Drilled but Uncompleted Wells (DUCs), Explained

A shale well is built in two stages. A drilling rig bores the hole, runs casing, and moves on. Later, a separate completion crew fractures the rock and connects the well so oil or gas can flow. A drilled but uncompleted well, a DUC, is a well stuck between those two stages: the expensive hole exists, production does not. The count of DUCs in the seven US shale regions the EIA tracks ran from 4,505 wells in December 2013 to a peak of 8,894 in June 2020, then drew down to 4,494 by February 2024 and sat at 4,510 in April 2024, the last month in the EIA workbook series this site mirrors. Every one of those figures comes from the site's own EIA database, and every table below can be checked against it on our rig counts page. This guide explains what the count measures, the one-line arithmetic that moves it, why the inventory ballooned and then drained, how to convert it into months of completion work, and how to read the monthly change without over-reading it.

1. What a DUC is, in the EIA's terms

The EIA added DUC estimates to its monthly Drilling Productivity Report (DPR) in September 2016, and its definition is plain: DUCs are wells that producers have drilled but have not yet made ready for production. Making a well ready means the completion process: casing and cementing the wellbore, perforating the casing where production should enter, hydraulic fracturing to open flow paths in the rock, and the hookup work that lets the well produce into a gathering system. A well can sit as a DUC for weeks while a pad is finished, or for years while an operator waits on crews, pipelines, or prices.

The DPR covers seven regions: Anadarko, Appalachia, Bakken, Eagle Ford, Haynesville, Niobrara, and Permian. In the EIA's description, those regions together account for nearly all US tight oil and shale gas production, which is why the DUC count is read as a national shale indicator rather than a regional curiosity. Four of the regions are oil-dominant (Bakken, Eagle Ford, Niobrara, Permian) and three lean to natural gas (Appalachia, Haynesville, plus the Anadarko mix). Our Baker Hughes rig count explainer covers the drilling side of the same system. The rig count tells you how fast new holes are being started. The DUC count tells you how big the backlog of finished-later holes has become. The two series answer different questions, and confusing them is the first misread this guide comes back to in section 9.

Two properties of the EIA series matter before any number gets quoted. First, the DUC figures are estimates, built by the EIA from well records, and the agency revises them as better records arrive. A level quoted from an old report and the same month quoted from the current workbook can differ. Second, the workbook this site mirrors (the EIA's duc-data.xlsx) ends with April 2024. This page therefore treats the series as a complete record of the 2013 to 2024 inventory cycle and labels every figure with its month. Nothing below presents April 2024 as the current 2026 level, because the source cannot support that claim. The mechanics the series illustrates, drilled versus completed, backlog versus drawdown, are the same mechanics any future DUC reporting will run on.

2. The arithmetic: drilled minus completed

The DUC count is an inventory, and it obeys inventory arithmetic. Wells drilled in a month flow in. Wells completed in a month flow out. The change in the inventory is the difference:

Change in DUCs = wells drilled - wells completed

That is the whole model, and the EIA publishes all three numbers by region each month, which means any reader can reconcile the inventory instead of taking it on trust. The last month of the site's series, April 2024, is a clean example because almost nothing happened: the seven regions drilled 864 wells and completed 858, so the inventory rose by 6, from an implied 4,504 to 4,510. A flat month looks like that. The interesting months are the ones where the two flows pull apart. In June 2020, drilling had collapsed to 325 wells, a fraction of the 1,034 drilled in December 2019, but completions collapsed further, to 257. An industry shutting down still added 68 wells to its backlog that month, because the second stage stopped harder than the first. Through 2021 the flows reversed: completions beat drilling in all twelve months, and the inventory fell every month, from 7,492 in January to 5,243 in December. No rig-count reading alone reconstructs that year. The drilled and completed flows do.

Source for every figure in this table: the site's database copy of the EIA DUC workbook, seven-region totals. The cover-ratio readings built from the same flows are in section 6.

3. The full cycle: build, peak, drawdown

Read across a decade, the series tells one story in three acts. The build came first. The inventory rose from 4,505 in December 2013 to 6,367 by December 2015 and 7,937 by February 2019, as multi-well pad drilling spread and operators drilled wells faster than completion crews finished them. The EIA noted in 2019 that most of the growth sat in the oil regions, above all the Permian, where pipeline takeaway limits in 2018 gave operators a physical reason to drill wells they could not yet produce into a pipeline. By December 2019 the backlog stood at 8,542 wells with drilling still running ahead of completions, 1,034 against 888 that month.

The peak was a shutdown artifact. When demand collapsed in the spring of 2020, operators cut drilling hard, and cut completions harder. June 2020 shows the result: 325 wells drilled, 257 completed, and the inventory topping out at 8,894. A rising DUC count in that context did not signal confidence. It signaled that the second stage of the industry had stopped faster than the first. The regional detail in the next section shows the same shape at basin level: the Permian alone peaked at 3,521 DUCs in July 2020, and the Eagle Ford at 1,656 in May 2020, both far above where either would end the series.

The drawdown ran for nearly four years. Completions exceeded drilling in every month of 2021, pulling the inventory from 7,492 in January to 5,243 in December while drilled wells recovered only gradually, 452 in January 2021 to 750 by December. That is the DUC mechanism doing the job the EIA described when it launched the series in 2016: a large backlog lets supply respond to recovering prices without waiting for rigs to remobilize, because the holes already exist. The draw slowed once the backlog thinned. Flows balanced through 2023 (1,044 drilled against 1,050 completed in January 2023), and the inventory bottomed at 4,494 in February 2024 before closing the published series at 4,510 in April 2024, within 16 wells of where it began in December 2013. A full round trip in ten years, with the peak almost exactly double the trough.

4. Where the wells sat: regions at the end of the series

The seven regions did not share the cycle evenly. The table below puts each region's April 2024 inventory next to its own series peak, both computed from the site's EIA database. Two regions ended the series near their peaks for opposite reasons, and the oil regions that drove the build gave most of it back.

Two cautions ride on this table. The EIA's region definitions in the workbook group Appalachia as one region, where the DPR's production tables split the Marcellus and Utica plays, so regional DUC comparisons should stay inside this one dataset. And the regional rows sum to the seven-region total the EIA publishes as its DPR Regions line, 4,510 in April 2024. Anyone quoting a US total near double that figure has added the total to its own parts.

5. Why operators drill wells they do not finish

A DUC is drilled capital waiting on a decision, so the reasons for holding one are the reasons the second stage gets deferred. The EIA's own writing on the series names the main ones, and each maps to a pattern in the data. Lease and rig contracts can require drilling to hold acreage or to satisfy commitments made to landowners, which keeps the first stage running through a price fall; the 2015-16 build in the Bakken and Niobrara backlogs, peaking at 928 and 877 wells, fits that pattern. Completion crews are a separate, scarcer resource than rigs in a hot market, and a shortage of frac crews leaves drilled wells queued; the EIA flagged crew availability during the 2017-19 build. Pipeline takeaway works the same way from the other end: a well completed into a full pipeline produces into weak local prices, so the Permian backlog ballooned while the basin's takeaway was constrained in 2018 and drained after new capacity arrived. Price timing is the fourth reason: completion is the larger remaining cheque on many shale wells, and an operator facing a wellhead price below its completion break-even can park the well and wait.

A fifth reason is operational, and it produces DUCs in healthy markets too. Modern shale development drills several horizontal wells from one pad. The rig drills the batch back to back, then moves to the next pad while a completion crew finishes the batch behind it, sometimes completing wells in sequence so the fractures interact as designed. In that workflow every well spends part of its life as a DUC by plan, and a rising count can simply mean more pads are mid-batch. This is why the level alone cannot tell you whether the backlog is strategy or stress. The flows and the cover ratio in the next section narrow it down: a planned queue turns over fast, a stranded backlog ages.

The worked example below is a labeled hypothetical that shows why an operator might park a drilled well on price alone. It uses round teaching numbers, not any company's actual costs.

Hypothetical example (illustrative numbers only): Suppose a drilled well needs a completion that costs $4 million, and suppose the operator expects the completed well to sell its early production at a wellhead netback of either $38 or $52 per barrel depending on when it starts. The barrels do not change; the revenue against the same $4 million completion cheque does. At the lower netback the operator may rationally wait, holding the well as a DUC, if it expects the higher netback within a period the lease allows. Multiply that single-well decision across a drilling programme and a price fall becomes a rising DUC count without a single contract being signed. Real decisions add decline curves, hedge books, midstream commitments, and debt covenants. The example isolates one lever, price against remaining cost, because that lever is the one the inventory data can actually show you working.

6. Months of completions: turning a count into a clock

A raw well count mixes regions with very different completion rates. Dividing the inventory by the month's completions converts it into time: how many months of completion work the backlog represents at the current pace. Call it cover. It is a computed ratio from the same EIA flows, not an EIA-published figure, and it reads like this:

Cover (months) = DUC inventory / wells completed that month

The June 2020 row is the warning label for the whole method. Cover divides by a monthly flow, so when the flow collapses the ratio explodes without the queue changing much. Use cover when completions are running at something like a normal pace, and treat any cover reading printed during a shutdown as a measure of the shutdown. With that caution, cover is the fastest way to compare eras: the market carried eight to ten months of queued completions in the late 2010s and about five months by 2023-24. A thinner queue means production responds to price with less of a head start, which is the supply-timing point the EIA made when it launched the series.

7. What DUCs do to supply timing

The supply chain from a price signal to new oil runs through three clocks. Mobilizing a rig and drilling a well takes months. Completing a well that is already drilled takes weeks of crew time once the crew is scheduled. Producing a completed well starts as soon as it is connected. A large DUC inventory shortens the chain because the slowest clock, drilling, has already run. That is the mechanism behind the 2021 data in section 3: completions ran between 741 and 988 wells a month through 2021 while drilling recovered from 452 to 750, so new supply could be brought forward by working the backlog instead of waiting for the rig fleet. Our Permian Basin production outlook and the global production data show the output side of that response.

The same mechanism caps itself. Working a backlog down is a one-time transfer: each completion both adds near-term supply and removes one unit of future optionality. Once the inventory thins toward the level operators hold for pad logistics, the short clock disappears and the supply response goes back to rig speed. The series shows the transfer completing: cover fell from 9.6 months in December 2019 to about 5 months by 2023-24, and the inventory itself halved from its peak. Anyone modelling a fast shale response to a price spike off 2019-vintage DUC levels would be spending a cushion the data says is gone. Regional detail matters for the same reason: the Haynesville ended the series at its own high of 791 wells while the Eagle Ford fell to 345, so a gas-weighted completion wave and an oil-weighted one are different stories hiding inside one national total. The rig-count intelligence hub routes between the rig, basin, and DUC views when the monthly data moves.

8. Reading the monthly change: a checklist

The EIA series is monthly (the last published month in the site's copy is April 2024; the routine applies to any month of the series and to any successor release). Run the steps in order:

1. Reconcile the change. Check that the inventory move equals wells drilled minus wells completed for the month (April 2024: 864 - 858 = +6). If it does not reconcile, the EIA revised a prior month or a region definition moved. Find out which before interpreting anything.
2. Name which flow moved. A rising count from drilling ahead (December 2019: 1,034 drilled, 888 completed) means something different from a rising count during a completion stop (June 2020: 325 drilled, 257 completed). Same arrow, opposite industries.
3. Split oil regions from gas regions. Compare Permian, Bakken, Eagle Ford, and Niobrara against Appalachia and Haynesville. The April 2024 table shows why: the national total looked calm while the Haynesville sat at a series high and the Eagle Ford near a series low.
4. Convert to cover, with the shutdown test. Divide the inventory by the month's completions. If completions fell sharply that month, the ratio is measuring the stop; wait for a normal completion month before quoting cover.
5. Cross-check the rig count. DUCs rising while rigs fall points to contracts, crews, or takeaway. DUCs falling while rigs are flat is the 2021 pattern: supply responding off the backlog, which our rig counts page and the rig count explainer let you verify side by side.
6. Write one defensible sentence. Level, direction, which flow drove it, and cover: for example, "The seven-region inventory closed the published series at 4,510 wells in April 2024, up 6 on balanced flows, at about 5.3 months of completion cover." If a slot cannot be filled from the release, say what is missing instead of strengthening the adjective.

9. Four common misreads

Misread 1: "DUCs rose, so production is about to surge." A rising count means the backlog grew. Production responds when completions rise, which is the opposite flow. June 2020 posted a record inventory and a collapsing completion rate in the same month. Watch completed wells for supply; watch the inventory for how long a completion pace could be sustained.

Misread 2: "Every DUC is a finished well waiting for a valve." The count treats a well drilled last month on an active pad the same as one drilled years earlier. The EIA count carries no lateral length, no rock quality, no age, and no record of whether the operator still intends to finish the well. Old, short, or poorly placed DUCs may never be completed. The inventory is an upper bound on quick supply, not a promise of it.

Misread 3: "The US total is about 9,000 wells." That figure appears when the seven-region total is added to its own regional parts. In April 2024 the regions summed to 4,510, the same number the EIA publishes as the DPR Regions total. Any DUC figure should be traceable to either the regional rows or the published total, never both added together.

Misread 4: "A 2024 level describes the 2026 market." The workbook this site mirrors ends with April 2024, and shale inventories can be worked down or rebuilt within a few quarters, as 2021 proved. Quote DUC levels with their month attached. A level without a date is how a drawn-down cushion keeps getting spent in analysis years after the data says it thinned.

10. Frequently asked questions

What is a DUC well?

DUC stands for drilled but uncompleted well. The wellbore has been drilled, but the well has not yet been made ready to produce. Completion is the second stage: casing, cementing, perforating, and hydraulic fracturing, followed by connecting the well so oil or gas can flow. The EIA counts DUCs monthly in the seven Drilling Productivity Report regions.

How is the DUC count calculated?

It is inventory arithmetic. Each month, wells drilled add to the count and wells completed subtract from it, so the change in DUCs equals wells drilled minus wells completed. In April 2024, the last month in the EIA workbook series this site mirrors, the seven regions drilled 864 wells and completed 858, so the inventory rose by 6 to 4,510.

Why do companies drill wells and not complete them?

The EIA has pointed to rig and lease contracts that require drilling to hold acreage, a shortage of completion crews during busy periods, pipeline takeaway limits that leave nowhere for new production to go, and price timing, where an operator waits for a better wellhead price before paying for the completion. Pad drilling also creates DUCs on purpose: a rig drills several wells from one pad, then a completion crew finishes them as a batch.

Are DUCs a reliable signal of future production?

They are a timing signal, not a production forecast. A large DUC inventory means supply can respond faster than the rig count alone suggests, because completing a drilled well takes weeks rather than the months needed to drill and complete a new one. But the count says nothing about lateral length, rock quality, or how old each well is, and the EIA revises its estimates. Read DUCs next to the rig count and completion rate, not on their own.

What happened to DUCs in 2020 and 2021?

In the EIA series this site mirrors, the seven-region inventory peaked at 8,894 wells in June 2020. Drilling had collapsed to 325 wells that month, but completions had fallen further, to 257, so the backlog kept growing. Through 2021 the pattern reversed: completions ran ahead of drilling in all twelve months, and the inventory drew down to 5,243 by December 2021 on the way to a low of 4,494 in February 2024.

Why does the DUC data on this page end in April 2024?

PetroEyes mirrors the EIA DUC workbook (duc-data.xlsx) into its own database. That workbook series ends with April 2024 data, so April 2024 is the latest month this site can show from that source. The tables here are labeled with their month for that reason. Treat the levels as the end point of the published series, not as a live count for 2026.

11. Related reading

• Rig Counts and DUC Dashboard - the site's weekly Baker Hughes rig data with the basin and DUC breakdowns this guide explains.
• Baker Hughes Rig Count, Explained - the drilling side of the system: what the weekly census counts, basin splits, and how to read the trend that feeds the DUC queue.
• Rig Count Intelligence Hub - the topic hub routing between rig counts, basin activity, and DUC inventory context.
• Permian Basin Production Outlook - the output side for the region that held 3,521 DUCs at the 2020 peak and 893 as the series ended.
• How to Read the EIA Weekly Petroleum Status Report - the weekly inventory release, read alongside the monthly drilling data covered here.
• Analysis: Energy Data and Market Trends - the running EIA inventory series for crude, Cushing, SPR, and natural gas storage.