Alaska Gov. Sean Parnell has articulated a goal for Alaska of a million barrels a day of oil flowing through the Trans Alaska Pipeline system, TAPS, a decade from now. Three and a half decades ago in 1977 oil started moving through TAPS from the North Slope to the Lower 48 (and very occasionally other) markets, increasing every year until it peaked at just over 2 million barrels a day in 1988. In almost every year since then, the North Slope has produced less oil than the year before, with the result that 2002 was the last time TAPS averaged over 1 million barrels per day. In the decade since then production has fallen to around 650,000 bpd.
One way to think about this challenge is to assume a flat base of 635,000 bpd. To return to 1 million bpd means that every day, for 365 days a year over the next date decade or 3,650 days, Alaska must add 100 bpd of new production. No Saturdays and Sundays off, every Monday there must be 700 more barrels in the pipeline than the previous Monday. However, instead of a flat base year to year North Slope production is declining at almost that same rate the governor wants it to grow by. Currently everyday on average 100 fewer barrels — rather than 100 more barrels — go into TAPS than the day before. (6 percent decline times 650,000 barrels/365 days a year). The latest Department of Revenue forecasts project North Slope production at roughly 500,000 bpd by 2020. That means that Alaska would need to add well over 100 bpd of production more than is currently forecast very day of the decade to be producing at a million bpd by decade’s end.
Is this possible? Here are five scenarios.
1. Giants Needed
While Alaska needs more than an additional 100 bpd of new production every day it is not likely to achieve that through thousands of small producers — each producing 100 bpd bringing a new well on daily. In fact the easiest way is to find another supergiant field like Prudhoe Bay — or a field even half the size of Prudhoe Bay. In 1988 when the entire North Slope was producing 2.1 million bpd, 1.6 million bpd was coming from the single field at Prudhoe Bay.
Giant oil fields are generally considered to be those that produce over 500 million barrels over their lives: The definition of a supergiant is a little looser but generally it’s a field that is an order of magnitude larger or 5 billion barrels. The Prudhoe Bay field — which has already produced 15 billion barrels and has billions left — definitely meets the definition of a super giant.
The next biggest field on the North Slope is Kuparuk, which has produced about 2.5 billion barrels — so it is a giant, in fact a very large giant, but not a 5 billion barrel plus supergiant. Several Kuparuk like fields would have to come on line over the next decade to meet the 1 million bpd goal. However, if the Department of Revenues Forecasts are to be believed, the more typical North Slope giants will prove to be Endicott (brought on line in 1988), Alpine (2001) perhaps even Milne Point (on line in 1986) or Point Thomson (yet to come on line). It would take five more of these typical giants — one every other year for the next decade — to reach 1 million barrels. This is a considerably different pace than the historical rate of essentially one new giant every 10 years.
2. Changing the game: Technology beats finding giants.
Looking in the rearview mirror at how production has matured over the first 35 years of TAPS’ life may be a good reality check. But firmly planting one’s eyes on the rearview mirror means a lot can be missed. In the Lower 48 new technology is already proving to be a game changer. Horizontal drilling has already made its mark on the North Slope. Roughly speaking the amount of exposure a well has to the rocks it is trying to produce from, the more production there will be. Resources spent drilling down to those rocks are wasted resources, if multiple side tracks can reach the same or a larger area. Horizontal wells are on average much more productive greatly reducing the cost per well and the cost per barrel produced.
Hydraulic fracturing or fracking is a new technology which builds on the notion of increasing the contact between the well and the area it is trying to drain. The fracturing process can be thought of as expanding the well bore into the surrounding rock through thousands of hairline factures. The process uses water under very high pressure to fracture the rock and increase the flow of hydrocarbons out of the well. Again this process also makes wells vastly more efficient: twice as productive or more than older wells.
Traditional methods typically recovered less than 50 percent of the original oil in place; the needle is shifting to above 50 percent. Rocks that couldn’t produce enough oil economically using the old technologies can be exploited with the new technologies — frequently these are the lower porosity and permeable shales. It is not so much that we find another giant as that technology transforms what would have been considered uncommercial or small fields into a giant; or giants get transformed into supergiants. In the Lower 48 things are changing so quickly that no one seems to quite understand how these two technologies are going to transform the oil and gas business.
In the world of gas, it has taken less than half a decade for “the unconventional to become the new conventional.” In the Lower 48, people speak of gas coming from “gas factories” — exploration risk has all but disappeared and the focus is on technical methods of removing the vast quantities of known gas — all without spending millions of dollars to drill new vertical bores down through miles of rock hoping to find gas.
How will this play out in Alaska? Great Bear is doing a great job of articulating its plans and hopes for Alaska development of unconventional shale oil resources. Undertaking a 15-year program drilling 200 wells a year (3,000 wells total) will deliver a peak of 300,000 bpd dropping down to a steady state of 150,000 bpd. According to a presentation given to the House Resources Committee, on Feb. 18, 2011, if a year round access to drilling emerges from the Roads to Resources program so that drilling starts in 2013, a decade from now they will be producing roughly 175,000 bpd (and on a rising rather than falling curve.)
Using the Great Bear figures which were based on incentives generated through credits, the application of these new techniques may replace the need for a giant field or two (of the five required) in our quest for 1 million bpd. There are all kinds of other unconventional reserves on the North Slope — parallel technical breakthroughs might produce similar new oil flows. However, none has working and growing exemplars in the Lower 48 the way that the shale processes do.
3. Does gas in barrel-of-oil equivalents count?
What about gas making up the difference in barrel of oil equivalents? The last section touched on new technologies to exploit gas resources. As gas has become easier to produce (combined with a simultaneous macro-economic easing of demand as a result of recession) more has been produced. The result, as any competent economist would have predicted, is that the price of natural gas has fallen. That it is not a stretch to call this phenomenon revolutionary is confirmed by the fact that simultaneously oil prices have stayed at unprecedented high levels.
Frequently in management texts one finds the notion of setting goals within constraints. If the governor really wanted TAPS to move 1 million bpd and there were no other constraints, this would be a perfect testing ground for all the rhetoric about setting the private sector free or seeing what the private sector can produce without having to carry the state’s government as an operating cost. The state could announce a zero royalty rate, and exempt all production from production, income and property taxes — and do it through constitutional mechanisms that would assure investors that increased production, not revenue was Alaska’s only long term goal — surly this would bring about enormous increases in investment, and eventually production. But at what cost? The state finances upwards of 90 percent of its unrestricted general fund budget from oil revenues — and oil flows without those revenues would be worse than pointless to many Alaskans.
Unfortunately, getting barrel of oil equivalents from gas could have directionally the same effect. Why? As mentioned above, the value of gas has fallen so dramatically in relation to oil. To keep the math simple, a project to export 4.2 billion cubic feet a day of gas (with a heating value of 1000 Btu per thousand cubic feet) is the energy equivalent of 700,000 bpd. Adding that production to Alaska’s exports would put the state at over 1 million bpd equivalent. The bad news is that using late 2011 prices that much gas would sell for roughly $2 million a day. On the other hand, 700,000 barrels of oil would sell for almost 40 times that or $80 million a day. Here is not the place to run that through the intricacies of the state’s fiscal system: suffice it to say, that at these prices the state’s revenues would fall dramatically if the production shortfall were made up with gas equivalent through a gas line to the Lower 48.
4. Other People’s Oil
The Chukchi and Beaufort seas are the Outer Continental Shelf, OCS, off the northern coast of Alaska which has proven phenomenally expensive — and disappointing — to explore in the past. Estimates of the potential prize are huge and explorers want to take another look. For example the National Energy Technology Laboratory published estimates for the Beaufort in the “supergiant” range of 5 billion barrels of oil, with the Chukchi even higher. Shell, for example, wants to invest billions in the area and has spent the better part of a decade in the field, before regulatory agencies and in the courts, trying to acquire all the required permits. Assume for a moment that Shell (1) works its way through all the barriers and actual explores, (2) indeed finds the equivalent of a supergiant field and (3) decides to move it to market through TAPS — all within a decade. This might well fulfill the governor’s vision of a million barrels a day in TAPS. However, because the oil does not come from land which the state either owns and/or has taxing power over, the oil that we rely on for the production taxes, income taxes and royalties that pay for state government may continues to decline at a precipitous rate.
Unlike the situation with gas described above, the state can and probably would remedy that situation. Consider FY 2010 when according to the Department of Revenue, 240 million barrels of oil were produced in the state and generated $4.9 billion in unrestricted oil revenues. Roughly $4.8 billion or $20 dollars a barrel came from production taxes, income taxes and royalties, while 50 cents a barrel came from property taxes — practically all of that from taxes on TAPS as it passed through the unorganized land outside of the North Star, North Slope and Valdez boroughs.
If TAPS is filled mostly with non Alaskan-produced oil, then the remedy from the state’s point of view would be to shift its taxing strategy away from production tax and toward a tax on TAPS. The Alaska Department of Revenue currently forecasts the TAPS tariff to rise from about $4 a barrel to something close to $6 a barrel a decade from now (coupled with a continuing decline in throughputs.) Simply adding OCS barrels to the mix should drive the per barrel cost of running the pipeline downwards. On the other hand the state might make the pipeline tariff more like cigarettes today — where more than half the purchase price goes to taxes. Tobacco Free Kids reports that Anchorage has the third highest combined state and local cigarette taxes in the nation, and there is no reason to think Alaska would not have a similar view toward TAPS. A million barrels a day through TAPS with each barrel paying $6 in state taxes would generate over $2 billion a year, which would make up for a lot of foregone production taxes and royalties.
This would be a dramatic example of changing tax policy and that leads to the current day and the current debate in the legislature and the actual implementation one of the governor’s five planks: fiscal reform.
5. Beyond hope and hype — actually delivering investment deals
Economists point out that, all other things being equal, the less something is taxed the more of it will be produced, and the more it is taxed the less that will be produced. On Alaska’s North Slope that approach can be tricky — it is not a closed system where incremental dollars earned from selling North Slope oil can either go to the state’s capital budget or go to the lease holders’ capital investment budget. Just as the initial investments in Alaska’s oil production were funded by profits generated elsewhere in the world, as Alaska matures disinvestment can occur and the profits generated and not taxed away here can go to fund investments in other parts of the world
We can contrast two views of government’s role: in one the government creates the environment and investment climate it wants, and hopes for the best outcomes over time. If it is not getting enough investment it moderates the tax take in favor of investors. Or it may test in the opposite direction and see the effect of increased tax on investment.
The alternative approach derides this passivity, and argues that Alaskans, acting through state government, need to more actively develop these resources. Alaska should take risks proportional to its rewards.
Being more practical than ideological, of course the state’s actual policies blend — or muddle — these two ideas. For example Alaska currently sets taxes and hopes it will attract sufficient investment. However, any fine tuning with the fiscal environment in investors favor is viewed by some as a “giveaway” unless the state receives guarantees and promises from the industry for more investment. Of course promises and guarantees are the language of contracts. In the world of contracts, a promise is only extracted in exchange for another promise. In short it leads the state to the opposite philosophy of government driving development: by making mutual promises with investors. If the investor promises to invest, the state promises to set limits on its take from the investment.
Politically there has been a great deal of confusion surrounding these efforts at mutual promises — both the Stranded Gas Development Act under the Knowles and Murkowski administrations and the Alaska Gasline Inducement Act under the Palin and Parnell administrations have experimented with this latter managed policy — so far to little effect, generally because while politicians feel quite comfortable asking for guarantees and promises from putative investors, the state has proven quite unwilling to make broad promises about future revenue streams.
To achieve the kind of significant production growth envisioned by the governor, we will probably need both to lower the high incremental rates associated with progressivity — and assure potential investors that the lower rates will remain in place after the investments have taken place.
There are at least two ways of doing this — both probably requiring constitutional amendments. Section 9.1 of the Alaska constitution states that “The power of taxation shall never be surrendered. This power shall not be suspended or contracted away, except as provided in this article.” The people of the state could take the constitution’s authors up on their challenge and enumerate the conditions under which that precious power of taxation would be temporarily suspended or contracted away: what kind of promise and performance would an investor have to undertake before being promised some kind of fiscal stability.
The second would be to erase the notion that the oil industry is responsible for keeping the state in whatever style it becomes accustomed to. Despite a spending (appropriation) limit in Section 9.16 of the Alaska constitution — according to figures from Legislative Finance Division, it took just three years of increasing revenues between 2005 and 2008 for governors Murkowski and Palin to double Alaska’s general fund, GF, spending from $2.6 billion up to $5.5 billion. In the four years since then governors Palin and Parnell oversaw continuing increases that put the 2012 unrestricted GF budget at $6.7 billion. Putative investors are going to be very concerned where Alaska’s politicians and voters will turn to sustain that kind of spending in the face of either falling production or price correction.
Investors might be reassured if instead Alaska moved more toward the Norwegian Model: treat all oil and gas revenues as incremental and set them aside, only to be drawn on through a restrictive formula.
Alaskan voters have focused on this part of the constitution amending it in 1976 by adding Article 15 — the Alaska Permanent Fund, in 1982 adding the Appropriation limit mentioned above and in 1990 adding the Article 17 — the Budget Reserve Fund. Perhaps what is needed now is an amendment that puts all oil and gas revenues into the Budget Reserve Fund (or a successor fund) and then limits the rates at which that fund could be drawn down and used to fund government operations. In other words, provide an investor with the knowledge that the current year budget shortfalls would not be balanced by increasing taxes on oil and gas projects.
Conclusion
How likely is that the state can turn a 100 bpd of decline into 100 bpd of growth? Pointing out some of the barriers to achieving that kind of growth may lower unreasonable expectations. It will not be pretty if the citizens of Alaska are led to believe that they are poised on the brink of an additional 100 bpd going into TAPS every day for the next decade. If that kind of growth doesn’t occur, it would be unfortunate if the blame fell on those companies that did invest and produce more oil in Alaska. The paths to reach a million bpd over the next decade are difficult ones.
