The 10-year itch

Cook Inlet R-to-P ratio may make users nervous, but it spurs investment

By Kristen Nelson

Petroleum News

There is a lot of concern in Cook Inlet about running out of natural gas — gas for electric utilities, gas for home heating and gas for industrial use.

Dealing with that concern is an issue for ConocoPhillips and Marathon, who applied in January for a two-year extension of the export license for their Kenai Peninsula liquefied natural gas plant.

Scott Jepsen, ConocoPhillips Alaska’s Cook Inlet manager, says the concern is because natural gas supplies in the Cook Inlet basin are transitioning from oversupply to what is normal in the Lower 48, a 10-year supply.

Cook Inlet’s situation is similar to what occurred in the Lower 48 in the 1970s, alarming users but prompting drilling, Jepsen told a March 8 joint meeting of The Alliance and the Resource Development Council.

It’s a transition stage between a supply of gas so large that there is no incentive to drill and a supply of gas which — without any additional drilling — would last about 10 years, a close enough sales window that industry is interested in exploring for and developing more gas.

“In the mid-‘60s, basically the Lower 48 was a stranded gas resource,” he said. “But over time we burned through that oversupply” and by the mid-1970s, the reserves-to-production ratio was about 10 years: at the rate natural gas was being consumed, known reserves would last about 10 years.

There were a number of short-term reactions when the supply dropped to 10 years, Jepsen said: price controls were instituted to prevent rapid price rises, utilities quit expanding service and pipelines took expensive take-or-pay contracts to ensure they had supplies for their customers.

The price of natural gas did go up, and companies began drilling because by the 1970s if you “drilled and developed natural gas, you had a pretty good prospect of selling it without displacing somebody else from the market and you’d get a good price for it,” he said.

The number of wells drilled for natural gas in the Lower 48 about trebled in the 1970s.

“The market responded,” Jepsen said. “And eventually the price controls went away; people … stopped being concerned about natural gas supply and we’ve basically been at that R-P ratio now for about 30 years.”

An R-P ratio that encourages investment

Natural gas was discovered in Cook Inlet as companies explored for oil in the 1960s, so much natural gas that the LNG plant owned 70 percent by ConocoPhillips and 30 percent by Marathon was built to provide a way to commercialize some of that gas, as was the Kenai Peninsula fertilizer plant.

Those industrial facilities, along with the Southcentral utilities, have been burning gas since the 1960s.

Cook Inlet, Jepsen said, is now about where the Lower 48 was in the 1970s.

In the early 1980s the R-to-P ratio for Cook Inlet had dropped to about 30 — 30 years worth of supply at 1980 production rates.

Today, he said, the inlet is trending down to an R-to-P ratio of about 10.

What’s happening? “We’re concerned about price. We have issues about not letting contracts go forward that have an arms-length price negotiated. We have concerns that we’re going to run out of gas” for the industrial facilities and the utilities. “We have concerns that exploration’s not going to fill the gap.”

“We’re in that same uncomfortable position that the Lower 48 was in, in the mid-1970s,” Jepsen said.

“I think we’ll transition into a period where we get more comfortable with the supply and demand balance,” he said.

If you find gas today you can sell it

In 2002, he predicted that the next five years “would say an awful lot about what’s happening in this industry,” because in 2002 you could, for the first time, find gas in Cook Inlet and sell it for a good price.

In the 15 years before 2001, Jepsen said, “there was almost no exploration and development of gas fields in Cook Inlet.” The price wasn’t all that robust and with a high R-to-P ratio, there wasn’t any point in looking for gas because to sell it you’d have to price somebody else out of the market.

But starting in 2001, 2002, “we started to get that R-P ratio of about 10.” If you found gas, you could sell it for a price high enough that there was an incentive to drill for gas.

As a result, some 75 exploration and development wells have since been drilled for gas. At a nominal price of $3 million to $5 million per well, that’s a $200 million to $350 million investment in wells, he said. “That doesn’t count compressions, line looping, drill sites, roads, pipelines etc.” Jepsen said that his back-of-the-envelope estimate is that $300 million to $500 million has been invested in the last few years looking for gas in the inlet.

Why not shut the gas in?

In that 2009-2011 timeframe, Jepsen said, the two companies have some 120 million to 150 million cubic feet a day of natural gas that they need to sell.

“We can sell a portion of it to the utilities, but not the lion’s share,” he said. “The vast majority of it we have to basically shut in.”

So why not shut the wells in until the gas is needed?

The answer, Jepsen said, is water. The experience of every operator in the inlet is that “if you shut in a producing gas well, you’re asking for trouble.” That trouble, he said, comes in the form of water, because a lot of the gas wells in Cook Inlet have started to produce a little water. “And the first rule of thumb when you’re producing a gas field that’s producing water is outrun that water,” produce the gas before the water takes over.

“If you shut in these wells, water’s going to continue to encroach, even if you’re not producing,” Jepsen said, and that causes “catastrophic failure of the sands.” Sand fills the well bores and production can’t be restored from those wells.

“In order to go back in you have to essentially drill replacement wells” and those wells aren’t always successful, risking the “deliverability of reserves if you have to shut in these wells.”

Why a two-year extension?

As to why the companies have applied for a two-year extension, Jepsen said a two-year export license extension doesn’t require the companies to have a sales contract in place, which means they can focus on getting the extension.

And there’s the transition period Cook Inlet is in with the R-to-P ratio. “It will probably take a couple of years to get more history behind us, to get past this transition point and show that industry does respond the way I think it does.”

Utilities will have contracts negotiated and will feel better about their future supply and in two years there should be clarity about what’s happening with North Slope gas, he said, all of which will help show what Cook Inlet’s long-term energy picture looks like.

“So it may be quite possible we’ll be looking at another extension,” he said. “But right now, we’re at a point of uncertainty and two years I think is more defendable than trying to go out for a longer period of time.”

Application out for public comment

Continued LNG operations supply energy security to Southcentral Alaska because gas can be diverted from the plant in extreme cold weather to meet local needs, Barnes said. It provides flexibility for the future, including continued exporting and perhaps importing and “it’s a reason to continue looking for gas in the Cook Inlet,” he said.

Barnes said DOE will look at two areas in approving the expansion application: are there sufficient reserves and resources to meet local needs during the export period and does the export overall serve the public interest.

The Alaska Division of Oil and Gas shows 1.6 trillion cubic feet, of proved and probable reserves in its 2006 report, while the Netherland, Sewell analysis done for the companies’ application from public data shows 1.7 tcf, a difference of about 5 percent, Barnes said.

DOE has made some estimates of a total resource of 15-plus tcf and the Colorado School of Mines’ Potential Gas Committee describes the Cook Inlet as having a resource base of about 14 tcf. The Potential Gas Committee cites a minimum exploration add of about 600 billion cubic feet, and a most likely exploration addition of about 1 tcf, Barnes said, while the U.S. Minerals Management Service had a wider range, about 700 bcf to 2.5 tcf.

But, he said, “none of these estimates look at what happens in-field, which is the first place that producers look.”

“Frankly, we’d rather leverage off our existing infrastructure and get the most we can out of existing fields before we step out too far,” Barnes said. The Cook Inlet basin is “highly prospective” for natural gas he said, and current price levels “are encouraging reserves’ growth and aggressive reservoir management to maximize recovery.”

Public interest impacts

But there’s also the upstream component: some 800 to 1,000 upstream jobs on the Kenai Peninsula “drilling wells, operating equipment (and) producing every day.”

The LNG plant is important to long-term supply in Cook Inlet: “it provides a base-load market that can drive exploration and development,” Barnes said. And it provides peaking capacity “at no cost to the utilities.” Providing peak shaving has historically been part of the plant’s license to operate, he said.

Jepsen said that the plant has had a 40-year sales agreement with Tokyo Electric and Tokyo Power and “they understand that we cannot supply them gas unless we supply it to the local economy first. … They’re willing to work with us to make sure that we have gas in the local market,” he said.

On the infrastructure side, the two-year extension provides “an opportunity to use that infrastructure, to keep it, maintain it for future operations, perhaps ongoing export,” Barnes said, as well as the possibility, at some point in time, of “perhaps using it as an import facility, a peak-shaver type opportunity.”