December 8, 2016 • Vol. 6, No. 9docFinder alert
docFinder alert

Well Productivity Gains Trigger Revival in DJ Basin Investment


Noble Energy extended laterals boost returns


November 16, 2016

Full Presentation


Anadarko dramatically cuts costs in core area


November 17, 2016

Full Presentation

Q3 results from major US E&Ps once again provided evidence that the industry is learning how to do more with less. Despite a 70% reduction in capital spending from 2014 to 2016, oil and gas production is expected to remain about level with 2014 output. One widely publicized reason is that drilling and completion and operating costs have fallen 40-50% over that span, a trend we highlighted in a recent docFinder Alert on the Permian Basin. Another factor has been an equally dramatic increase in productivity per well. The EIA’s November Drilling Productivity Report showed that the average new oil well in the seven major unconventional resource plays produced 649 bo/d in that month, 39% higher than the average 466 bo/d in November 2015. Surprisingly, the most significant increase among those seven plays was in the Niobrara shale in the DJ Basin, where new-well oil production per rig increased 50% from about 800 bo/d in November 2015 to 1,200 bo/d in November 2016. This play has been the most under-publicized of the major US resource basins. We decided to explore the activities and production trends of the major regional players, so we turned to docFinder, the most comprehensive and accessible source of global oil and gas financial and operational information. We found that major producers have narrowed their focus to core areas within the play, where they have boosted returns through longer laterals and enhanced completion techniques. But only a select few are increasing investment at current prices because oil differentials in the region are $9-$10 below NYMEX.

Email PLS for a quick demo on how docFinder can save you valuable time in researching market activity!

One of these players is Noble Energy, which produces about 110,000 boe/d from the Niobrara accounting for 26% of its total output. The industry has reduced the number of rigs in the play from the mid-60s in 2014 to as low as 12 in the spring of 2016. Noble is an exception to that trend, targeting 40% of its 2016 capital investment to the play because of outstanding results and adding a rig in 4Q16. The company has concentrated on drilling extended laterals of 7,500 to 9,500 ft with a basic well design that includes a hefty 1,400 lb of proppant and slickwater per foot. These enhanced completions result in longer plateau production, which drives significantly higher 30-day production rates. Noble said its EUR per lateral foot has increased 15-20% in its three core areas, which are generating before-tax rates of returns of 30-70% at $40/oil. This justifies investment even at current commodity prices.

Another producer with more dramatic plans is Anadarko Petroleum, the largest producer in the play (245,000 boe/d, 31% of total output). The company recently announced a $2 billion acquisition of Gulf of Mexico assets to generate free cash flow to increase investment in the DJ and Delaware basins. Anadarko is adding two Niobrara rigs in 2H16 and plans to double production from the play over the next five years. The company has consolidated its core position, cutting drilling and completion costs by 45% and 56%, respectively, since 1Q15. Standard-lateral costs have been reduced to $2.3 million, bringing the before-tax breakeven to under $30/bbl.

Hot slides and more industry examples!
Down below you'll see four (4) relevant stories and another reminder how docFinder and its library of over 1.5 million slides can deliver critical information in seconds.

You can do what?
You can now search docFinder by numerical data like lateral length, sand, IP, EUR, IRR, well costs, API, B-Factors and more! Email Ernesto Sandoval to learn more.

Click here to access the docFinder database!
Click here to sign up for a web demo!

featured.slides from docFinder

Slide Slide Slide Slide


Efficiency results in fastest growth for play

November 16, 2016


Longer laterals spur optomistic growth plan

November 9, 2016


Slashes drilling costs but delays completions

November 1, 2016


Company exits play as oil prices fall

January 5, 2015

PDC Energy has been the fastest-growing Niobrara producer, increasing output 39% in 2016 to over 65,000 boe/d in 3Q16, in part due to an aggressive capital program that has exceeded cash flow by about 50%. But this investment has paid off in above-average profits, and the outlook has improved after it recently enhanced its portfolio through an acreage swap with Noble Energy. This exchange boosted PDC’s middle-core acreage by 17% and more than doubled the number of extended-lateral drilling locations. Mid-reach and extended laterals will now make up about 65% of all wells going forward, compared with 15% historically. The longer laterals, combined with higher proppant volumes, are producing results significantly above the company’s type curve in areas like its LDS project. The increased efficiency is allowing the company to maintain its high production growth while reducing its rigs in the play from four to three in the 4Q16.

Synergy Resources, a pure-play producer with a $1.85 billion market cap, also has ambitious growth forecasts as it concentrates on the “Wattenberg fairway,” an area it describes as the highest-quality acreage in the DJ Basin. The contiguous nature of the acreage gives it the ability to drill longer laterals with better economics. The production to date from mid-level wells drilled on the Bestway pad significantly exceeds its type curve in the region and is generating an IRR of 57% at current strip pricing. This has spurred management to more than double capital spending to $260-300 million in 2017 to drill 68 mid-length laterals and 34 long laterals. The company forecasts production growth from the current 10,794 boe/d to 17,000-20,000 boe/d by the end of 2017.

Whiting Petroleum, which holds 129,000 net acres in Redtail field in the DJ Basin, has matched the drilling efficiency of the other major operators, reducing completed-well costs to $4.0-4.5 million. New techniques, such as the use of one string of casing all the way to total depth, has slashed drilling times, including a recent 10,000-ft well that took just 2.75 days. But oil prices have led Whiting to be more conservative about bringing wells on stream, and it suspended completion activity in 2Q16. That has led to an inventory of more than 100 DUC wells. Management recently said it has more confidence in the direction of oil prices, so it will begin to complete those wells in 2017, cutting the DUC inventory at least in half. Production fell from 14,500 boe/d in 4Q15 to 10,700 boe/d in 3Q16, but the completions should reverse the trend next year.

In contrast to other producers with major DJ Basin positions, Encana decided to exit the play in October 2015. In its January 2015 analyst presentation, Encana touted the prospectivity of the play as it forecast a 40% increase in output in 2015 from its 51,000 net acres. But the rapid decline in oil prices eroded economics as the year progressed. Also, Encana only had an average 37% net interest in the play, which meant that it likely was not the operator on much of its acreage. When the company re-evaluated its portfolio, it decided to allocate capital to four “core” plays where it had more control of investment decisions and operations—the Eagle Ford, Permian, Montney and Duvernay—and exit the DJ Basin. Interestingly, the buyer was a firm 95% owned by the Canadian Pension Plan Investment Board, which evidently took a longer-term view that the quality of the acreage would generate significant returns.


Full Presentation


Full Presentation


Full Presentation


Full Presentation