The Impact Of DUC Completions On 2016 Crude Oil Production

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Includes: OIL, USO
by: Stephen Rhodes

Summary

An estimated 2,000 drilled-but-uncompleted oil wells existed at the end of 2015.

If 1,500 DUCs are completed in 2016, inventory will not normalize to 23 days of refinery capacity until the end of the year.

Assuming conversions commence in January, March inventory will reach 534 million barrels, approaching the storage capacity limit of 551 million barrels.

One of the imponderables in assessing 2016 projected U.S. crude production, inventory levels and price is the number of drilled-but-uncompleted (DUC) wells that will be brought into production over the next year. There is no precise data as to the size of the DUC inventory, North Dakota being the only producing region that tracks uncompleted wells, 969 at the end of November. However, various analysts have developed numbers ranging up to 5,000. This article attempts to determine, at current rig count levels, how long it will take to bring crude oil inventory down from its current level of 30 days of refinery demand to a normalized 23 days, with and without DUC conversions.

The analysis below will show that with no further decline in rig count, and even without DUC conversions, inventory will continue to increase through March reaching 514 million barrels. With conversions, inventory will reach 534 million barrels in March, approaching the working storage capacity of 551 million barrels, before beginning to decline. The upward pressure on inventory comes from increasing production in the Gulf of Mexico and the Permian Basin, which more than offset declining production in the rest of the United States. Even with only 200 active rigs, the Permian is so productive that output will continue to increase throughout the year, with or without DUC conversions. However, before getting into projected inventory levels, we look first at the DUC phenomena.

The DUC Population

Bloomberg Intelligence released this chart in April 2015:

A more recent study completed by Jeffries provided the following table:

Neither of these presentations distinguishes between oil and gas wells. Note that Jefferies qualifies their estimate with the comment that the actual number of DUCs is probably twice the 2,557 given in that the inventory of DUCs was derived from well pads rather than individual wells.

The most recent, and perhaps the most comprehensive, analysis is by Raymond James Research and focused on oil DUCs alone. Raymond James estimated the number of oil DUCs at the end of 2015 as between 1800 and 2200, and provided estimates of the impact of oil conversion on production under three different scenarios: 1300, 900 and 500 Ducs converted starting in January 2016:

We use the Raymond James study for this analysis, assuming 1,300 DUCs are completed beginning in January. Raymond James viewed the conversion of more than that as unlikely as it would have too severe an impact on the market.

Before looking at specific production and inventory levels driven by the Raymond James chart we should comment on the drivers for conversion. First, DUCs likely came about as a result of contracted rigs that had to be utilized even if low prices made well economics unfavorable. If rigs are under contract and their costs are sunk, it makes sense to use them. Drilling requires about 1/3 of the total well cost of $6 to $7.5 million, a lost cost if the rigs are not used. The E&P can come back to frac and connect the well when prices improve.

Second, even if pricing does not improve there is an incentive to complete wells before reserve based loan redeterminations. Completed wells can contribute to proven, developed, and producing (PDP) reserves and thus raise the borrowing base.

Third, although North Dakota has extended the abandoned well limit from 12 months to 24, other states have not followed suit. The prospect of well close-in costs, not withstanding lease losses, further increases pressure to complete the wells even if economics are not favorable.

Other Production and Inventory Assumptions

In an earlier article I presented an inventory analysis assuming that U.S. production would be flat except for the four basins consisting of the Bakken, Eagle Ford, Niobrara and Permian. Production for these basins was calculated using EIA projections of rig productivity and legacy decline rates, assuming that rig counts would hold constant. It also assumed net imports would remain constant and refinery demand would increase 2% over the prior year. This analysis uses the same basic approach, but with some refinements that improve on the prior assumption of constant production outside the four basins.

Alaska: Alaska production is assumed to continue to decline at its recent historical rate of 6% per year.

Gulf of Mexico: EIA provided a detailed forecast of offshore GOM production in March, 2015 as shown here.

In that off shore wells are long lead development projects, and that recent GOM production is consistent with the March, 2015 forecast, we will use it for this analysis, excluding the hurricane related shut-ins.

Four Basin Production: Production in each of the four basins is based on the current rig count, rig productivity, legacy decline rates, and the past three month rate of change of productivity and decline rate. These parameters are shown in the table below. It is noteworthy that under these assumptions, Permian production continues to increase through-out 2016, even without DUC conversions, whereas the other basins experience continuing production declines. Assuming 200 active rigs after March, Permian production increases, December to December, from 2,023 MBpd to 2,077 MBpd. The table below summarizes the assumptions used. Note that several of the parameters change from February to December as mix among the four basins changes.

February

December

BASIN

Bakken

Eagle Ford

Niobrara

Permian

Combined

Combined

Rigs, February 16

44

79

25

200

348

348

Rig Productivity Bbl/mo

712

785

694

412

573

638

Mo Rate of Change, %

1.0

1.3

2.4

0.9

1.5

1.2

Monthly Decline Rate, %

5.6

11.0

11.0

4.1

7.0

6.3

December 15 MB/d

1,141

1,292

415

2,023

-

4,871

December 16 MB/d

881

790

251

2,077

-

3,999

Table by author. Data from EIA.

Other Lower 48 Onshore Production

The detail available for production in Alaska, GOM and the Four Basins is not available for the remaining production in the Lower 48 (L48), except for some minor volumes coming out of three other basins monitored by the EIA. L48 production and rig level for the past two years is displayed in the graph below. Series 1 (red) shows rig count, expanded by a factor of ten, and series 2 (blue) displays production in MBpd.

We see that L48 production has been nearly flat during this period, even in the face of a steep rig decline. We expect production to decline at the December rig count of 157, versus the average of 375 rigs for the period, but it is not apparent in the graph. It appears, however, that 375 rigs were needed to offset legacy decline and keep production flat. If we knew rig productivity we could infer the decline rate, and obviously the higher the productivity the higher must be the decline to keep production flat. However, we don't know rig productivity we must make an assumption.

My objective is to find an outer bound as to when inventory will be reduced to a normalized 23 days of refinery demand. Accordingly, for L48 we use the lowest productivity and decline rate among the 4 Basins, namely those associated with the Permian.

Graph by author. Data from EIA and BH. Series (1) production, series (2) rigs x 10.

Production With and Without DUC Conversion

Consolidation of Production Data

We pause here to consolidate the above data and project production by month through 2016, first assuming no DUC conversions and then adding conversions. We obtain the following:

Alaska

GOM

L48

4 Basin

No DUC

DUC

+DUC

Month

Mbpd

Mbpd

Mbpd

Mbpd

Mbpd

Mbpd

Mbpd

Oct-15

496

1,624

1,962

5,045

9,127

-

9,127

Nov-15

526

1,625

2,067

4,966

9,184

-

9,184

Dec-15

526

1,635

2,156

4,871

9,188

-

9,188

Jan-16

523

1,650

2,132

4,767

9,073

130

9,203

Feb-16

521

1,650

2,110

4,654

8,934

215

9,149

Mar-16

518

1,645

2,089

4,545

8,798

300

9,098

Apr-16

516

1,645

2,071

4,446

8,677

360

9,037

May-16

513

1,640

2,053

4,358

8,565

420

8,985

Jun-16

510

1,640

2,037

4,282

8,469

470

8,939

Jul-16

508

1,635

2,022

4,215

8,380

420

8,800

Aug-16

505

1,635

2,008

4,157

8,306

375

8,681

Sep-16

503

1,630

1,996

4,107

8,236

330

8,566

Oct-16

500

1,630

1,984

4,065

8,179

310

8,489

Nov-16

498

1,625

1,974

4,029

8,126

290

8,416

Dec-16

495

1,625

1,965

3,999

8,084

280

8,364

We see that the DUC conversions add a peak production amount of 470 Mbpd in June.

Effect on Inventory

To see the effect of these production levels in inventory add a few more factors.

Imports

To forecast production we were able to incorporate physical parameters such as rig productivity and well decline rates, except for rig count which depends on commercial decisions of drillers. Adding the caveat that rig count remains constant gave us a fixed outcome based on understandable parameters. No such parameter exists for net imports. Will foreign refineries move to stabilize their supply base by importing US crude? Will Saudi Arabia counter US export growth with even more aggressive pricing to US customers? These commercial decisions are unknowable in advance. Hence, this analysis assumes net imports remain constant at the average level of the last quarter of 2015, namely 6,955 Mbpd.

Unaccounted

The EIA incorporates a "plug" factor to reconcile enumerated production and imports against changes in inventory. During the past year that figure has ranged between (119) and 470 Mbpd. These two extremes occurred in the last two months, and may be due to some needed shake out in new statistical methods the EIA adopted recently to improve production reporting. This factor is unpredictable, and like net imports, we use the average of the last three months of 2015, which is a positive adjustment to production of 257 Mbpd.

Refinery Demand

Monthly refinery demand is assumed to be 2% higher than the prior year level.

Impact on Inventory

The table below shows how these various elements combine to effect US crude oil inventory. The first table develops inventory levels assuming no DUC conversions.

No DUC

Net

Not

Total

Refinery

Month

Mbpd

Crd Imp

Accounted

Available

Input

US Inv

DOI

Oct-15

9,127

6,649

420

16,196

15,485

482,810

31.2

Nov-15

9,184

6,882

470

16,536

16,300

489,424

30.0

Dec-15

9,188

7,334

(119)

16,403

16,606

482,324

29.0

Jan-16

9,073

6,955

257

16,285

15,916

493,738

31.0

Feb-16

8,934

6,955

257

16,146

15,647

508,198

32.5

Mar-16

8,800

6,955

257

16,012

15,808

514,501

32.5

Apr-16

8,683

6,955

257

15,895

16,377

500,033

30.5

May-16

8,574

6,955

257

15,785

16,603

474,703

28.6

Jun-16

8,481

6,955

257

15,693

16,810

441,205

26.2

Jul-16

8,395

6,955

257

15,607

17,162

392,995

22.9

Aug-16

8,324

6,955

257

15,536

17,047

346,140

20.3

Sep-16

8,256

6,955

257

15,468

16,521

314,560

19.0

Oct-16

8,202

6,955

257

15,414

15,794

302,775

19.2

Nov-16

8,151

6,955

257

15,363

16,625

264,902

15.9

Dec-16

8,112

6,955

257

15,324

16,938

214,859

12.7

From the table we see that without DUC conversions inventory will normalize to a normalized 23 days of refinery input in July. Now let's see what happens with DUC conversions thrown in.

+ DUC

Net

Not

Total

Refinery

Month

Mbpd

Crd Imp

Accounted

Available

Input

US Inv

DOI

Oct-15

9,127

6,649

420

16,196

15,485

482,810

31.2

Nov-15

9,184

6,882

470

16,536

16,300

489,424

30.0

Dec-15

9,188

7,334

(119)

16,403

16,606

482,324

29.0

Jan-16

9,203

6,955

257

16,415

15,916

497,768

31.3

Feb-16

9,149

6,955

257

16,361

15,647

518,463

33.1

Mar-16

9,098

6,955

257

16,309

15,808

533,992

33.8

Apr-16

9,037

6,955

257

16,249

16,377

530,150

32.4

May-16

8,985

6,955

257

16,196

16,603

517,562

31.2

Jun-16

8,939

6,955

257

16,151

16,810

497,801

29.6

Jul-16

8,800

6,955

257

16,012

17,162

462,146

26.9

Aug-16

8,681

6,955

257

15,893

17,047

426,365

25.0

Sep-16

8,566

6,955

257

15,778

16,521

404,072

24.5

Oct-16

8,489

6,955

257

15,701

15,794

401,184

25.4

Nov-16

8,416

6,955

257

15,628

16,625

371,250

22.3

Dec-16

8,364

6,955

257

15,576

16,938

329,027

19.4

With DUC conversions normalization of inventory will be delayed four months to November.

Conclusion

The presence of drilled-but-uncompleted wells will delay production declines normally associated with reduced rig counts until the end of 2016. We can expect any upward pressure on WTI price to be suppressed as the price improvement triggers conversion of the DUC inventory. Accordingly, assuming no further reduction in rig counts, any return to $40+ WTI should not be expected until late in the year.

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.