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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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