A big conversation piece around the oil and gas round tables is the large and vast inventory of drilled and uncompleted wells.
Controversy is not far behind this table talk as nearly all states or leasing agreements have requirements on when new wells have to be brought online after initial spud. In basins where economics are not favorable such as North Dakota the state has issued allowances of an extra year to defer the completion of these DUCs. There has been some talk of whether a DUC is considered a PUD or PDNP, and if it is PDNP how to discount the value to determine how much to lend against those assets. Landowners are also at a loss in some cases as money they thought they would be receiving after their division order came in has been put on hold indefinitely. Some operators will have to make the choice to complete the well and lose reserves or face a potential lawsuit from landowners and the state for not completing wells within the specified time.
In a previous life I used these DUCs in a search and destroy style mission; find operators with large capital expenditures requirements brought on by these DUCs but low budgets or high debt. These DUCs represented their prior success, when pricing was favorable, which was used against them to secure working interest (WI) and a foothold in future projects. Sifting through the immense data files and access databases to create these profiles was time-consuming and could lead to lackluster results if the database was not kept current. Advising companies on similar strategies now, using DrillingInfo’s Rigs Analytic platform makes this task and many others fast an easy, let’s dive in.
DUC’s and wells that have been shut-in for at least 6 months allow capital providers or analysts to determine where a company stands on future drilling. If you look at a company’s 10’k report and determine that they are only going to bring online 20 wells in 2016 in the Bakken but have 18 DUCs that will hit their 2-year expiration limit in the same year it can be concluded that they will only be drilling 2 wells during 2016. Since we are able to determine the location of these DUCs we can also know their approximate production based on offsets allowing us to make a depiction of what the production should be from these new wells. We can also determine which month different wells have to be completed to comply with that states rules.
On the other hand, if we are looking at an investor presentation and know that a company has more DUCs in inventory than their CAPEX allows for, time to go hunting. Using this data along with Drillinginfo’s leasing analytics we can determine if surrounding acreage is expiring or who is the lessor which allows us to begin to make a pitch of funding both wells and leasing activity. This is significant because the difference with these DUCs is that half of their expected costs are already sunk; we are able to get in at a lower price point than if the wells were newly drilled as a company has to make a decision to take the capital or deal with a potential lawsuit from the state or landowners by not completing the well within the approved 2 year window.
This is just one example of how the industry can use the data available to make decisions. There is a lot more to an investment decision that provided in this article but the ability to make these types of pitches to investors and companies will help a new wave of funding for companies with not enough capital to move forward. It can help jumpstart or keep alive certain entities that are all but dead and allow for companies to hold on to non-core assets that are valuable at a higher price environment. For those with the capital to spend, happy hunting.
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For the last five years or so, horizontal wells drilled with large rigs and drilling pads has been the picture in most people’s minds when they think of the oil and gas industry.
With the downturn in pricing many of these rigs have been stacked due to uneconomic plays.
Conventional oil and gas and vertical wells have largely been considered low hanging fruit and a staple of many producers’ portfolios that can get ignored when pricing is favorable and other plays are hot. Some companies in light of today’s environment might give more light to their vertical drilling programs as the costs associated are far less than that of their horizontal counterparts and economics are still favorable. The areas that will be hit the worst in today’s pricing environment are those where the unconventional boom occurred that do not have large scale conventional formations to fall back on for vertical drilling and production.
Figure 1.1: US Well Starts by Month colored by trajectory
States such as Texas and Oklahoma have had a fairly consistent amount of vertical well starts while their horizontal counterparts have decreased. One region where unconventional formations are still hot, horizontal or vertical is the Permian. This is due to lower break even costs and a robust midstream system that has been in place for a long time. The Permian is not new to the E&P space, with many wells having produced for decades regardless of macro environment. An increase in the push for horizontal wells has been increased due to being one of the few economical plays left in the current environment.
Figure 1.2: Permian Well Starts Through Time
Using DrillingInfo Analytic platform well starts by well type was mapped. The overall profile is that well starts for both horizontal and vertical have decreased over time. In March 2014, when DrillingInfo historical rig data begins, vertical well starts accounted for approximately 55% of all well starts in the Permian. Today that figure is down to approximately 23% of all wells drilled while horizontal wells have gone from 38% to 68% of all wells drilled. The overarching question is how many of those wells that were drilled have actually been turned on and are producing. Using DrillingInfo’s analytics platform well starts over time, colored by current status for each trajectory was mapped for the Permian.
Figure 1.3: Vertical Well Status by Month Drilled in Permian Basin
Figure 1.4: Horizontal Well Status by Month Drilled in Permian Basin
Of the reported vertical wells drilled inside DrillingInfo’s analytics database for the Permian 87% have been either brought online or had existing production while horizontal wells report 85% with new or existing production. The drop off towards the end of 2015 is due to no status production reports on wells as they may be too new to have any production registered with the state.
Driving through the fields of the Permian, SCOOP, and Utica over the past few months there are signs that the industry is still alive. With overall rig counts in the Permian alone at 152 active, which represents a downturn of nearly 50% over the last 12 months there is reason to be doubtful. However, we are able to see a shift in priorities in E&P’s to assets that they consider most economic. The Permian while showing signs of a slowdown is still growing overall with 63 horizontal and 20 vertical wells having a reported rig on site in March 2015. There is a backlog of DUCs but as the low price environment continues and completion costs come down we will see those wells begin to come online. Since many of those wells are economic currently, waiting for completion costs to lower will only raise their value to many E&Ps. The strategy might be risky as operators risk mineral owner issues if they do not produce the wells in a fair amount of time as we have seen in the Bakken and completion costs might not lower. The offset is that operators are allowing for pricing to hopefully rebound and are not having any real loss other than drilling costs. With a large backlog and slow decrease in status of these DUC’s, new well starts will continue to suffer as those older wells have to be brought online which will only continue to stifle some parts of the industry that are reliant on new well starts.
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