During the quarter, we brought online 9 horizontal wells in the Permian. Included in that figure is an 8-well pad in Howard County that actually straddled Q2 and Q3 and is therefore only partially reflected in Q2 in our quarterly numbers. While still very early, we like what we’re seeing in those production results. In total, we’ve brought online 76 wells to-date since commencing our 2-rig Permian horizontal program 3 years ago.

We recently spud our final well under our Joint Development Agreement with TPG Sixth Street Partners. The JDA with TPG proved crucial in transforming our business model and providing needed capital to develop our substantial Permian resource through the downturn. They have been a great partner over the last 3 years and we are thankful for TPG’s support! As we move to drilling and completing horizontal wells outside of the JDA, we are excited to gain additional exposure to our substantial Permian resource which will serve as a growth engine for the future of the company.

Our Permian horizontal program helped us achieve record oil production of 17,901 Bbls/d, even against the headwind of wellbore interference caused by our own offset fracs and those of nearby operators. Our shallow decline Permian base assets also played a big role in our results and, in our opinion, is a differentiating factor for Legacy relative to many other companies, exhibiting a <2% decline rate during the quarter and provided strong free cash flow to fund this production growth.

We achieved a quarter-end total debt to pro forma adjusted EBITDA ratio of 4.7x, representing a reduction of nearly 3x since its peak of 7.6x at YE’16. We’ve worked tirelessly through the downturn to reduce operating costs, sell non-core assets, transform the business by increasing our interest in our Permian horizontal development program, and most importantly, to drill great wells efficiently. I’m really proud of the outstanding work the team has done to de-leverage the business and position us for growth.

Also, our BD and land teams really improved the value of the business by recently completing several trades involving a puzzle of 11 different tracts of land in the Permian Basin. The team was effectively able to monetize 8 small tracts with an average size of 55 adjusted net acres by trading them for 3 tracts adjacent to our near-term drilling prospects. The benefit of these deals are measurable: a 58% increase to our average lateral length and a 45,000 ft increase in our net lateral footage to be drilled. Not surprisingly, this will improve

the projected economics of these drilling locations and it allows us to monetize small tracts that many investors likely haven’t valued within our portfolio.

We own a lot more of these small tracts and are actively working to move them from our small-tract-stack to our drillable inventory stack. Now I’ll point you all to page 7 of the posted presentation where we’ve presented some new data surrounding these small tracts. The team has done good work to identify these tracts comprising 56,000 gross, or 15,500 net acres in the Midland and Delaware Basins with deep rights prospective for Wolfcamp, Bone Spring, and Spraberry development. These figures specifically exclude the Central Basin Platform and Northwest Shelf, areas where we see a lot of potential for these types of tracts as well, and we look forward to sharing those figures in the future. Those acres also don’t include any of our 922 identified horizontal sticks.

As always, we continue to examine and re-evaluate our resource potential. For those that have followed us for a while, you know that our Permian position in particular is a conglomeration of over 150 acquisitions and over many years that originally targeted mature PDP reserves. Consequently, we didn’t do the upfront work to determine our horizontal development potential. As we continue to go through land files and do the corresponding engineering and geologic work, we update our views. Page 9 of the posted presentation shows our latest look at horizontal potential in our asset base. We have and will continue to refine our technical work as well as spacing and lateral length assumptions. These figures represent both the identification of

new prospects and the removal of those where we no longer see potential. There’s also been some divestitures and trades run through these figures and conversion to PDP from wells brought online in the first half of the year. These are operated only locations, generally 1-mile or greater.    We’re proud to report an increase in our operated horizontal acreage to 51,500 gross and 41,000 net, and an increase in the number of operated drilling locations to 922 gross and 665 net, respectively, representing more than 25 years of inventory assuming our current drilling pace of 2 rigs at 18 wells per rig per year.

We’re proud to deliver record daily oil production this quarter as 20 new wells brought online during Q1 hit their stride in Q2. We discussed significant levels of frac interference in our last conference call and we experienced similar levels of frac interference in the second quarter..

We brought online 9 wells during the 2^nd quarter, some of which belong to an 8-well pad in Howard County that we brought online late Q2 and early Q3. We previously talked about our dedicated frac fleet and are pleased to realize the efficiencies of this agreement and the cost reductions it provides. Our folks were also able to procure a second fleet on the spot market to accelerate the development of the 8-well pad. This pad also served as a pilot for two new completion implementations for Legacy:

We are increasing our use of dissolvable plugs in the lateral; and

Increasing the use of resin-coated sand. One decreases coiled tubing use in the initial completion, and the other reduces subsequent cleanouts once the wells are on production

We spud our first well in Martin County during the quarter where we’re drilling a 4-well pad of 2-mile laterals in the Wolfcamp B. There are a lot of offset datapoints as this pad sits between two very densely developed areas of Martin County and we look forward to seeing those results later on this year. We’ve started building surface locations in Midland County and will start moving the rig to that pad once we complete the drilling in Martin County. We really like this “round the Basin” development strategy as it allows us to leverage data from offset operators to optimize landing and frac design heading into a batch completion. We also see or expect to see a reduction in wellbore interference as we are developing areas that are not direct offsets to our existing, young production.

The Land trades completed this quarter that Paul mentioned are a big deal to my Operations team. Blockier acreage with longer laterals will help our development program on multiple levels throughout the process, we look forward to executing more of those trades.

Our gas and NGL production and revenue had some variance this quarter and that’s driven by our non-op Piceance Basin properties where we achieved record ethane recovery. This drove the large increase in NGL volumes. This is generally a net revenue enhancing strategy by the marketer of these volumes, despite the reduced gas price realizations you’ll see in our quarterly figures.

EBITDA grew by 2% during the quarter to $72 million which was driven by a 4% increase in daily oil volumes primarily attributable to our Permian horizontal development program.

While headline NYMEX oil prices increased by 8% during the quarter, our realized price only increased by 1.5% as the Mid-Cush differential widened, increasing our total company oil differential from -$2.53 in Q1 to -$6.81 in Q2.

On the cost side, LOE per Boe declined from $10.99 in Q1 to $10.84 in Q2. This includes a mix of lower Permian SWD costs and higher Permian workover activity related to sub pump failures. While LOE is running a little higher than we like, our core competency as a cost-efficient PDP operator will allow us to make the tweaks necessary to bring this figure down.

Development capital for the quarter was $81 million, bringing year-to-date total to $140 million, nearly all of which was spent on our horizontal Permian development. We’ve fracked 25 wells so far this year as we brought online our third, 8-well pad, reducing our year-end DUC count. We expect that cadence to become less choppy going forward as we pursue smaller, 4-well pads. For the remainder of the year, we expect to complete an additional 9 wells, so our previously-guided capital figure of $225 million remains unchanged at this point in time.

Since our last conference call we entered into a Settlement Agreement with holders of our Preferred Units to settle the previously disclosed class action lawsuit. In order to avoid the additional time and expense of ongoing litigation and without

admitting fault, we agreed to issue approximately 10.7 million additional shares of New Legacy to holders of our Preferred Units for a total of approximately 27.6 million shares to existing holders of our Preferred Units. Following final approval by the court, each outstanding Preferred Unit will be converted into a right to receive approximately 2.9 shares of New Legacy common stock.

The Court has entered into a scheduling order and set September 12 as the date of the final fairness hearing, at which Legacy and the plaintiff will request final approval of the Settlement.

Separately, we filed what we believe is our final amendment to our S-4 yesterday evening and we are requesting effectiveness from the SEC today. We anticipate filing a definitive proxy statement and commencing the unitholder solicitation in the coming days.

Within that solicitation material you’ll notice we’ve set September 19 as the date of the special meeting of unitholders to vote upon our Corporate Reorganization.