On the bright side for the industry, several drillers are stating their intentions to get rigs back into action and begin drilling new wells again.
Here is a quick look at second quarter updates from a few drillers and services companies, with a focus on their Utica shale activity where applicable.
Appalachian Basin - Warrior North Area - Carroll County, Ohio
In the Warrior North Area, Rex Energy placed the three-well Goebeler pad into sales during the second quarter. The Goebeler wells were drilled to an average lateral length of approximately 7,360 feet and completed in an average of 41 stages with average sand concentrations of 2,800 pounds per foot. The wells produced at an average 24-hour sales rate per well, assuming full ethane recovery, of 2.1 MBoe/d, consisting of 3.5 MMcf/d of natural gas, 801 bbls/d of NGLs and 704 bbls/d of condensate.
The company also placed into sales the two-well Perry pad. The Perry pad was drilled to an average lateral length of approximately 6,350 feet with an average of 36 completion stages. An update on the Perry pad will be provided during the third quarter of 2016. The four-well Vaughn pad is currently being drilled with an expected average lateral length of approximately 7,200 feet, with the four well pad expected to be placed into sales in the first quarter of 2017.Eclipse Resources:
Since resuming operations, the Company has drilled 3 gross (3.0 net) operated Utica Shale wells and is continuing its drilling program in the dry gas portion of its Utica Shale acreage. In addition, the Company has completed 7 gross (6.6 net) wells averaging 8 stages per day in the liquids rich portion of its Utica Shale acreage. The Company put its first four well pad into sales this week and expects to bring its next five well pad into sales during the next 30 days.
Commenting on the second quarter results, Thomas S. Liberatore, Eclipse Resources’ Executive Vice President & Chief Operating Officer, said, “The Company’s return to drilling and completion operations during the second quarter has continued to highlight our operational strength, despite the previous pullback in activity, with an average of 17 days spud to total measured depth per well and an average minimum of 8 completed stages per day in our completion operations during the quarter. Our Purple Hayes well has now produced a cumulative amount of 1.2 Bcfe during its first 90 days while exhibiting very shallow pressure declines of approximately 45 psi per week. We remain extremely pleased with this better than anticipated performance and the results to date. We attribute much of the outperformance of this well to our completions design in which we developed designer completion fluids that allowed us to place proppant out at such long distances using 100% slickwater and preventing formation damage. As we have moved forward in completing our DUC wells that we drilled approximately two years ago with shorter laterals, we have continued to use these same fluids to test the upper limits of proppant placement intensity into our wells. On our Borton pad that was placed to sales this week, we completed our wells with 100% slickwater, tight stages of 150 feet and sand concentrations of 1,800 to 2,000 pounds per foot, or 30-40% higher sand concentrations than the Purple Hayes well. On our next pad, the Wheeler Pad, that is expected to go to sales in the next month, we increased the sand concentrations to 2,000 to 2,400 pounds per foot. Additionally, on a select number of test stages, we were able to place up to 3,000 pounds per foot on a 150 foot stage and 2,400 pounds per foot on a 110 foot stage. As we move to our next DUC pad, where we expect to test tighter stages of 110 feet with 2,400 pounds of sand per foot on two wells and 150 foot stages with 3,000 pounds per foot on two wells.”Stone Energy:
Stone reported a second quarter of 2016 net loss of $195.8 million, or $35.05 per share, on oil and gas revenue of $89.0 million, compared to a net loss of $152.9 million, or $27.68 per share, on oil and gas revenue of $149.5 million in the second quarter of 2015. The adjusted net loss, which excludes impairment charges of $118.6 million, was $41.6 million, or $7.45 per share. Net cash (used in) provided by operating activities totaled ($31.6) million for the second quarter of 2016, while discretionary cash flow totaled ($6.6) million during the second quarter of 2016, as compared to $62.1 and $84.9 million, respectively, during the second quarter of 2015. Please see "Non-GAAP Financial Measures" and the accompanying financial statements for reconciliations of adjusted net loss, a non-GAAP financial measure, to net loss, and discretionary cash flow, a non-GAAP financial measure, to net cash (used in) provided by operating activities.
Net daily production during the second quarter of 2016 averaged 29.0 thousand barrels of oil equivalent (MBoe) per day (174 million cubic feet of gas equivalent (MMcfe) per day), compared to net daily production of 34.5 MBoe (207 MMcfe) per day in the first quarter of 2016 and net daily production of 48.6 MBoe (291 MMcfe) per day in the second quarter of 2015. The second quarter 2016 production mix was approximately 59% oil, 32% natural gas and 9% natural gas liquids (NGLs), and included approximately 23 MBoe (138 MMcfe) per day from the Gulf of Mexico (GOM) and 6 MBoe (36 MMcfe) per day from Appalachia. Appalachian volumes for the second quarter of 2016 included 21 MMcfe per day from the Heather and Buddy fields, 11 MMcfe per day of intermittent production from the Mary field and 4 MMcfe per day attributed to final adjustments of our working interests in two Mary units.Antero Resources:
Low pressure gathering volumes for the second quarter of 2016 averaged 1,353 MMcf/d, a 40% increase from the second quarter of 2015 and a 4% increase sequentially. High pressure gathering volumes for the second quarter of 2016 averaged 1,253 MMcf/d, a 5% increase from the second quarter of 2015 and a 3% increase sequentially. Compression volumes for the second quarter of 2016 averaged 658 MMcf/d, a 45% increase from the second quarter of 2015 and a 9% increase sequentially. The increase in gathering and compression volumes was due to production growth from Antero in Antero Midstream's area of dedication. Condensate gathering volumes averaged 1,983 Bbl/d during the quarter, a 34% decrease compared to the prior year quarter and a 33% decrease sequentially. The sequential decrease in condensate gathering volumes was driven by Antero shifting Ohio Utica Shale development from its Highly-Rich Gas/Condensate area to higher rate of return drilling in the Highly-Rich Gas area, as well as the shifting of Antero Resources' development program to the Marcellus Shale from theUtica Shale, due to firm transportation constraints to premium markets in the Utica Shale. Fresh water delivery volumes averaged 105,379 Bbl/d during the quarter, an 11% increase compared to the prior year quarter and an 8% increase sequentially. The increase in fresh water delivery volumes was driven by operational efficiencies leading to accelerated Marcellus completions and an increase in the average water used per foot in completions to 41 barrels, a 25% increase as compared to 2015 and an 11% increase compared to the first quarter of 2016.CONSOL Energy (from Oil and Gas 360):
CONSOL Energy’s (ticker: CNX) upcoming drill plans include adding back two horizontal rigs which are expected to resume drilling starting in August 2016, the company said in its Q2 2016 earnings release.
The company is looking to drill eight dry Utica shale wells, located in Monroe County, Ohio, (100% working interest) and two Marcellus shale wells, located in Washington County, Pennsylvania, (50% working interest).
The two new Marcellus Shale wells are located on a 6-well pad that contains 4 existing drilled but uncompleted (DUC) wells. CONSOL expects to finish drilling the remaining 2 wells in order to complete the pad. CONSOL expects that the lateral length for the 10 wells to average approximately 8,700 feet.
CONSOL said it expects to see a partial year production benefit from these new wells starting in April 2017. Also, the company anticipates its DUC well inventory to grow to 91 gross Marcellus and Utica shale wells exiting 2016, which includes 76 wells that are located in the wet areas.Baker Hughes (from NGI):
Responding to declining revenues amid continued commodity price pressures, Baker Hughes Inc. (BHI) looked to cut costs during the second quarter, including 3,000 layoffs as part of an organizational overhaul.
BHI began the restructuring with a target of about $500 million in annualized cost savings, management told investors during the Houston-based oilfield services (OFS) giant’s quarterly conference call Thursday. CFO Kimberly Ross said the company realized about $450 million in annualized savings during the quarter, with two thirds of that resulting from the workforce reduction.
BHI was not the only industry player to reduce its workforce during the second quarter (see Shale Daily, July 22).Rice Energy:
During the second quarter, we turned to sales 9 gross (6 net) horizontal Utica wells with an average lateral length of approximately 8,900 feet. In addition, we drilled 3 net and completed 4 net Utica wells during the second quarter for an average cost of $1,150 per lateral foot, reflecting continued cost reductions from shorter project cycle times and lower service costs. In addition, we participated in 4 gross (2 net) non-operated Utica wells turned to sales during the second quarter.
As of June 30, 2016, we have placed online 9 gross (6 net) operated Utica producing wells during the year.Spectra Energy:
Second quarter 2016 ongoing distributable cash flow was $281 million, compared with $321 million in the prior-year quarter. Distributions per limited partner unit for second quarter 2016 were $0.66375, compared with $0.61375 per limited partner unit in second quarter 2015.
For the quarter, ongoing earnings before interest, taxes, depreciation and amortization (EBITDA) were $448 million, compared with $456 million in the prior-year quarter.
Ongoing net income from controlling interests was $293 million for the quarter, or $0.73 diluted earnings per limited partner unit, compared with $307 million, or $0.83 diluted earnings per limited partner unit, in the prior-year quarter. Net income from controlling interests was $287 million for the quarter, or $0.71 diluted earnings per limited partner unit, compared with $307 million, or $0.83 diluted earnings per limited partner unit, in the prior-year quarter.
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