The Fuse

The DUCs Are Fracking: The Uncertainty Surrounding Drilled but Uncompleted Wells

by Matt Piotrowski | May 06, 2016

Oil market observers are excited, albeit a bit nervous, about the DUCs.

Drilled but uncompleted (DUC) wells have garnered a lot of attention, and for good reason. They represent a massive source of uncertainty regarding price direction and U.S. supply, and their overall impact is completely unknown. Some argue they are overhyped because of logistical and economic barriers, while others believe they will bring about a gusher of supply at a moment’s notice.

Drilled but uncompleted (DUC) wells represent a massive source of uncertainty regarding price direction and U.S. supply, and their overall impact is completely unknown.

The oil market is currently in uncharted territory as the major backlog of DUCs is a relatively new phenomenon. For the most part, before shale, companies drilled a well and completed it as quickly as possible in order to get the crude to market. But the steep price downturn forced many companies to conserve cash—they drilled new wells near or under breakeven prices but didn’t hire crews to complete them. As a result, the current “fracklog” of DUCs has occurred.

Higher oil prices bring about the possibility that a wave of DUCs are brought online in the near future, perhaps relatively quickly, and the uptick in supply could cause another dramatic leg downward for prices. The Energy Information Administration (EIA) sees U.S. crude output falling by .83 mbd this year, or 9 percent, and another .56 mbd in 2017, but the forecast is fraught with risk and may in fact be too pessimistic. While lower prices, company bankruptcies, and staff layoffs certainly undermine the production output, companies have protected themselves with hedging their output during the latest price rise. The DUCs are an additional wild card, which could slow or reverse output declines. That said, there’s also the possibility that shale’s supply losses do indeed become so steep that a burst of production from DUCs has a minimal impact on offsetting those declines.

How many DUCs are there currently?

“Frankly, any definite answer regarding the DUC question is conveying a completely false sense of precision,” analysts at Raymond James wrote last year. With that in mind, it’s important to take any data regarding DUCs with a grain of salt. Most consultancies and analytics firms use data from the different producing states and operators’ earnings reports, which don’t provide a real-time picture.

One often-cited assessment comes from Rystad, an analytics firm based in Norway, which put the total at 4,000 DUCs at the end of 2015. The number peaked at the end of 2014 at 4,500 but fell last year due to rig activity falling faster than completions.

Screen Shot 2016-05-06 at 12.00.37 PMMeanwhile, Platts Analytics says there were an “excess of 6,500” DUCs in inventory at the end of last year, with more than 40 percent in the main shale plays of the Permian and Eagle Ford in Texas. NavPort, an analytics firm that tracks unconventional production activity, puts the total DUC count for oil and gas at slightly more than 8,000 at the beginning of March. Consultancy Wood Mackenzie estimates there are now roughly 3,500 DUCs, with inventory having declined by roughly 700 so far this year. Woodmac breaks the numbers down between “abnormal” DUCs—those that were initially drilled more than three months ago—and “normal” ones, which vary with the rig count and mostly include any well waiting on completion.

At what price will companies draw down their inventory of DUCs?

“DUC strategies differ depending primarily on price assumptions,” says Woodmac. DUCs, according to The New York Times, are “viewed by oil executives as a way to hoard cash as service costs plummet, and are a flexible lever to rapidly increase production whenever oil rises again.”

“DUC strategies differ depending primarily on price assumptions.”

Just last week, for instance, Whiting Petroleum, the top producer in the Bakken, said it would bring down its inventory of DUCs if prices hit $50 and remained there for three months. “$50 per barrel is the price where we would move forward on that,” said the company’s CEO Jim Volcker last week.

“While each producer will behave differently than the next, it seems realistic pricing in the mid-$40-$50 per barrel range they will bring incremental volumes back into the market place,” said Platts Analytics’ Suzanne Minter before the U.S. Senate Energy and Natural Resources Committee last week.

The recent hedging that occurred when contracts along the futures curve shot up past the $40 level may also start a number of DUCs. Further pressure on companies from banks may force operators to keep hedging, a development that could also bring more deferred wells online.

“Operators who have a larger backing can hold on completing wells much longer than wells who are hurting for cash flow right now.”

How much companies will want to spend on completing the DUCs is tricky. The DUCs may ultimately be self-defeating, since they could cause a collapse in oil prices. Strategies are likely to depend on companies’ current financial situation. “Operators who have a larger backing can hold on completing wells much longer than wells who are hurting for cash flow right now,” Amie Sarnese of NavPort told The Fuse. In fact, producers with relatively strong balance sheets are completing enough wells to keep output steady this year, while also creating an inventory of DUCs to use in 2017 when prices are expected to be stronger.

How quickly can they be completed and brought online?

Bringing a DUC to completion takes a bit longer than 30 days, according Platts Analytics, while NavPort (see graphic below) breaks down the average time it takes from spud to completion at 34 days for the Permian and under 30 for the Midcontinent (which includes the Bakken). For the Eagle Ford, however, it’s much higher at 57 days. Even though on average the time to complete a well appears relatively long, companies “have the potential to, and have in the past, completed wells much faster than average,” notes Sarnese.

Screen Shot 2016-05-06 at 11.56.34 AM

The response time varies based on companies’ strategies, how much cash they have on hand, and whether they will be able to hire workers, or “frac crews.” It’s unlikely that all operators will react at the same time given the variety of factors that goes into deciding whether to increase production, so any production boost would likely be spread out over a longer period of time. Moreover, during the current downturn, oilfield service companies have laid off a large number of workers, making it more difficult to increase production swiftly in a higher-price environment.

While DUCs pose an opportunity to stabilize U.S. output, or help it rebound, the rosiest forecasts may not come to fruition.

While DUCs pose an opportunity to stabilize U.S. output, or help it rebound, the rosiest forecasts may not come to fruition. “There will always be an inventory of DUCs, as it is impossible to drill and complete all of the wells in the same month, leaving a small backlog in even the most ideal market,” said NavPort’s Sarnese.

What are the costs of completing DUCs versus drilling new wells?

Woodmac says that WTI breakevens for DUCs are in general one-third lower than those for new wells, although it varies by play, while The New York Times reported that costs are at least 40 percent lower to complete old wells than drill new ones. Minter of Platts Analytics says that 40 percent of costs go into drilling of the well and the rest of the costs go into the completion of that well. The completion includes the process of piping and fracking, allowing for production to actually begin.

In other words, although completion costs are higher than drilling new wells, DUCs are still the cheapest source of production—since initial drilling costs have already been paid—and provide a quick opportunity to boost revenues.

How much production could DUCs ultimately add?

Any production increases from DUCs depends on a variety of factors, including price, company strategies, manpower, and costs.

Richard Westerdale, a director at the U.S. State Department’s Bureau of Energy Resources, said recently that the current log of DUCs could bring some 500,000 barrels per day back into the market.

Any production increases from DUCs depends on a variety of factors, including price, company strategies, manpower, and costs.

In Texas, if all of the state’s DUCs were completed at once, they have the potential to add 1.25 mbd onto the market, according to Minter, whose estimate is based on an initial production rate of 500 bd.

By contrast, Woodmac has more sober expectations. It estimates that with the 1,700 abnormal DUCs, they can add roughly 300,000 bd of shale output. The roughly 1,800 normal DUCs would likely contribute about the same amount, but they are part of the “continuous contribution” of production and don’t necessarily represent “pent-up” supply.

“DUCs will contribute a decent amount of production, but that will be overwhelmed by losses in the lower 48 states,” Alex Beeker of Woodmac told The Fuse. His firm estimates that output in the lower 48 will fall by 1.2 mbd from mid-2015 to the end of 2016. Without the addition of output from the DUCs, the declines would be steeper.

Could shale surprise to the upside again?

Since U.S. tight oil, or shale, came online earlier this decade, it has consistently defied expectations. Its resiliency has been tested throughout the price crash with rigs being idled, companies going into bankruptcies, and capital expenditures getting cut. Shale’s decline over the past year has been slow and steady and more losses are likely in store.

But does it have the potential to surprise to the upside yet again? With prices having rallied and with expectations for higher prices for next year, will DUCs be able to stabilize output or bring about another wave of supply online? We’ll soon find out.