hy does a company invest billions of dollars in a remote and frigid place thousands of miles from market and connected to the rest of the world solely by air and a skinny 400-mile dirt road?

For ConocoPhillips, the answer is simple.

“We produce oil here because that’s where the oil is,” says Natalie Lowman, director of communications for ConocoPhillips, Alaska’s largest oil and gas producer.

The company started operating on the Kenai Peninsula in the Swanson River fields and ran a liquefied natural gas plant in Nikiski until 2018. Today, its operations are all on the North Slope, where ConocoPhillips owns just over a third of the Prudhoe Bay Unit and 28.5 percent of TAPS. It also owns 94.5 percent of the Kuparuk River Field, the second-largest in North America, and owns the Alpine field entirely. The company is one of the largest holders of federal and state leases in Alaska.

But Alaska’s massive oil resources on the North Slope are inextricably tied to the region’s remoteness and extreme weather, which drive up exploration and production costs. A general rule of thumb is that it costs between $35 and $40 to produce a barrel of oil and get it to market, according to Kara Moriarty, president and CEO of the Alaska Oil and Gas Association.

“Transportation costs are around $9 of that $35,” she says.

And there’s only one way to get the oil to market: through the 800-mile-long pipeline to Valdez and then via ocean-going tankers. In 2019, an average of 490,366 barrels of oil traveled through the pipeline every day, about a quarter of its capacity, according to Alyeska Pipeline Service Company. The pipeline, which went online in 1977, was designed to have a lifespan of thirty years. However, its owners—ConocoPhillips, BP (which is in the process of divesting its Alaska assets to Hilcorp), ExxonMobil, and Unocal—are studying ways to expand its life even as throughput falls, which could raise transportation costs even more.

In the Lower 48, production costs are similar, with shale oil somewhat more expensive. But Texas alone has more than two dozen refineries and a network of pipelines—in addition to easy access to roads, trucks, and boats—that makes transportation much more efficient. And while fracking is a more expensive way to produce oil, those costs are coming down as well, Moriarty says.

Smaller operations in the Lower 48 are also more nimble. “They can ramp up and ramp down really fast. We don’t have that same capability. You need bigger fields and you need a bigger find and a bigger investment up front and then you expect that well to produce,” she says.

Operators in the Lower 48 may have hundreds of rigs, far more than on the North Slope. When COVID-19 hit, Lower 48 operators just shut down, losing 500,000 barrels a day of production, Moriarty says. While oil companies shuttered much of their exploration efforts on the North Slope, the producing wells are still active around the clock.

Simply operating on the North Slope is difficult, Lowman says. There is no infrastructure other than what the oil companies have built.

“The location is remote, the climate is extreme, workers must be flown 600-plus miles from Anchorage to get to work,” she says. Once on the North Slope, most workers are on two-week shifts, during which they live in company housing. Workers in North Dakota and Texas also frequently live in mancamps at remote fields. The biggest difference is that their personal truck is often parked right outside and they can get in it and go for a drive after their shift is over.

Alaska’s environmental regulations are stringent, which adds to the cost, but are reflected in a culture of safety fostered within the oil companies and the relative lack of spills and accidents, despite the harsh environment.

The weather affects every aspect of life on the North Slope.

“Most equipment is special-built for sustained operations in subzero weather,” Lowman says. “Rigs are enclosed and oil processing facilities are in buildings to allow operation in the continuous subzero temperatures experienced in the winter time. Blowing snow closes road transportation for days at a time in the winter.

“The supply chain is long and costly and requires significant upfront planning to make sure equipment is onsite when needed. At -35°F, all outside work shuts down. For structures exposed to cold, low temp steel is required.”

Most exploration on the North Slope can only be done in the winter, Lowman says.

“Since there are no roads beyond those needed to operate the existing fields, ice roads and pads are constructed in the winter and wells are drilled from the ice pads,” she says. “The ice roads and pads cost tens of millions of dollars to construct—and melt every summer.”

Seismic studies are also conducted in the winter to avoid damage to the sensitive tundra. North Slope winters are brutal, with temperatures hovering well below zero most of the season and wind chills that can cause dips to -100°F. The sun stays below the horizon for weeks.

Last winter, ConocoPhillips built about 160 miles of ice roads, Lowman says.

“There is a short window in which to execute an exploration work program,” she explains. “Ice roads open in January and typically close in late April, so the window of opportunity to get the work done is just three months, depending on weather.”

In the Lower 48, by contrast, exploration can be done year-round.

Another major difference is land ownership. Most of Alaska’s oil fields are on state and federal land and require extensive and expensive permitting. Oil companies spend millions of dollars acquiring leases. In North Dakota, for instance, the state’s first oil field was discovered in a farmer’s wheat field by “wildcat” drillers in 1951. That was the first well in the Williston Basin, although it, too, was delayed by several blizzards, according to the American Oil & Gas Historical Society.

The earliest wells in the Bakken shale formation, thought to be the second largest domestic oil resource after Prudhoe Bay, were drilled on another farm about five miles away two years later.

In both Alaska and the Lower 48, advances in drilling technology have been a boon. The methods of fracking and horizontal drilling have boosted production.

For the Bakken shale formation, traditional vertical wells weren’t the answer. A shale formation is “conventional, light-sweet crude oil trapped 10,000 feet below the surface within shale rock,” according to the Energy Policy Research Foundation. In the formation, a layer of oil-bearing sandstone is sandwiched between two layers of shale.

Horizontal drilling techniques were developed in the 1980s. Bakken yielded its oil through a combination of horizontal drilling and fracking, the practice of injecting liquid at high pressure into the rock to open oil-bearing fissures. The US Geological Survey estimates the formation to contain up to 11.4 billion barrels of technically recoverable oil, although some estimates are far higher.

In Alaska, this spring ConocoPhillips was preparing to deploy a massive extended reach drilling rig dubbed “The Beast,” also known as Doyon 26, when the COVID-19 pandemic shut down most North Slope operations except for wells in production. Doyon 26 can reach 35,000 feet horizontally, which would allow it to drill wells in a 125 square mile area from one surface pad.

“Developing oil from the North Slope’s legacy fields and new satellite fields has become increasingly challenging, capital-intensive, and technology driven,” Lowman says. “In addition, our ongoing efforts to renew aging facilities and pipeline infrastructure in order to ensure long-term safety and operational reliability will continue to require significant capital investment.”

The lack of infrastructure outside core developed areas also makes exploration of the National Petroleum Reserve in Alaska challenging.

“New processing plants, roads, gathering lines, living quarters, airstrips, drill sites, and pipelines are required to develop remote fields like Willow,” she says.

Some oil processing facilities can also be trucked in, but the larger ones are transported to the North Slope on seagoing barges and then moved by land to their sites.

“The sealift of barges can only be done during a short window in the summer, which adds complexity to the logistics and construction planning,” Lowman says. “If a sealift window is missed, the project could be delayed by a year.”

Moriarty has been with AOGA for fifteen years, and she says a ballot initiative that is planned for this fall is the fifth initiative dealing with Alaska’s oil tax structure.

“Honestly, I think it’s probably one of the most dangerous yet,” she says. It would force a 150 to 300 percent rise in production taxes, as well as change the way companies can calculate deductions. It also would in effect make the records of any business working in the oil fields—whether it’s an oil company, supplier, or trucking company—a matter of public record.

A constantly changing tax regime makes it even more difficult for Alaska’s oil producers, Lowman says.

“The threat of increased production taxes is on the table virtually every year, and this creates uncertainty for oil companies in planning their future investments,” she says. “If the ballot measure passes, it will result in a significant tax increase on the Prudhoe, Kuparuk, and Alpine fields, even at these low prices. This will put a brake on future investment and stall recovery of work activity on the North Slope.”