So now let's go ahead and talk about the Utica. So we are also very encouraged about our performance to date at the Utica. Obviously, it's a little earlier than the Bakken. We have a very solid post-appraisal plan located in the core positioning of the play. Now we have the highest NRI in the liquids-rich region, which leads to an economic competitive advantage to others. We are also, as we've talked earlier, leveraging Bakken capability to improve efficiencies and reduce costs. And I'll show you some of the transfer in the next couple of slides.
So with our measured development plan, I state measured, I'll talk about that later, we exceed 40,000 barrels a day equivalent by 2020, with over 500 well locations and a net EUR greater than 300 million barrels equivalent.
So Hess' acreage is located in the industry recognized sweet spot of the wet gas window. So acreage is located in the Optima, what we call Tier 1 area for both pressure and liquid content as can be seen by the map to the left.
Test rates are strong in all pads and in all 3 Hess-operated counties as be -- can be seen on the top-right table. And longer-term performance is also very encouraging as we work through the early time facility constraints. Estimated average gross development EURs with a 8,000-foot lateral or approximately 1.2 million barrels equivalent. It is a conservative number.
So now I would like to compare well designs between the Bakken and the Utica plays. This often gets discussed in the public. The cost are different, but they are both equally profitable. So for well lateral lens, the Bakken has more -- has for the most part, a standardized as Gerbert discussed earlier, 10,000-foot lateral length. This is based on North Dakota DSU acreage pooling. So Ohio has no pulling at this time, and requires 100% land consent. So this leads to nonstandard lateral lengths in the Utica play with varying well productivities, and I'll talk about that a little later. So in the drilling aspects, at Utica state-mandated water protection barriers and safety requirements for potential mine collisions require additional casing strings above and beyond the Bakken. And on the completion side, tighter less permeable rock in the Utica requires higher number of frac initiation points and sand volumes. As Herbert described to you earlier, this takes about 3x to 5x longer in cycle time, but it's very important in this tight, tight rock. So very important to understand that.
So this translate into higher well cost for Utica. However, Utica has more than double the EURs and 95% NRI in the wet gas window. So these easily offset the higher costs, making both plays very comparative in overall returns.
But there is one thing that's similar. If you haven't heard this before, I'll say it one more time. The comment thread to both plays is it's repeatable and is standardized. So we're applying the Bakken lean approach to Utica, as well as testing various wells in stage spacings just like Gerbert discussed, looking for the highest value well-designed.
So the Lean approach is yielding similar results at the Utica. We see reduced spud-to-spud cycle times as a result of cycle times, as well as unit drilling and completion costs. All of which are happening much quicker than we saw in the Bakken. This to me shows we are learning quicker and accelerating improvements as we go to new assets.
If you take reference to the bottom let plot, Hess' average lateral length is the longest in the industry and this equates to more productivity. This also makes land development capability, a key enabler to success, both getting land consent and also being able to allow yourself the ability to drill the longest well in the DSU, very important enabler to the Utica.
So we expect these improvements to continue to prove in all areas going forward, as we mature our workflows described earlier.
So now as we transition out of appraisal into development, our first guidance on the Utica is 40,000 barrels a day equivalent for 2020. Now this is based on a measured development pace that exercises capital discipline. Because we have limited remaining call by production leases, we are able to drill the best wells first in this plan and also be able -- have the capability to accelerate drilling if required. So this plan, this flexible plan equates to 2 to 3 rig program, spending about $300 million to $350 million a year.
Now we'll watch the third-party infrastructure build outs in the area and pricing uncertainties going forward, and we will react accordingly. So now our infrastructure strategy in Utica is also quite different than the Bakken. We are leveraging existing midstream third parties to minimize capital expenditures. In the near term, third-party gathering and processing will be secure by the end of the year for all our wells drilled through 2018. We have multiple regional outlets that provide us market export flexibility and our commercial strategy is to reduce financial exposure from long-term contracts and take advantage of expected future export oversupply. So I started this presentation talking about how excited I am to work in the growth -- of this growth potential in Utica and the Bakken. They deliver double annual growth in long-term cash flow. The Bakken guidance has increased with our confirmed 7/6 development, and we see significant upside.
Utica's first guidance indicates a 40,000-barrel a day equivalent rate by 2020 and the flexibility to turn up this program if required.Read the whole transcript here.
And, thanks to Marcellus Drilling News, you can view the slides used during the event (pages 44-51 are of particular interest in relation to the portion of the transcript we have quoted from).
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