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Pumping Up TAPS: First, can the decline be halted? BP, Conoco operate 98% of northern Alaska oil production: can it be done without them? Analysis by Kay Cashman Petroleum News
Before determining if it’s possible to increase flow in the trans-Alaska oil pipeline from projected 2011 levels of about 605,000 barrels a day to 1 million barrels, the governor’s goal, it’s important to first determine if the decline in North Slope production can be halted — specifically, stabilized without increases in investment from the region’s two major operators, BP and ConocoPhillips, which with ExxonMobil and their smaller partners account for almost 98 percent of the liquids in the pipeline.
Executives from BP and ConocoPhillips say they do not expect to increase their capital spending in Alaska until the state’s production tax is reduced.
BP, ConocoPhillips and ExxonMobil, the largest producers in the fields BP and ConocoPhillips operate, say the state’s production tax — Alaska’s Clear and Equitable Share, or ACES — takes away the incentive to invest at high oil prices, which they are ably demonstrating is true by not increasing capital investment in their North Slope legacy fields.
All three producers support Gov. Sean Parnell’s proposed legislation to, as they describe it, “reform” ACES. House Bill 110 reduces the tax by changing how progressivity is applied, capping it and establishing a lower base rate for new fields.
HB 110’s companion bill in the Senate, SB 49, went nowhere during the first regular session of this two-year legislative term, but is expected to be the major focus of that body in January, when the Legislature convenes.
Detractors of HB 110 say ACES is working, BP and ConocoPhillips are making big profits in Alaska, and that the two largest operators are holding the state hostage with the tax bill.
It doesn’t matter who’s right I say, it doesn’t matter who is right.
The fact is, without added investment by the three largest producers on the North Slope, their production, at least, is going to fall.
But if there are “improvements in the fiscal regime” in Alaska, ConocoPhillips Alaska President Trond-Erik Johansen said Nov. 16, “you will see more action. … You will see more drilling; you will see more projects. … That’s just the way capitalism works.”
So, let’s look at current and projected oil production for the North Slope. (For simplicity’s sake, in this article the “North Slope” includes all oil fields north of the Brooks Range in Alaska, including offshore pools.)
State says 12.4%; BP says 25% In November, North Slope production averaged 624,687 barrels per day, down 6,850 barrels from the 631,537 bpd in November 2010, which is slightly more than a 1 percent drop, month to month. Over the last year throughput in the trans-Alaska oil pipeline dropped 7-8 percent, Johansen said.
The Alaska Department of Revenue’s spring 2011 forecast predicts production will drop from a daily average of 605,000 barrels a day in 2011 to 530,000 barrels a day by 2020, a decline of 12.4 percent.
But Claire Fitzpatrick, chief financial officer and senior vice president of BP Exploration (Alaska), predicts a 25 percent drop in oil production between now and 2020 for BP-operated fields on the North Slope, and a 7-8 percent decline in the next couple of years.
Fitzpatrick reminded attendees of the mid-November Resource Development Council conference that fields operated by BP account for about two-thirds of current North Slope production, meaning she’s in a position to know how much oil is likely to be produced.
What’s the difference? Why the big difference between the Department of Revenue and BP’s production estimates for 2020?
According to Fitzpatrick, Revenue’s estimates include some “big buts” — that 52 percent of the department’s forecast for 2020 is from projects under development or evaluation, including projects in existing producing fields. (See figures 6, 7, and 9 from Revenue’s spring 2011 forecast, which support what she says.)
A lot of the “under development” has not yet had final investment decisions from the owner companies, she says.
So, Fitzpatrick concludes, more than half the oil the state is banking on in 2020 comes with a big “If.”
That means that more than half the production in the spring forecast — and therefore a big chunk of projected state revenues — depends on investments yet to be made.
“I don’t know what the next DOR forecast is going to show in terms of decline over that timeframe. I do know what my forecast shows, and we are showing a steeper decline over that period than I was at this time last year,” Fitzpatrick says.
“We’ve reviewed our plans and activities much more rigorously in terms of what’s possible versus what’s realistic in the current business climate,” she says, meaning some of the projects BP talked to Revenue about prior to the spring forecast are now off the table.
On Dec. 1, Revenue officials confirmed that the latest Revenue forecast, due to be released in mid-December, will reflect a much lower production rate in 2020. (Pumping up TAPS goes to press on Dec. 9, but we’re holding space in the On Deadline section near the beginning of this magazine to report on Revenue’s latest forecast.)
Still, some new oil will most certainly be produced, with or without, a tax change. The ExxonMobil-operated Point Thomson field, for example, will likely be produced under a settlement agreement with the state of Alaska — that’s 2,000 barrels a day in 2015 and 9,000 barrels thereafter, per Revenue’s spring 2011 forecast.
And after all ConocoPhillips’ work to get approval to build a bridge across the Colville River in order to start producing oil from CD5 in the National Petroleum Reserve-Alaska, where it is eligible for ACES tax credits, it’s safe to assume ConocoPhillips will move forward with NPR-A exploration and development. In Revenue’s spring 2011 forecast, that’s 10,000 barrels a day in 2015, 65,000 barrels by 2020, including production from Linc Energy’s Umiat oil field.
Even BP expects to proceed with its Liberty project in federal waters, which Revenue shows at 5,000 barrels a day in 2013, then peaking in 2014 at 39,000 barrels, and dropping to 14,000 barrels in 2020.
Still, a 25 percent drop in two-thirds of 98 percent of North Slope production by 2020 is considerable. And BP, remember, has to approve most of the investments in the ConocoPhillips-operated fields because it’s a working interest owner in many of them. (“Has to approve” is not a legal mandate; but the unit owner relationship is much like a marriage. “Sure you can buy that pool table, honey, but….”)
Oil BP, Revenue not including Production from the only oil fields not operated by BP or ConocoPhillips on the North Slope — Eni’s Nikaitchuq unit, Pioneer Natural Resources’ Oooguruk unit and Savant’s Badami unit — are included in the Department of Revenue’s forecast.
Revenue’s projections put Oooguruk and Nikaitchuq at a combined daily average of 19,000 barrels in 2012, up from 12,258 in November, and peaking at 38,000 barrels a day in 2014.
But Pioneer’s Nuna development, which is inside the Oooguruk unit, and Savant’s Red Wolf prospect, part of the Badami unit, are not in the forecast.
More important, not a drop of oil from the North Slope’s active explorers — Repsol, Brooks Range Petroleum, UltraStar Exploration, ASRC Exploration and Great Bear Petroleum — is included in Revenue’s forecast, per Victoria Ferguson, a petroleum economist with the department.
With the exception of ASRC, all these companies are planning to drill exploration wells this winter; although as of Dec. 1, two of the explorers will probably not be able to find drilling rigs, bumping their wells to the winter season of 2012-13.
Potential production from these seven companies’ projects, some of which are unitized and have been previously drilled, do not meet Revenue’s standards for inclusion in its forecasts, Ferguson says, providing a list of those standards:
A. Reservoir delineation through new penetrations, drill stem testing and seismic.
B. The reservoir should be fairly well defined and proved to have productive capabilities
C. The operator should have fairly concrete development plans in place.
Great Bear production excluded
Despite the Parnell administration’s enthusiasm for Great Bear’s source rock exploitation plans, the company has to prove it can produce oil from the formations on the North Slope, Ferguson says.
“Since production from source rock is considered unconventional, we will wait for some extensive, definitive production data from a pilot project before we forecast any significant production from the Great Bear properties,” she says.
Those standards make sense when you’re looking for absolutes. Even ignoring Great Bear’s very bold production estimates makes sense, although its project could potentially reverse the decline on its own, and more, within the 2015 to 2020 timeframe.
Still, Great Bear is proposing to produce oil from source rock; something that has never before been done on the North Slope. And given the difference in the cost of operating in northern Alaska versus in North Dakota’s Bakken or Texas’ Eagle Ford shale plays, Great Bear might need the tax breaks in the governor’s bill to make its Alaska project economic.
Ed Duncan, Great Bear’s president and chief operating officer, told legislators in February that competition for capital is on a global scale, and while Alaska presents an opportunity for oil and gas investment, “we also see a great opportunity for Alaska to improve its position globally” by making the tax changes proposed in HB 110.
Alaska is prospective for development because “it has some of the best rocks in one of the best petroleum provinces in the world.” But, Duncan says, “it also has some fiscal terms that are suppressing development.”
The risk in Great Bear’s source rock exploitation plans is not technical but “commercial viability in competition for capital (because it) requires capital to make this play really happen,” he says, describing the play as both capital intensive and labor intensive.
“This is an opportunity to deliver a play that has long-lived production; manageable risk; allows the state to forecast forward revenue; (and) has tremendous job growth associated with it — if we can make it happen.”
The objective of Great Bear’s exploration and evaluation program is to run short tests on at least four wells, with those tests potentially leading to the sanctioning of a pilot plant to more fully determine the production characteristics of the rocks, Duncan told Petroleum News in November.
It will be necessary to obtain at least a one-year production profile, determining parameters such as production decay characteristics, as well as assessing the economic feasibility of oil production from the rocks, before making a decision to move to full field development, which he says could occur in 2015.
A 123,000 barrel a day difference If you’re looking to leave ACES as is, you have to know whether the other explorers, all of which have access to adequate funding and two of which are already producing oil in the region, have a chance of filling the gap between 2011’s projected average of 605,000 barrels of oil flowing through the Trans-Alaska Pipeline System, or TAPS, and what will be running through it daily in 2020.
Cutting another 8 percent off 605,000 barrels a day in deference to Fitzpatrick, another 48,000 barrels are deducted from Revenue’s projected 530,000 barrels, for a drop to 482,000 barrels a day between now and 2020.
That’s a difference of about 123,000 barrels a day. (Maybe more, maybe less: Remember to check out the On Deadline section at the front of this magazine with Revenue’s latest forecast.)
In 10 years, Alaska might see some federal outer continental shelf production from Shell, but Shell says that’s only if nothing goes wrong between now and then, and it can drill in 2012. It would be foolish to count on Beaufort and Chukchi OCS oil in the next decade, but if Shell picks up Beaufort Sea leases in the Dec. 7 state sale, as rumored, then it’s possible (see On Deadline).
And trying to keep production flat is not just about state revenues; it’s also about the trans-Alaska pipeline tariff for non-TAPS owners, such as Repsol, Brooks Range Petroleum, Linc, Great Bear and others. The tariff will undoubtedly go up as the cost of the system is shared among fewer and fewer barrels of oil, another disincentive for non-TAPS owners to produce oil on the North Slope.
And if TAPS operator Alyeska Pipeline Service Co.’s low flow impact study is correct (see story on page 23), there is a whole list of mitigation measures that Alyeska will have to implement to keep the pipeline operating as throughput drops below 600,000 barrels a day — costly mitigations that could also raise the tariff.
BP, ConocoPhillips and ExxonMobil own the largest percentages of TAPS, so a higher tariff is not going to sour them on Alaska, as a pumped up tariff has in the past with several oil companies, including Conoco before it merged with Phillips, which in turn purchased the assets of ARCO Alaska.
Repsol hoping for 119,000 bpd So, excluding Great Bear’s potential production, let’s look at possible production in the next 10 years from other explorers, starting with Repsol, which has about 20 prospects on just under 500,000 acres that were identified by minority partners Armstrong Oil & Gas’s North Slope subsidiary 70 & 148 and GMT Exploration.
Oil production from Repsol’s first five exploration projects is scheduled to come online between 2015 and 2018, peaking at 119,000 barrels a day in 2017 or 2018.
The company appears to be drilling its low-to-moderate risk prospects first, although one of the initial five drilling sites was switched out for another where several leases are set to expire.
If the company is only able to permit and drill four of those projects this winter, it is likely to drill the prospect it dropped next winter, along with several others, delaying one project’s production by a year.
Armstrong expects changes in ACES With at least 119,000 barrels a day in the pipe by 2018 or 2019, it appears Repsol will nearly singlehandedly save the day for Alaska.
But what wasn’t said in Repsol’s March 7 press release announcing its deal with Armstrong and GMT was a single word about ACES, although the company did say one of the reasons it entered into the $768 million transaction is because the Parnell administration is looking at ways to make the state more for attractive for oil and gas investment versus trying to squeeze more tax dollars from industry.
Just three weeks before the long-awaited deal closed Armstrong Vice President Ed Kerr submitted a letter to the co-chairs of the Alaska Legislature’s House Resources Committee, saying that the governor’s bill, “HB 110 will have a significant impact on our capital expenditures and future activities in Alaska. 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 said Armstrong has “more than a dozen ideas outside of existing producing units” on its project list, ideas it hopes to drill and test.
“In many cases we know the oil is in place. The improved fiscal terms as provided in HB 110 will greatly affect whether these projects will get developed.”
Presumably the bigger finds will have the best rate of return, so they would get developed under ACES as it is today.
Pioneer’s Nuna Development Also not included in Revenue’s spring 2011 forecast was Pioneer’s Nuna Development within the newly expanded Oooguruk unit. Its primary target is the Torok formation (see page 41).
Original oil in place is estimated to be 340 million barrels in the Oooguruk offshore drill site area and the core area of the unit — the planned initial development area where the Oooguruk-Torok reservoir is completely filled with oil. That oil would be included in Revenue’s projections.
In the prospective Nuna area, the Oooguruk-Torok reservoir appears to be only partially filled with oil; the original oil in place is estimated at 690 million barrels. Pioneer estimates that it can produce up to 25 percent of that through primary and secondary recovery methods, for a net 173 million barrels.
The Alaska Oil and Gas Commission, looking at primary recovery of 20 percent, or 138 million barrels, says the production rate for the Oooguruk-Torok oil pool over an expected 20-30 year project life is expected to average 4,000 to 9,000 bpd, with peak production of about 8,000 to 15,000 bpd, plus natural gas.
Production could conceivably start in 2017, so it would have some bearing in the next 10 years.
A lot depends on appraisal and exploration drilling into the Torok this winter and next.
And on the economic competitiveness of the project with Pioneer’s oil and gas assets outside Alaska.
At a Feb. 16, 2011, House Resources Committee meeting in Juneau, Ken Sheffield, at the time president of Pioneer in Alaska, said the company supports HB 110. He said Pioneer’s challenge is finding the next opportunity to grow its business. The company might have the opportunity to expand its Oooguruk project to produce the Torok accumulation, but a half a billion dollars for Torok would have to compete for funding against other opportunities in the Lower 48 in fiscal regimes where the tax burden is not so high.
So, another question mark.
If BP and ConocoPhillips elect not to increase investment and all the stars align for Repsol, the Madrid-based major stands to produce the most new oil from the North Slope in the next 10 years.
Armfield’s plan 2050 But there is one other explorer whose production could make a dent in arresting the decline, and that’s Brooks Range Petroleum Corp. An active explorer on the North Slope (see page 40), BRPC has drilled five wells and several sidetracks since 2007. It tends to target known, but untapped, fields between 25 million and 50 million barrels close to infrastructure.
Again if all the stars align, it might have two or three fields online in the next 10 years, producing between 5,000 and 12,000 barrels each (numbers not confirmed by BRPC).
In February testimony to House Resources in favor of HB 110, Bart Armfield, vice president of operations for BRPC, talked about his “plan 2050,” which takes an incremental look at what would be required to keep the trans-Alaska oil pipeline flowing at 600,000 bpd through that time.
It’s a phased approach, he said, requiring the cooperation of the state, majors and independents.
If 10 new fields averaging 12,000 bpd are brought on in the next 12 years, that would increase recoverable reserves by half a billion barrels, and require in excess of $6.3 billion in investment.
“History demonstrates that we can” do this, Armfield said, based on what has occurred over the last 12 years with Alpine, Northstar, Oooguruk and Nikaitchuq coming online and Badami restarted.
That isn’t 10 fields, he said, “but collectively they represent the equivalent of 10, 12,000-barrel-of-oil-per-day field projects.”
To get to the next level, 20 years out, requires 22 more fields be brought online.
Armfield said unconventional resource plays and technology developments in the Lower 48 demonstrate what can happen, and said that in the very near future that may be applicable to the North Slope.
By the end of the day, in “plan 2050,” 44 new developments have occurred, requiring more than $18 billion in new investment.
Armfield said the new fields are a combination of developments within existing units and grassroots developments. In the first 12-year phase, if existing units supported four new developments “then new players would support six grassroots developments.”
But the $18 billion to bring on that much new development really requires $36 billion in investment, Armfield said, because “not every project is going to be successful on the North Slope.” He said he used the 50-50 rule, with half failures and half successes, “which is probably very aggressive.”
To get $36 billion of new investment capital coming into the state requires “the positive adjustment through HB 110,” Armfield said.
Other companies agree with BP, Conoco The questions posed at the beginning of this article were, Can the decline be halted? And since BP and ConocoPhillips operate 98 percent of northern Alaska oil production, can it be done without them?
Maybe. If most of the companies exploring, or set to explore this winter, on the North Slope are successful, there might be enough production to halt the decline in the next 10 years, especially if I’m right about Revenue’s fall forecast, so compare the numbers on page 14 with those in the page 8 On Deadline article about Revenue’s fall forecast, which came out after all but those pages went to press.
But, the next question is, will those explorers develop their discoveries under ACES?
Not all of them have answered that question.
But they have all said they need HB 110 to make producing oil in Alaska competitive with investments elsewhere.
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