Ten years ago Petroleum News published a “roll call” of oil and gas companies doing business in Alaska. In the five preceding years the number had dropped by more than one-half, from 19 active companies in 1991 to nine in 1996.
Today, the number of active companies in the state is 31.
In 1996 Petroleum News defined “active” as a true oil and gas company, not a land speculator — i.e. a firm with the means to actually explore and develop its Alaska acreage or the ability to attract partners to fund exploration and development.
“Active” not always operatorBut “active” did not necessarily signify an operator; rather it included companies that might have been capable of operating in Alaska or raising the funds to do so, but chose instead to remain at least partly in the background and allow a lead partner to do the drilling.
In identifying the 31 oil and gas companies currently involved in exploration, development and/or production in Alaska, Petroleum News used similar criteria — plus it excluded companies investing in unconventional hydrocarbon resources in Alaska in order to make the comparison between 1996 and 2006 more analogous.
However, comparing the nine active companies in 1996 to the 31 companies in 2006 still isn’t an apples-to-apples comparison because some of the nine companies in 1996 have since gobbled up one or more of their counterparts, further reducing their numbers by today’s estimation.
For example, ARCO Alaska, Union Texas and Phillips were three of the nine companies still investing in Alaska in 1996 (Conoco was already on the way out). Today, all three companies are part of one company that does business in Alaska — ConocoPhillips — so Petroleum News dropped companies from the 1996 poll vs. adding two companies to the 2006 number, which brought 1996 down to seven.
The same can be said of BP and Amoco, which have since merged, further dropping the 1996 number to six.
But six is a bit misleading because Shell was not included in the 1996 list of active companies since it was selling off its Cook Inlet assets. However, it continued to produce oil until 1998 when it sold the last of its inlet assets to XTO’s predecessor Cross Timbers. So, we bumped the number of active companies in 1996 back up to seven.
Thirty-one not the entire groupThe 31 oil and gas companies with a significant investment in Alaska today are: Alaskan Crude, Anadarko/Kerr-McGee, ARC Energy Fund, Aurora Gas, AVCG/Brooks Range, Benchmark, BG Group, Bow Valley, BP, Chevron/Unocal, Centurion, ConocoPhillips, ENI, Escopeta, ExxonMobil, Forest Oil, Marathon, Petro-Canada, Pioneer, Ramshorn, Renaissance, Rutter and Wilbanks, Savant, Shell, Storm Cat, Swift, Talisman’s FEX, TG World, True North, UltraStar/Winstar and XTO.
Some of these companies, such as Bow Valley, Ramshorn, TG World, ARC and Centurion, are strictly investment partners in Alaska — but each has brought a significant amount of capital to its Alaska joint ventures and reportedly maintains close ties with its Alaska operating partner.
There are other companies that could have been included in the number of oil and gas companies active in Alaska today, but their involvement or contribution is relatively small, or not yet clear or uncertain at this time. They are Andex, Arctic Slope Regional Corp., Devon Energy, GeoPetro and Hewitt Exploration.
There were companies that were excluded in the 1996 count for some of the same reasons, such as Forcenergy, which entered Alaska that year.
23 of the 31 must keep TAPS, state coffers fullTwenty-three of the 31 active companies own North Slope leases or own a chunk of a company that does. Before some unusual production problems that began in July, the northern part of the state was producing about 758,000 barrels of Alaska’s daily crude output, which averaged approximately 775,000 barrels per day in 2006 through Dec. 20. The balance was produced from the Cook Inlet basin in Southcentral Alaska. Its crude is not transported through the 800-mile oil pipeline from Prudhoe Bay to the Port of Valdez.
Only two of the 23 oil and gas companies, ConocoPhillips and BP, are active on the North Slope as operators. In the next two years two more companies will likely join their ranks when, and if, Anadarko and Pioneer bring on two units that are expected to produce a total of 75,000 to 80,000 bpd at their peak. (Revenue’s production from these two fields totals a mere 31,000 at peak, reportedly because the numbers it gets from companies are worst-case scenario for the purpose of royalty relief, etc., whereas Petroleum News picks its production numbers up from analyst conferences.)
State coffers that rely on petro dollars and the minimum rate at which TAPS can operate make what these 23 North Slope investors do over the next 10 years critical.
U.S. and state government forecasts show that North Slope oil production will level off at about 730,000 bpd in 10 years (see chart with this story).
The Alaska Department of Revenue fall forecast shows current North Slope fields will be producing less than half what they are today in fiscal year 2017 — 369,000 bpd vs. the 845,000 bpd they averaged daily in FY 2006. (A fiscal year runs from July 1 to June 30. FY 2006 ran from July 1, 2005, to June 30, 2006.)
Fields under development are projected to deliver 119,000 bpd in FY 2017, as compared to zero oil in FY 2006.
The third component was prospects under evaluation for development. Revenue has them producing 242,000 bpd in FY 2017.
In its fall forecast Revenue said it breaks production down this way “so that the reader will have an understanding about the uncertainty associated with the production forecast. We continue to forecast production of those reserves that have already been discovered and at minimum are being evaluated for development.”
What’s not in the forecastBut “just as important,” the department said, is what it doesn’t include in its forecast.
It does “not include any viscous oil from the 20 billion barrel Ugnu field, which is in the evaluation mode, and less than 5 percent of the viscous oil known to exist in the 10 billion barrel West Sak field.”
Also absent, Revenue said, is any production from known federal offshore oil fields Hammerhead, Kuvlum and Sandpiper, “all of which could provide revenue-sharing to the state and help sustain the Trans-Alaska Pipeline System throughput.” (Shell has renamed Hammerhead and hopes to evaluate the prospect for development in FY 2008.)
Revenue also does not include any future production from unannounced discoveries or undiscovered fields, including those in the 1002 area (coastal plain) of the Arctic National Wildlife Refuge and the National Petroleum Reserve-Alaska. (The only well in the 1002 area is a tight hole, as are most of the wells drilled in the last few years in NPR-A. A tight hole is a well for which no information on its results has been released.)
A small amount of NPR-A production was included in the forecast from information state agencies have received from companies with discoveries in NPR-A, specifically 7,000 bpd from Alpine West by FY 2010, peaking at about 12,000 bpd in FY 2012. (Approximately half of Alpine West is on state land.)
From the rest of NPR-A the department included only 10,000 bpd by FY 2011 peaking at 65,000 bpd by FY 2015. (The state only receives production/severance and property tax on drilling rigs, etc. from NPR-A, which is a federal petroleum reserve.)
Revenue predicts only 6.5 billion to 7.5 billion barrels of recoverable oil will be produced from Alaska’s North Slope between now and 2040-2050, respectively, which it said is “a conservative estimate of the remaining potential Alaska.”
It is conservative in light of two facts:
• proven reserves from the Arctic Alaska Petroleum Province are more than 7 billion barrels of oil and 35 trillion cubic feet of natural gas, and;
• the U.S. Geological Survey estimates another 50 billion barrels of liquid petroleum (oil and natural gas liquids) remains to be discovered in northern Alaska, distributed almost equally between the federal offshore area and combined onshore and state offshore areas.
USGS credited NPR-A with 12 billion barrels of total liquid petroleum.
Another 4.4 billion barrels is expected to come from the central North Slope, east of NPR-A and west of ANWR, where a number of independents are currently exploring close to existing infrastructure.
The 1002 area is anticipated to hold more than 10.5 billion barrels.
In the federal offshore the Chukchi Sea is credited with more than 15 billion barrels and the Beaufort with more than 8 billion barrels.
Industry observers say if prices remain above $40 per barrel, costs level out, and the tax and incentive structure is reasonable, there is no reason Alaska can’t eventually produce the 1.4 million barrels a day that the trans-Alaska oil pipeline can handle with pump modifications that would only take two years to complete.
With more significant modifications, pipeline operator Alyeska Pipeline Service Co. said the 800-mile line could take a throughput of up to 2 million barrels of oil per day, which is close to its peak throughput of 2.1 million barrels in 1988.