Initial Production

The oil price collapse has opened a wide rift between high quality “good” assets, breakeven “bad” assets, and ruinous “ugly” assets.  The consequences will impact energy markets for decades to come.  In our recently published Drill Down Report, we demonstrate the differences between good, bad and ugly wells by examining the diversity of production economics across the Eagle Ford basin and why producers have been zeroing in on the counties——and areas within those counties—where initial production (IP) rates are highest, and preferably where large volumes of associated natural gas and natural gas liquids can be found as well. Today we consider Eagle Ford counties in more depth—their IPs, their internal rates of return (IRRs), and the number of new-well permit applications in each county in the first quarter of 2016.

For the past, year many shale oil producers have defied the expectations of many and kept output at or near to record levels in the face of falling oil prices and much tougher economics. Improvements in productivity, cost cutting and a concentration on “sweet spot” wells that generate high initial production (IP) rates have all helped cash strapped producers survive. But with oil prices so far in 2016 stuck in the $35/Bbl and lower range and with the worldwide crude storage glut still weighing on the market – producers are finally pulling back. Today we look at how increased pressure on North Dakota producers is putting the brakes on Bakken crude production.

Crushing oil prices are hitting U.S. shale producers hard and the outlook for 2016 shows little sign of a let-up. Production has continued to prove resilient but the odds are that something has to give at these prices. However there are still sweet spots in U.S. shale plays where producers are increasing acreage and drilling new wells. The headline plays that many analysts talk about are the Delaware and Midland basins in the West Texas Permian but as we outline in today’s blog there is also continued interest in the relatively less well-known central Oklahoma SCOOP and STACK plays.

The natural gas market just managed to dodge a collision this summer between excess gas supply and available storage capacity. Now about a month into the gas winter season, storage inventories are still near record levels after topping 4.0 Tcf just two weeks ago. The Henry Hub CME/NYMEX January contract price closed yesterday (December 2, 2015) at $2.165/MMBtu, historically low even as we head into the highest demand months of the year. It’s now clear that 2016 will inherit this bearish market unless there is a Polar Vortex Tsunami in January and February. But what does this mean for producers, and how much will demand respond? In today’s blog, we begin a series on potential scenarios for the 2016 gas market balance.

The CME/NYMEX Henry Hub natural gas futures price averaged $2.64/MMBtu in September, the lowest level for any September since 2001, and it continues to hover at a similar low for October so far. Rig counts are down nearly 60% since December 2014. The market is on high alert for the first sign of production declines that might encourage higher prices – believing this to be a matter of sooner or later. Yet natural gas production has been hitting all-time records. Today we look at monthly natural gas production data from the Energy Information Administration (EIA).

For nearly two months -- Since late July -- WTI crude oil prices have averaged $45/bbl, never once closing above the $50/bbl mark.  Over the same period, the natural gas price at Henry Hub has averaged $2.70/MMbtu and now languishes $.20/MMbtu lower.  Is this a time to be wallowing in misery and self-pity?  Absolutely not!!  This is the time for midstreamers and producers to reposition their businesses with a laser-like focus on the opportunities that low prices have served up.  There are bargains out there in the oil (and gas) patch.  If producers are in the right locations, with drilling costs much lower than last year, there is good money to be made.  And likewise, opportunities abound for midstreamers to pick up assets at very attractive prices to get that production to market.  But to execute such a strategy, you must have a rock-solid understanding of what is really going on in today’s markets for crude oil, NGLs and natural gas.  Our goal for the upcoming State of the Energy Markets Conference scheduled for October 28, 2015 in Denver, CO is just exactly that - to give you a rock-solid market knowledge based on hard data and thorough analysis.  Today’s blog is an advertorial for the conference.

Crude oil producers in the Bakken region responded to the oil price collapse with drilling cutbacks and a laser-like focus on sweet-spot areas with high initial production rates. It turns out those oil sweet spots also produce a lot of associated natural gas. But there’s not enough infrastructure in place to deal with the extra gas, and that’s slowing North Dakota’s efforts to reduce flaring (burning gas that can’t be utilized for various reasons). Today, we consider the multiple, domino-like effects that low oil prices are having on one of the U.S.’s most important tight oil plays.

U.S. Lower 48 natural gas production is averaging a record 74.2 Bcf/d in September to date, according to PointLogic Energy. Meanwhile, CME’s Henry Hub natural gas futures contract has languished at an average of $2.68/MMBtu this month to date, the lowest for any September since 2001. Much of the recent gain in natural gas production has come from  new Utica Shale output.  In today’s blog, we drill down into the region’s pipeline flow data to see where exactly the growth is coming from, what’s driving it and what it could mean for natural gas supply.

<p>Last year was a banner year for the sand mining companies that cater to the U.S. shale drilling services industry.</p>

In the past 10 years Marcellus and Utica shale drilling has transformed the U.S. Northeast from a sleepy backwater of gas production into a powerhouse that (according to the Energy Information Administration) supplied 22% of total U.S. gas production in December 2014.  NGL production from the region is already 8% of the U.S. total and likely headed toward 20% by 2020.  These vast shale formations cover most of Pennsylvania, West Virginia and Eastern Ohio, but it turns out that most of the production comes from only 20 or so counties across those three states.  Such geographic concentration has significant implications for regional infrastructure development and capacity. Today we describe where producers have found success in the region.