Strong Production Quarter
Q2 production came in 5% above the midpoint of the guidance range despite slightly lower-than-expected D&C spending for the quarter .
Total operating costs per unit decreased by 14% sequentially to $24.45/boe.
Pro forma for the East Texas divestiture, Q2 production was 40.4 Mboe/d (85% oil, 7% NGLs and 8% natural gas).
Halcón updated its production guidance for the rest of the year. The company estimates that it will produce:
- 41.0-43.0 Mboe in Q3 2014, which implies an ~4% "same store" quarter-over-quarter growth;
- 40.0-42.0 Mboe in 2014, which implies a 2.5% midpoint increase relative to the midpoint of the previous guidance.
The overall result is solid and, combined with the guidance, gives good visibility with regard to the company's stated production objective for the year.
The Bakken remains Halcón's highest-return development asset and the most active drilling area. The Bakken currently accounts for 70% of the company's total production.
In the Williston Basin, Halcón produced an average of 28.3 Mboe/d during Q2, a 22% sequential increase. The result is ahead of my 26 Mboe/d estimate for the quarter.
The improved volumes reflect more normal activity levels post the weather impacts experienced during Q1. The company operated an average of four rigs.
Of note, Halcón's activity in the Bakken was concentrated almost exclusively in the company's "core of the core" Fort Berthold Indian Reservation area (map below) where 18 operated wells were put online during the quarter. 1 additional well was connected in Williams County. The company also participated in 45 non-operated wells (2.25 net wells) during the quarter.
(Source: Halcón Resources, June 2014)
Perhaps the most important commentary from the company relates to well performance. According to Halcón, the 18 FBIR wells connected in Q2 had very strong IP rates and are outperforming Halcón's 801 MBoe type curve.
(Source: Halcón Resources, June 2014)
Completed well costs in the Fort Berthold area are currently estimated at $11.5 million. The cost was down 3% sequentially in Q2.
Aslo worth noting is the comment that the new well in Williams County also demonstrated strong early performance and is outperforming the 477 MBoe type curve (which reflects a 43% EUR revision earlier this year).
(Source: Halcón Resources, June 2014)
Well costs in Williams County are lower than in the FBIR area. While the Williams County acreage remains a "Tier 1" area in the company's portfolio, recent well productivity improvements may help reduce the gap in drilling economics between the "core of the core" FBIR area and the Williams County area.
Halcón produced an average of 9.1 Mboe/d in El Halcón during the quarter, representing a 30% quarter-over-quarter increase. While the result is below my 10 Mboe/d, the shortfall is fully explained by the lack of completion activity in June (based on my analysis, six new wells were connected in April and two wells were connected in May; no wells were connected in June versus my assumption of four well connections).
The company operated an average of three rigs in El Halcón during the second quarter and expects to keep the same pace of activity in the second half of the year.
According to Halcón, industry activity in the East Texas Eagle Ford continues to ramp up, and there are currently 15 to 20 total rigs drilling in the play. Based on its own results combined with the results from offset operators, Halcón believes that its entire 101,000-acre position has been de-risked and well performance should be repeatable.
The company's well performance in El Halcón continues to improve. During the conference call, Halcón provided several interesting data points. The 8 wells brought on production during Q2 had an average 24-hour IP rate of 804 boe/d and an average 30-day IP rate of 620 boe/d. These rates represent a substantial improvement over the first quarter.
In July, El Halcón turned to sales another three wells that had average initial production rate of 1,091 Boe/d (93% oil), a solid improvement over the Q2 average.
Tuscaloosa Marine Shale
Halcón's second operated TMS well, the Black Stone 4H-2 (5,400' drilled lateral), has not been tested yet. The well encountered fill during clean out operations near stage 10 (of 22, all of which were successfully pumped). Halcón was only able to partially clean out the fill and additional clean out operations are underway. Flow back is expected to commence once clean out operations are finalized.
While the mechanical complication is a disappointment, it is not particularly surprising given the execution success statistics in the play. As I have written repeatedly, in the TMS trouble-free execution is as important as well performance.
Another two in-progress wells, the Fassman 9H-1 and SD Smith 1H, both in Wilkinson County, are reported to have been successfully drilled. The wells are now awaiting completion. Of note, the 6,030' lateral in the Fassman well was drilled in just 6.5 days, an extraordinary result for the play and an indication that vast room for well cost reductions exists.
In the SD Smith well, Halcón drilled a pilot hole with a full state-of-the-art logging suite and recovered 200' of conventional core. After adjusting for the time it took to drill the pilot hole, the SD Smith well was drilled in 33 days, spud to TD, another impressive result.
Halcón commented that economics in the play are expected to improve over time as drill days come down, competition for services increases and efficiencies are realized.
Notwithstanding the lack of a success report for the Black Stone 4H-2 well in the strategically important TMS asset, the Q2 results contain many positive elements that add together to a solid quarter.
The company's flagship FBIR development area is performing strongly and drilling returns in "Tier 1" areas, Williams County in the Bakken and El Halcón, continue to improve.
Given the stock's weakness over the past 30 days, implications for the share price from the Q2 report are positive.
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