” Wielechowski wrote in an email.

However, the state’s official long-term production estimates, published annually in November, were put together before the new tax law took effect and do not reflect the level of response shown by the companies recently.

Alaska voters will decide whether to repeal SB 21 on the Aug. 19 primary ballot, with a yes vote to repeal and a no vote to keep it in place.

“The number one statistic that matters most to Alaskans is production, not forecasts or projections. The news that we have ‘stopped the drop’ in our oil production for the first time in more than 10 years is no surprise to those of us who believe creating a competitive investment climate will bring more rigs, more jobs, and more oil to the state.

“Proof of this concept is now out for everyone to see; oil tax reform is working,” said Kara Moriarty, president and CEO of the Alaska Oil and Gas Association. “More production also means more royalties going into the Permanent Fund, as a result of the change. It’s also another compelling reason to vote no on ballot measure 1 on Aug. 19.”

On June 10, in a press release, Wielechowski also said he would drop his opposition to SB 21 if the industry produced one barrel of new production above the 2013 average of 531,000 barrels and it resulted in new revenue.

“If SB 21 produces new oil, even ONE new additional barrel, and this production results in new revenue to the state, we will drop our support for revising oil taxes, Wielechowski said in the June 10 release.

State Sen. Hollis French, D-Anchorage, joined Wielechowski in issuing the release.

The revenue picture will take some time to finalize, but the first estimate shows the producers missed Wielechowski’s challenge by only 701 barrels in the per day average.

State agencies monitor oil production closely because about 90 percent of state revenues come from oil royalties and taxes. The Alaska Oil and Gas Conservation Commission, an independent state regulatory agency, supervises and tests the meters that measure the flow of oil.

The long-term average decline from the North Slope fields has been about 6 percent since 1989. Last December, forecasters in the Department of Revenue, anticipating better performance from producers based on the tax change, estimated that the fiscal year ending June 30 would see a 4.4 percent average decline.

The buildup of production surprised state officials. By March and April it appeared there might even be a slight net increase over last year but June production rates are somewhat down because of maintenance on production facilities. That results in a lower production rate for that month, although the barrels will eventually be produced.

Tichotsky said the figures may look a little better when the official June production numbers come in.

“The production for June and all of 2014 will be officially finalized sometime in the first week of August, when the June production off-take reports come in, and will likely be slightly higher and bring us closer to one-tenth of a percent of a zero decline,” he said.

By comparison, one-tenth of a percent is within the 0.25 percent margin of error range for the meters that measure the oil production.

Tichotsky said state economists Loren Crawford and Tim Harper, in the Revenue Department’s Economic Research Group, compiled the production numbers.

A number of new oil development projects have been announced for the North Slope since mid-2013, when SB 21 passed the Legislature, but it takes time for new projects to be approved by company boards of directors and to secure permits for construction.

ConocoPhillips, one of two major North Slope operators, has three new projects planned that will result in a net addition of 40,000 barrels per day of new Slope production by 2018, according to Scott Jepsen, the company’s vice president for external affairs.

BP Exploration Alaska, which operates the large Prudhoe Bay field, is planning a major development project in the western part of the field that will eventually add 40,000 barrels per day of production, the company has said.

In the short-term, however, both BP and ConocoPhillips have boosted production through more intensive drilling and workovers of existing wells. Both companies have added more drilling rigs and boosted activity levels.

BP’s work on projects to boost well production is up 20 percent over last year, and spending on “production-enhancement” work is up 40 percent, company spokeswoman Dawn Patience said.

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