Q2 2019 Earnings Call

Ladies and gentlemen, thank you for standing by welcome to the Denbury resources second quarter 2019 results conference call. At this time, all participants are in listen only mode.

Later, well conduct a question and answer session, maybe like to queue for questions. At a time you May Press Star then one on your Touchtone phone.

Have you shouldn't need assistance during the call. Please press Star then zero and operate well since you off line. As a reminder, this conference is being recorded I would now like turn the conference over to our host director of Investor Relations Mr. John Meier. Please go ahead.

Thank you Jeff.

Good morning, everyone and thank you for joining us today.

With me on the call are Chris Kendall, our President and Chief Executive Officer.

Mark Allen, our executive Vice President and Chief Financial Officer.

Matthew Dan our senior Vice President of business development and technology.

And David Shepherd, our senior Vice President of operations.

Before we begin I want to point out that we have slides, which will accompany today's discussion.

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For those of you that are not accessing the call via the webcast. These slides may be found on our home page at Denbury Dot com.

By clicking on the quarterly earnings Center link under resources.

I would also like to remind you that today's call will include forward looking statements that are based on the best and most reasonable information we have today.

There are numerous factors that could cause actual results to differ materially from what is discussed on today's call.

You can read our full disclosure on forward looking statements and the risk factors associated with our business in the slides accompanying today's presentation. Our most recent SEC filings and today's news release, all of which are posted on our website that denbury dot com.

Also please note that during the course of today's call, we will reference certain non-GAAP measures.

Reconciliation and disclosure relative to these measures are provided in today's news release as well as on our website.

With that I will turn the call over to Chris.

Thanks, John and thanks to all of you for joining us today.

I'm pleased to announce that Denbury second quarter of 2019 was truly outstanding.

The team and I are looking forward to sharing details with you this morning, but before we do.

I'd first like to talk a bit about the current macro environment.

Specifically I'd like to review, how Denbury strategy assets and expertise a line to counter many of the challenges facing the energy industry today.

When I step back and think about those challenges.

I see two key themes emerging.

The first centers on how energy companies will meet clear investor demands to operate sustainable businesses that can return capital to shareholders.

The second involves the industry's ability to consistently provide a significant portion of the worlds energy in a manner that addresses the increasing environmental concerns around the production of fossil fuels.

I can say with confidence that Denbury is ideally placed to meet these challenges.

The company is in a strong position to meet shareholder demands for return of capital.

Our long life low decline low capital intensity high margin assets have provided us the flexibility under which we have been able to consistently and reliably generate free cash.

We have subsequently use that free cash to optimize the balance sheet.

Reducing our debt commitments by over 1 billion since the end of 2014.

We will continue to prioritize debt reduction through the use of free cash in the near future.

At its core our business involves the utilization of C. O two for enhanced oil recovery injecting millions of tons of C. O two into our reservoirs every year.

Over 3 million tons per year of that C. O. Two is currently captured from industrial sources that could otherwise have been admitted into the atmosphere.

Putting that number perspective, we're injecting the emissions equivalent of nearly 700000 cars every year.

As Denbury grows over time, we expect that number to increase significantly with our major new development at Cedar Creek anticline flooded with a 100% industrial source C O two.

This oil recovery techniques using industrial source COO to provide the lowest carbon footprint from oil production in the industry.

As the only U.S. public company of scale with C O two equal or as a primary strategy.

This places denbury and the unique and beneficial position within the industry, particularly given that our growth plans are based around utilizing increasing levels of industrial source C O two.

Looking further into the future I believe that carbon capture transportation unsecured geologic sequestration will become an essential business and denbury is assets and expertise position the company to be a leader as this market develops.

Turning now to the quarter Denbury is performance was outstanding by all measures and I could not be more proud of the work accomplished by our teams across all facets of the business.

Most importantly, we maintain safe working conditions for our employees and contractors and upheld our duties as stewards of the environment driving our performance higher in all key HSC metrics.

Total production was slightly up from the first quarter of 2019 supported by Great results at Bell Creek, where we reached a new your production record.

This performance has given us the opportunity to increase the midpoint of our full year 2019 guidance range.

Even after the mid year sale of our citrus belfield and its associated production.

I'm pleased to share that we accomplish these strong production results all while maintaining our originally guided annual capital range.

Importantly, we remain on track for the remainder of the year at the midpoint of that range.

Operating costs across the business were significantly reduced in the quarter and we now expect annual Ela, we need to be in the lower half of our previously guided range.

We further reduced our DNA levels, which are now around half of what they were as recently as a few years ago.

We continued making progress towards our CA enhanced oil recovery development, which is on track for field pipeline installation next year.

We completed an initial test of a promising exploitation concept at conroe.

Weve made good progress on non core asset divestitures.

Selling cetra nail and contracting 38 million in incremental Houston area land sales.

We executed the debt exchange that significantly reduced our near term subordinated debt maturities without increasing interest expense.

Our oil Levered production with high Gulf Coast premium pricing exposure resulted in strong realizations of nearly $61 per BOE, we high operating margins and 38 million in free cash flow generation.

Finally, and importantly, we continue to make progress on our priority of reducing leverage with total debt to EBITDA now reduced to just over 4.1 times or 3.6 times on the second quarter annualized basis.

Over the next few slides I'll review the quarter in more detail.

On slide eight we've updated our free cash flow projections based on actual results through the first half of 2019.

Assuming $55 WCS for the remainder of the year, we forecast full year free cash flow of between 120 and 150 million.

In line with our priority of improving the balance sheet.

We used a 120 million in cash as part of our second quarter debt exchange.

Which we expect to be funded through current year free cash flow.

These cash flow projections are enhanced by our strong hedge protection position, which protects about 70% of our 2019 production.

Mark will share more detail on that shortly.

Our second quarter revenue per be are we was nearly $61, resulting in an operating margin of just under $33 per be a week.

This high operating margin combined with our low capital spend supports the strong free cash flow that denbury consistently the levers.

Capital spending is exactly where we wanted at this point in the year as planned we made the bulk of art and 2019 Cc a C O two pipeline pipe investment in the second quarter.

By the end of the third quarter 2019, we expect all pipe will be completed and prepared for installation in 2020.

Our key tertiary capital project at Heidelberg is substantially complete and our Bell Creek Phase six project should be completed this quarter.

Our primary capital plans for the second half of the year include the continuation of our mission Kenyan exploitation program.

Additional drilling in the Charles formation.

Another well and beat and Bell Creek targeting an untapped accumulation in the phase one through four area.

With the completion of our major expenditures for the first half of the year.

We expect capital to reduce in the second half and that total full year capital will be near the midpoint of our guidance range.

I'm very pleased with the continued reliability and predictability of our production with second quarter 2019 production slightly ahead of our previously guided expectations of being flat with the first quarter 2019.

Production performance has been strong across the board highlighted by record production levels at Bell Creek.

And I'll go into more detail on our work there shortly.

As we discussed in the first quarter call, we expect third quarter production to be lower than the second quarter, mainly due to an extended period of planned maintenance at our primary north regency or to source.

As well as seasonal temperature effects in the Gulf Coast.

However, we expect fourth quarter production to rebound.

Primarily driven by response from our Heidelberg redevelopment completion of the North region Seo to supply maintenance and the impact of new exploitation wells to be drilled throughout the third and fourth quarters.

We've maintained a focus on continuing to optimize our portfolio and as a result sold the noncore citrus oil field in Alabama at the beginning of the third quarter. This field was producing about 400 net barrels per day at the time of the sale.

Considering our strong production performance so far this year.

We are increasing the midpoint of our guidance range by to our 50 Boe per day after accounting for divested citrus oil production for the second half of the year and we're also tightening the guidance range to 57000 to 59500 Boe per day.

I'm excited to say that performance at Bell Creek, just keeps getting better.

The second quarter 2019 production of nearly 6000 barrels per day made at the Companys highest producing airfield.

As we expected phase five performance has been the best of any phase completed to date.

And we have now substantially completed the development of phase six which has similar characteristics to phase five setting up additional field production growth in 2020.

The Bell Creek team has also look back at the initial development phases of the field.

And by using high resolution seismic imaging has identified untapped incremental oil accumulations, one of which we drilled in the first quarter.

That well has been a strong producer at around 500 barrels of oil per day.

And we have identified a handful of additional similar opportunities that we plan to begin testing later this year and into 2020.

Our operating teams made excellent progress in reducing costs in the second quarter.

Unit costs were lower than anticipated at 20, 170 per Boe weve about 8% below the first quarter level.

The key improvements were realizing fuel to power and fuel and Workovers, which are based on value, adding sustainable Ela, we management strategies.

So your two costs have benefited from ongoing utilization optimization in several fields, along with an improved tariff structure in the Rockies.

Renegotiated electricity demand charges in several fields, lower natural fuel gas gas fuel prices and fewer well failures and the Gulf coast are also pushing costs lower.

Given the momentum of our P. per BOE, we cost reductions, we expect that our full year 2019, Ela, we will fall in the lower half of the previously guided Ela, we range of 22 to $24 per be a week.

During the second quarter, we tested our first horizontal well in the Conroe field.

We are pleased with the initial results of this test well with a high oil cut at around 50% and the peak production rate of over 200 Boe per day.

We next plan to drill a second well in an adjacent fault block that considers learnings from the first well, it's likely that the second well will be drilled in 2020.

As I previously mentioned, we believe that this exploitation concept can be applied across many of our Gulf coast fields and our teams are conducting the technical work to prepare for next steps in this play.

At Tinplate, we tested the cotton valley and have all of our recently drilled exploitation well.

Well, we were pleased to achieve a two and a half million cubic feet per day gas rate and high liquid yield of 100 barrels of oil per day.

These test results coupled with current commodity prices would make a stand alone lower cotton Valley development fall below our investment threshold.

We're working plans to test the identified Uphole pay intervals, which we believe to be higher in liquid content.

Once we've completed those plans and test will determine the next best apps, which could include self development or potentially farm any of the discovery to a third party.

In late August we plan to resume exploitation drilling at CCH over the past two years, our exploitation investments at CA have proven very successful with strong production and outstanding economics.

Later this year, we plan to drill two new mission Canyon Wells, one in cabin Creek and another in coal Creek as well as a new Charles be well also in cabin Creek.

We are intrigued by the performance of the initial trials be well well as initial oil rate was lower than the typical mission Canyon well, it's sustained high oil cut makes the horizon a good candidate for both water and Cotwo flooding.

Moving to our divestment program, we made good progress on monetizing non core assets in the second quarter.

Starting with our Houston area property sales, we now have an additional 38 million and multiple parcels at quarter, one Webster under firm contract with closing structures that result in the receipt of proceeds in 2019 through 2022.

This brings our total sold or under contract to a total of 53 million to date.

With significant remaining value on the properties still being marketed.

Also as I mentioned earlier on July one, we divested of our noncore citrus oil field.

For $10 million in cash and the elimination of an abandonment obligations estimated at about 40 million or $9 million when discounted to todays dollars.

This field was expected to produce an average of 400 net barrels per day in 2019.

However, we considered noncore both due to its higher operating costs at our technical and economic analysis that it was not a good candidate for a cotwo flood.

We will continue to evaluate the remaining mature properties for sale or retention and will proceed in a manner that generates the greatest value for the company and our shareholders.

In summary, I'm thrilled with our performance so far this year.

Our business at Denbury continues to outperform our assets are located in the right basins to optimize our unique seo to IAR techniques and our teams across the company are highly skilled and experienced and importantly, we remain focused on the challenges that lie ahead with denbury is unique capability to not only meet those challenges but to benefit from them.

Next I will turn it over to Mark for a financial update.

Thank you Chris.

My comments today will highlight some of the financial items in our release, primarily focusing on the sequential changes from the first quarter of 2019 I'll also provide some forward looking guidance to help you in updating your financial models.

Starting on slide 18 second quarter 2019, adjusted net income was $59 million or 13 cents per diluted share.

Ahead of analysts' expectations, and a nice improvement from first quarter earnings.

This quarter, we recognized a non cash gain on debt extinguishment related to our recent debt exchange transactions of 100 million and non cash income of $26 million for fair value changes in commodity derivatives.

We were the primary these were the primary differences from our GAAP net income.

Please note that in computing diluted income per share going forward interest on the convertible notes will be added back to net income and the potential shares to be issued upon conversion will be added to the shares outstanding.

More detail on that calculation is included in our press release.

Turning to slide 19, our non-GAAP adjusted cash flow from operations, which excludes working capital changes was $145 million for the second quarter, our highest level of adjusted cash flow since the third quarter of 2015 adjusted cash flow was up 26 million from the first quarter of 2019, driven primarily by higher oil prices and lower lease operating expenses, we generated free cash flow of 38 million in the second quarter. After considering 22 million of interest that is included as repayment of debt in our financial statements $77 million of development capital and incurred an $8 million of capitalized interest.

Our second quarter average realized oil price before hedges was approximately $62 per barrel.

10% increase from our realized price in the first quarter, we paid approximately $2 million on hedge settlements this quarter as compared to receiving $8 million in settlements last quarter, making our average realized price per barrel, including hedges seventh is 7% higher than last quarter.

Slide 20 provides a summary of our oil price differentials, excluding any impact from hedges for the seventh consecutive quarter, our realized oil price was higher than nymex prices, averaging $2.35 above Nymex, our highest level since the second quarter of 2013.

The premium prices, we received for our Gulf Coast production strengthened from the first quarter and in the Rockies. Our differential also continued to improve from the levels realized last quarter.

For the third quarter, we expect that our overall oil differential remain positive timex, but lower than the levels realized in the second quarter due to the weakening of the LLS differential in the Gulf Coast region, and moderately lower differentials in the Rockies region. We currently estimate that our overall Q3 Nymex differential will be in the range of flat to Nymex two one dollar of Nymex prices.

On slide 21.

We review some of our expense line items since Chris already addressed Ela, we I will start with GSK.

Our DNA expense was $18 million for the second quarter down about 1 million from last quarter, our DNA related to stock based compensation was approximately 4 million this quarter and we expect gene expense will generally be in the upper teens to $20 million range per quarter for the remainder of 2019 with stock based compensation anticipated represent roughly $4 million per quarter.

Net interest expense was 20 million this quarter, an increase of about $3 million over last quarter, primarily due to lower capitalized interest on the bottom portion of the slide you will see there is a detailed breakout of the components of interest expense and you will know cash interest remain steady.

Capitalized interest was approximately $8 million for the second quarter and we currently expect our capitalized interest to be in the seven to 9 million range for the third quarter of 2019.

In connection with the recent notes exchange transactions, the new secondly notes and convertible notes issued were recorded on our balance sheet at a total discount of approximately $110 million to their principal amounts.

These debt discounts will be amortized as interest expense over the terms of the notes therefore future interest expense reflected on our income statement will be higher than the actual interest payments for the new notes by approximately 4 million per quarter for 2019, and 2020 and 5 million per quarter in 2021.

Our depletion depletion and depreciation expense this quarter was $58 million a slight increase from the prior quarter. We expect this expense will increase somewhat and will be in the $60 million range for the remaining quarters of 2019.

The next slide provides a current summary of our oil price hedges. The remainder of 2019 is protected with hedges covering around 70% of the midpoint of our 2019 estimated production range, including weighted average price floors of roughly $57 for W.T.I. in $64 for LLS per barrel.

Since our first quarter conference call. We have continued to layer in hedges for 2020, and now have more than 22000 barrels of oil per day hedged for the year or roughly 40% of the midpoint of our 2019 estimated production range for 2020, our hedges have weighted average floor prices approaching $59 for Wi Fi and $63 for L.S. and similar to 2019 over two thirds of our contracts provide for upside exposure, but close to $66 for diabetes and $72 for less.

We plan to continue to add to our 2020 hedges as we deem appropriate and mark.

And depending on market conditions.

During June and July we completed a series of debt exchanges that reduced the principal balance of our subordinate notes by $120 million and extended maturities on debt principle of 348 million to 2024.

The details of the exchanges are shown in the lower right portion of this slide.

But in summary, we exchanged a total of 468 million of the existing subordinated notes for $103 million of new seven and three quarter percent senior secured second lien notes due 2024.

$246 million of new six and three 8% convertible senior notes due 2024.

And 120 million of cash.

In addition in order to create a more liquid issue of secured debt due in 2024, we also exchanged for $129 million of our previously outstanding 7.5% Senior secured second lien notes due 2024, but roughly the same amount of seven and three quarter percent senior secured second lien notes also due 2024.

We ended the second quarter was 80 million drawn on our 615 million Bank line, giving US 480 million of liquidity after considering outstanding letters of credit.

Our debt principle is just under 2.5 billion, which is right around $1.1 billion principal reduction over the last four and a half years.

Based on current 2019 projection using recent oil prices, we expect to generate sufficient free cash to pay down the 80 million on our bank line by the end of 2019.

Our last slide shows the improvement in our leverage metrics over the past year.

Our trailing 12 months debt to EBITDAX ratio has improved to 4.1 times half term better than the comparable metric a year ago, and if you exclude hedging impacts our trailing 12 month ratio would be 3.6 times.

We are pleased with the steady progress we have made with our leverage metrics and based on recent price futures. We would expect our leverage ratio to continue to hold around four times or possibly slightly lower throughout 2019.

We also want to highlight the strong coverage ratio, we have when measuring the PV 10 value of our oil and gas reserves against our debt principle.

Note that we the PV 10, we are using here as our year end 2018 as Cc proved reserves, which is over 80% proved developed producing.

Reducing our leverage and improving our debt maturity profile remain top priorities. We are pleased with the results of the recent debt exchange transactions, which largely address near term subordinated debt maturities, although bond market conditions are challenging at the current time, we plan to continue our disciplined focus while seeking opportunities to further reduce our leverage and extend maturities of our second lien debt well in front of the first maturities in 2021.

In the back half of 2019, we also plan to evaluate options for funding all or a portion of our CCOH two pipeline, which could include a JV structure with our entire Seo to pipeline system in the Rockies. We're also continuing to progress sales of non core assets such as our non productive acreage position and believe we are close to signing additional contracts that will further highlight.

Potential value.

And now I'll turn it back to John for some closing comments.

Thank you Mark.

That concludes our prepared remarks.

Jeff can you. Please open the call up for questions.

Of course, ladies and gentlemen, as another reminder, if you wish to ask a question over the phone. Please press Star then one you'll hear talent and again you've been placed into the queue. You may move yourself from the queue at any time at press the pound key using a speakerphone. Please pick up the handset before pressing any of the numbers.

Once again to ask a question over the phone. Please press Star then one.

Our first question comes from the line of Charles Mehdi with Jason Rae. Please go ahead.

Mehdi I haven't heard that one before.

Certainly.

And we'll take that to you your whole team there. There's a lot of question you guys have given us the us a lot to chew on and you've made some love it.

Put up a lot of good good points in this last quarter, but I'm just going to pick two real quick one could you talk about what Youre Seo to Capex is going to look like.

Using kind of Twoq you as tissue 19 is a baseline what's it going to look like per quarter in the back half of this year.

And then.

You know I know Theres, a big decision point about how you are you finance the.

The CCH pipeline, but but assuming that that you don't have any kind of outside partner there what would the gross capex per quarter looked like in 20.

You bet Charles So ill take the first question first just looking at our CEO to Capex for for 2019.

The vast majority of what you see there is the cc a pipeline and the procurement and coding of the line pipe this year and the bulk of that which I believe were looking at about 30 million. The bulk of that over 20 million has already been incurred through the first half of this year, so you'd see that.

That.

Weighted disproportionately towards the front end the year with the remainder to be spent in the final two quarters of the year.

We're not really to point to give the quarterly guidance for how we see 2020 shape up but again the bulk of the investment you'd see around that in the in 2020 would be the installation of the pipe and so that's about 100 million dollar line item that we'd see a taken place over the course of the year.

And then of course, the the great question that you that you added in there as how does that fit into how we set up our capital for next year.

And for that I dial back a bit and just to ask you to take a look at this year and how our operations have performed and how what I see as our teams doing a great job.

Holding our production close to flat at an ever reducing level of capital if I, if I peel that $30 million of CCH pipeline type capital out were spending about 220 million, let's say on maintenance capital this year.

And holding production close to flat.

We're committed to driving free cash and living within cash flow as we approach 2020, you will see the same thing and of course, we're going to have to see where where prices are at at that points to decide how to allocate capital.

But as we.

As we look at our two key commitments here one is to live within cash flow. The other is to progress this great CA project, which.

Still to us is very strong at $50 oil.

The interest that we've had from the outside in terms of helping fund that in various ways is very high and we're going to continue to work that through the remainder of this year and look at just what is that best option there.

As we've said before.

We're open to funding it ourselves depending on on cash flow, but we're also open to bringing in some outside money and that's just a decision we're going to have to take as we get closer to the end of the year and see how how prices start to shake out.

Got it that's helpful. Chris and then.

If I could ask about the.

The conroe to a.

The two eight test can you tell us about how that.

That came in versus your.

Versus your previous range of of a possible or expected outcomes and in about a week.

Maybe as part of that calibrate what should we be looking for as you try the next fault block over.

Hi, Charles this is Matt Damon.

I'll take that one.

The well came in just slightly under what kind of our midpoint of our expectations were.

Mainly due to a little bit lower reservoir pressure than anticipated.

But extremely pleased with the oil cut and as we look at taking those lessons to the next fault block.

Targeting some intervals was higher pressure little bit higher quality rock and maybe a little bit slightly different completion technique.

So we expect next year.

To drill that well and look for some better results than the first.

Thank you Matt that's good.

Our next question comes from the line of Jason Wangler with comparable cap. Please go ahead.

Hey, good morning, guys.

Why does the operating cost reductions looks pretty significant obviously, you kind of highlighted pointed to the lower end of the guidance in the back half of this year and for the rest of the year can you just talk about kind of what you are seeing there and what we are able to take advantage of.

Yes, Jason This is David Shepherd I'll take that a question good morning to you.

Yes, we made some significant progress and and sustainable low cost reductions I would say.

It's really centered around several things you know from a power fuel perspective, we always look at electricity.

Taking the benefit of renegotiating some of our demand charge contracts. So we'll see that continue to come into the mix here for years the com.

In the Rockies too as well, we've renegotiated a better tariff strategy too as well for our CEO to supply there. So we'll see that same similar benefits in the over a very long period of time.

Oh, well Saddam perspective failure rates and that's something we always look to improve we did see the benefit here in the second quarter.

Of some lower Workover numbers and are primarily associated in the Gulf coast too as well I see that probably ticking up just a little bit in the third quarter and up from what what we see compared to the second quarter, just because we would have some known failures, but I think that will I'm certain that will be a sustained reduction over a period of time I'd say that we have some other projects in the works too as well, we're just looking at our systems our processes chemicals, So non management tool as well. So there is more to call in this particular area.

Okay. That's helpful and then.

Hey, Chris for you just on the exploitation program as you think about going into next year in having some more significant capex is that still going to be a pretty meaningful portion of your spender or how do you kind of think about that as you look to next year.

You bet, Jason and I'd say, our priority next year is going to still stay very focused on.

Working the balance sheet and driving CCH forward. So that's what we're going to look at first obviously, we love our exploitation program. The successes we've had have been.

A powerful and never have done some some very nice things for us in particular up and see a there and thats why were continuing into the latter half of this year with more activities there.

The real question, though as you start to look into 2020 and look at where we want to allocate capital that's one that work on the.

We're going to again as I told Charles we're going to.

Get to closer to the end of the RC how capital.

Shaping up sale prices are shaping up.

And decide where to go we're also looking at some alternatives, where we may be able to bring in some outside participation to to help progress that along in a way that's attractive to denbury in the shareholders.

Keep all those options open as we as we go into the.

Second half of this year here.

That's helpful. Thank you.

Thanks, Jason.

Our next question comes from the line of Michael Scala with Stifel. Please go ahead.

Yeah. Good morning, guys. So I want to see that you've talked about.

Your ability to pay down additional debt with free cash flow Mark you said.

You could pay down the bank line with the free cash flow you are projecting for the second half of this year. If you were to do that.

What would be the the plan for free cash flow next year can you attack any of the longer term debt.

What you see there and where where do you see debt to EBITDA going next year based on strip prices.

Yeah I think.

So we do have some limitations we were work around so obviously, a we used 120 million here.

To pay down some.

That's in the in the exchange, we we have roughly.

28 million remaining under a the bank line in terms of additional capacity under a basket to pay down debt and potentially more under certain scenarios with leverage ratios and and de leveraging aspects that could be and thats. An additional 76 million. So obviously those are baskets, we set a quite a while ago and you know.

Thank you.

They can always be revisited, but those are kind of the parameters that are in place today.

I would say.

Obviously, we have the.

Sub debt maturities in 21, and 22, I think down too.

You know pretty.

Moderate to reasonable levels focus as we look at things really kind of turns to second lien and we'd like to work on extending that debt.

And it is our desire to you know situation obviously, the the debt markets are a bit challenged right now and but you don't have to do anything right today, but that's where you know our thoughts turn and there could be some opportunities I would say, we're debts trading to to take advantage of lower prices and discounts, but obviously, we have to balance that with liquidity liquidity is very important just where prices are going managing cash and so we will take all that into consideration just as we have done in the past if you look back over the last.

Four and a half so five years of living through this.

Yeah pretty volatile oil price environment, I think we've been able to manage through pretty good and we plan to continue to do the same so.

So yeah, we want to continue to reduce leverage and we'll continue to look at the company's best options for doing that depending on market conditions, and where we are at any point in time. So.

And Mike This Chris just what I'd, what I'd add to what Mark just said is even going back to the question of whether we fund the CCH pipeline internally or externally.

How we look at attacking that debt will will play a part in that as well and we can if we can see some benefits to funding the pipeline externally and attacking debt with the money that we the other items have spent but that's something that we'll look out strongly.

Yes, obviously, a lot of moving parts there Dave was given all that do you have any.

Projections on where you think that the EBITDA, if you're doing this year.

You know said for the rest of the year, we kind of see that holding in a relatively stable I think.

If we it really just depends on where the or where the oil price environment.

Goes to Mike as you know, where we've been at relative to various oil price I think if you look at the slide that we show in the on on the Slide show, they're kind of give some relative relativity in terms of where we've been looking back a year ago to last 12 months at various oil prices Advair, where we are today, obviously if prices trend lower you know it could tick up somewhat and just to remind that roughly.

A five dollar move in oil prices about 100 million of EBITDA and you know so the unhedged. So we do have hedges in place next year that will.

Protect us about decent level at this point in time, but obviously, we'd like to continue to expand that but if prices stay you know where the strip is today than it would likely a trend up a little bit, but I don't think it goes up it goes crazy Mike.

It's.

Between the slightly higher where we are today between four to four and a half to.

Range.

Okay got it and then.

My other question.

Yes, obviously, a nice response from Bell Creek.

Was all of that due to the better rock quality or did you do anything different with phase five and I guess, how do you see the.

Trajectory from that field over the remainder of the year as a rollover before phase six kicks in or or could you see some more growth at a baseline.

And Michael This is Matt day hand.

So production increase certainly phase five is performed fabulous.

It's one of the reasons, we love this business I could feel that makes virtually nothing and now well over 2500 barrels a day in that phase alone.

It is the best quality between phases, five and six in the field.

As you remember.

This field was developed or his section was developed.

A little bit differently and that the spacing is wider taking advantage of that higher quality rock, reducing the capex to to recover those reserves.

We couple that with.

The phase four wells that we drilled so Chris pointed out taking advantage of our seismic identified an area that was basically untapped.

We precisely placed the well over 500 barrels a day, we'll continue to see that well increases it's easier to response going forward.

Great that seismic met any application to any other fields thing and maybe in terms of CCH as you go forward with it.

Oh very much so I mean, we use seismic in the Gulf coast.

For the same same reasons I understand where the C. O two is and more importantly, where it hasn't gone.

And then make adjustments to the field performance.

We have shot seismic and CA, we'll continue to look at that going forward as we again begin injection.

Thank you.

Thanks Bye.

And our next question comes from the line of Richard Tullis with capital One Securities. Please go ahead.

Thanks, Good morning, everyone, I'm, Mark and Chris.

If you could maybe provide a little more detail on how you think in the structure could kind of come together for a potential.

JV related to pipeline funding.

Oh sure <unk>. This is mark as you know we have the existing Greencore line in the Rockies that we transport Seo to through today to Bell Creek.

We have the plan line going up to CCH. So if we wanted to a one option as we've kind of talked about before put that all together is one system and have a joint venture partner.

Maybe 50, 50 or something around that or we would contribute the existing line the.

Partner could fund the a portion of 150 million or so for the CCMA line and and we would go forward and joint ownership of of that structure.

Obviously when things were focused on as you know, we don't want to add more debt and so structures and important.

But but that is one.

Potential opportunity or avenue that that we see.

Thank you Mark and.

Chris in your opening remarks, you talked about and also in the release itself talked about you know the changing landscape and what opportunities that presents to denbury given its.

Long history of enhanced oil recovery tertiary operations.

You know as you as you look over the next several years, how do you envision denbury evolving did did those opportunities perhaps result in denbury contracting out its expertise in those areas for a fee or an equity position in other projects or just what are some of those potential options there.

Sure Richard I see tremendous opportunities for Denbury and this future the.

The changes that we feel and that I see in the world and in the industry or are strong.

And it's ironic with so much noise out there even in a day like today for example.

I would rather be denbury than any other company because the nature of what we do.

So perfectly aligns with this drive to reduce carbon emissions when we look at.

How seo to equal our extracts oil that technique being.

Substantially better than any other oil recovery techniques thats out there and we are focused primarily on that technique I <unk> you have to feel good about where you sit in in that role and as I mentioned in my prepared remarks, as we go more towards using industrial so our COO to where you are truly taking siloed, who that would otherwise be emitted into the atmosphere.

And injecting it.

That's a very strong move that supports a this combination of providing energy that the world needs and the lowest carbon footprint way possible. So I feel great about that.

Now where that goes it can go in many different directions number one it can be just more of what we're already doing and conventional fields like you see in CCM.

I think it can expand with equal or in other areas like shale as we've as we've talked about in the past.

I think that's it.

Can they the same skill sets that's that that we have and use can be applied to.

Transportation and other geologic sequestration Epo to that's that's a skill set that I think denbury has.

To your question of whether we contracted out that's a that's a whole nother a way of thinking about.

Our approach in the business and obviously say, we're not close to anything I think the skills that we have or just have a grace.

Opportunities that will that they'll open in the future.

That's helpful. Chris. Thank you and that's all from me appreciate it thanks for the question Richard.

[noise].

Our next question comes the line of Joe.

Bonani with.

Oppenheimer. Please go ahead.

Joe on for Tim Here, Andrew Page.

So if I could ask on the on the asset itself.

You guys had a pretty productive.

Order.

<unk>, but just kind of qualitatively.

How.

How far along in the process are you is that 50% of of the.

I think Joe do you actually just nailed it that when we when I think about where we are in the process and we are happy with the results that were able to report this quarter, but when I think about where we are in the process I'd say, we're about 50% through we still have a an awful lot of value out there that we're working through right now and so.

There is still plenty of potential to come as far as far as I see on those asset sales.

Alright, then our next question then comes the line of Shaun.

Sneeden with.

Guggenheim. Please go ahead.

Good morning, and thank you for taking the questions actually shrunk.

Mark maybe just a follow up on the prior.

That question, but can you remind us or are there restrictions on your ability to repurchase any the second liens at a discount.

At this point.

None that are coming to mind, Sean I'd have to check.

I just want to make sure but know nothings popping in my head right right off the bat.

Got it so only the.

The unsecured bonds you do you have that kind of view from basket in that sense.

Yeah like I said, we'd have to double check a couple of things there, but there may I think there is some some difference between the saudis most of their focus obviously over the.

The.

Last several years has been around the subs.

But so we need to check that but I do think we have a little bit more flexibility there.

Understood understood.

HM.

And then you could use a.

Remind us <unk> you what you think your kind of remaining secured debt capacity is that now that you've got the exchange side than the ended the quarter.

The well so yeah. So we did we had a 1.65 billion of basically junior lien debt as permitted under our our facility and so we've as issued all but just a little bit of that I guess.

So so we've used up most of that.

That can that's what's available or what was permitted under the bank line you know that can be reviewed and move around based on AC and Ta.

But but thats, what we have remaining today.

Got it that makes sense.

And then you Chris Oh, <unk> I know you mentioned potentially bringing in a partner and I think a lot of discussion was specifically around the pipe for CCH.

But.

Would you.

Look at or entertain partners on the development side for CCH, just given how big of an opportunity set is for you.

You bet Sean.

You know I I go back to Mark's comments earlier, and just how our structure is set up and one thing you'll find in the in the capital structure of the company and the various different so.

The agreements that we have is that we have.

Simplicity that allows us to do many different things and so one of those is financing the pipeline as we talked about but I also think that as we look at how that could how that could extend and how much more broad that could be.

The.

Possibility of participating in the development is something that is out there I mean, it's something that we're very proud of and we want to take a hard look at that but honestly just at this at this point.

And the development, we're going to be looking at different options and that's one that I think we consider as well.

Got it.

That makes sense.

I would assume that you potentially you could look at.

Kevin.

An overriding royalty or other kind of options that some folks.

In the market have done recently, yes, and that's a that's why I actually started by my answer by referencing the simplicity of the structure.

After those recent industry moves to the overrides weve taken a few inbounds on that and that's a that's another option that we see out there as well.

Perfect. Appreciate the color guys. Thank you thanks, John Thanks.

And there are currently no other questions in the queue and I'd like to turn it back over to Mr. Meyer.

Thank you Jeff.

Before you go let me cover a few housekeeping items.

On the conference front, we will be attending Enercom, the oil and gas conference next week on Wednesday.

On Tuesday August 13.

The details for the conference and webcast for the related presentations will be accessible through the Investor Relations section of our website at a later date.

Finally for your calendars. We currently plan to report our third quarter 2019 results on Thursday November seven.

And hold our conference call that day at 10 am central.

Thanks again for joining us on today's call.

Ladies and gentlemen, this does conclude our conference call for today. Thank you for your participation and using 18 T. Executive Teleconferencing you may now disconnect.

Conference recording has stopped.

[noise].

Ill turn the conference over to our host director of Investor Relations. Mr. John Mayer. Please go ahead.

Thank you Jeff Good morning, everyone and thank you for joining us today.

With me on the call are Chris Kendall, our President and Chief Executive Officer.

Mark Allen, our executive Vice President and Chief Financial Officer.

<unk>, our senior Vice President of business development and technology.

And David Sheppard, our senior Vice President of operations.

Before we begin I want to point out that we have slides, which will accompany today's discussion.

Did you encounter any issues with slides advancing during the webcast portion of the presentation. Please refresh your browser.

For those of you that are not accessing the call via the webcast. These slides may be found on our homepage at <unk> dot com by clicking on the quarterly earnings Center link under resources.

I would also like to remind you that today's call will include forward looking statements that are based on the best and most reasonable information we have today.

There are numerous factors that could cause actual results to differ materially from what is discussed on today's call.

You can read our full disclosure on forward looking statements and the risk factors associated with our business in the slides accompanying today's presentation. Our most recent SEC filings and today's news release, all of which are posted on our website at <unk> Dot com.

Also please note that during the course of today's call, we will reference certain non-GAAP measures.

Reconciliation and disclosure relative to these measures are provided in today's news release as well as on our website.

With that I will turn the call over to Chris.

Thanks, John and thanks to all of you for joining us today.

I am pleased to announce a Denver, a second quarter of 2019 was truly outstanding.

<unk> are looking forward to sharing details with you this morning, but before we do that.

I'd first like to talk a bit about the current macro environment.

Specifically I'd like to review, how Danbury strategy assets and expertise aligned to capture many of the challenges facing the energy industry today.

When I step back and think about those challenges I see two key themes emerging.

The first centers on how energy companies will meet clear investor demands to operate sustainable businesses that can return capital to shareholders.

The second involves the industry's ability to consistently provide a significant portion of the world's energy in a manner that addresses increasing environmental concerns around the production of fossil fuels.

I can say with confidence that Danbury is ideally placed to meet these challenges.

The company is in a strong position to meet shareholder demands for return of capital. Our long lived low decline low capital intensity high margin assets have provided us the flexibility under which we have been able to consistently and reliably generate free cash.

We have subsequently use that free cash to optimize the balance sheet, reducing our debt commitments by over $1 billion since the end of 2014.

We will continue to prioritize debt reduction through the use of free cash in the near future.

At its core our business involves the utilization of Cotwo for enhanced oil recovery injecting millions of tons of cotwo into our reservoirs every year.

Over 3 million tons per year of that Cotwo is currently captured from industrial sources that could otherwise have been admitted into the atmosphere.

Putting that number in perspective, we're injecting the emissions equivalent of nearly 700000 cars every year.

As <unk> grows over time, we expect that number to increase significantly with our major new development at Cedar Creek anticline flooded with 100% industrial sourced cotwo.

This oil recovery technique using industrial sourced cotwo provides the lowest carbon footprint from oil production in the industry.

As the only U S public company of scale with <unk> as a primary strategy.

This places <unk> in a unique and beneficial position within the industry.

Particularly given that our growth plans are based around utilizing increasing levels of industrial sourced cotwo.

Looking further into the future I believe that carbon capture transportation and secure geologic sequestration will become an essential business and <unk> assets and expertise position the company to be a leader as this market develops.

Turning now to the quarter <unk> performance was outstanding by all measures and I could not be more proud of the work accomplished by our teams across all facets of the business.

Most importantly, we maintain safe working conditions for our employees and contractors and upheld our duties as stewards of the environment driving our performance higher in all key HSE metrics.

Total production was slightly up from the first quarter of 2019 supported by Great results at Bell Creek, where we reached a new production record.

This performance has given us the opportunity to increase the midpoint of our full year 2019 guidance range, even after the midyear sale of our citronella field and its associated production.

I am pleased to share that we accomplished these strong production results all while maintaining our originally guided annual capital range.

Importantly, we remain on track for the remainder of the year at the midpoint of that range.

Operating costs across the business were significantly reduced in the quarter and we now expect annual LOE to be in the lower half of our previously guided range.

We further reduced our G&A levels, which are now around half of what they were as recently as a few years ago.

We continued making progress towards our CCA enhanced oil recovery development, which is on track for field pipeline installation next year.

We completed an initial test of a promising exploitation concept at conroe.

We've made good progress on noncore asset divestitures, selling citronella and contracting $38 million in incremental Houston area land sales.

We executed a debt exchange that significantly reduced our near term subordinated debt maturities without increasing interest expense.

Our oil Levered production with high Gulf Coast premium pricing exposure resulted in strong realizations of nearly $61 per Boe.

High operating margins and $38 million and free cash flow generation.

Finally, and importantly, we continued to make progress on our priority of reducing leverage with total debt to EBITDA now reduced to just over $4, one times or three six times on a second quarter annualized basis.

Over the next few slides I'll review the quarter in more detail.

On slide eight we've updated our free cash flow projections based on actual results through the first half of 2019.

Assuming $55 <unk> for the remainder of the year, we forecast full year free cash flow of between 120 and $150 million.

In line with our priority of improving the balance sheet, we used $120 million in cash as part of our second quarter debt exchange, which we expect to be funded through current year free cash flow.

These cash flow projections are enhanced by our strong hedge position.

Position, which protects about 70% of our 2019 production.

Mark will share more detail on that shortly.

<unk>, 97% oil weighting once again contributed to very strong operating margin our second quarter revenue per BOE was nearly $61, resulting in an operating margin of just under $33 per Boe.

This high operating margin combined with our low capital spend supports the strong free cash flow that <unk> consistently delivers.

Capital spending is exactly where we wanted at this point in the year as planned we made the bulk of our 2019 CCA Cotwo up line pipe investments in the second quarter.

By the end of the third quarter 2019, we expect all pipe will be completed and prepared for installation in 2020.

Our key tertiary capital project at Heidelberg is substantially complete and our Bell Creek Phase six project should be completed this quarter.

Our primary capital plans for the second half of the year include the continuation of our mission Canyon exploitation program additional drilling in the Charles formation, another well and be in Bell Creek targeting an untapped accumulation in the phase one through four area.

With the completion of our major expenditures for the first half of the year.

We expect capital to reduce in the second half and that total full year capital will be near the midpoint of our guidance range.

I am very pleased with the continued reliability and predictability of our production with second quarter 2019 production slightly ahead of our previously guided expectations of being flat with the first quarter 2019.

Production performance has been strong across the board highlighted by record production levels at Bell Creek and I'll go into more detail on our work there shortly.

As we discussed in our first quarter call, we expect third quarter production to be lower than the second quarter, mainly due to an extended period of planned maintenance at our primary north region Cotwo source as well as seasonal temperature effects in the Gulf Coast.

However, we expect fourth quarter production to rebound.

Primarily driven by response from our Heidelberg redevelopment completion of the North region, <unk> supply maintenance and the impact of new exploitation wells to be drilled throughout the third and fourth quarters.

We've maintained a focus on continuing to optimize our portfolio and as a result sold a noncore citronella field in Alabama at the beginning of the third quarter. This field was producing about 400 net barrels per day at the time of the sale.

Considering our strong production performance. So far this year, we are increasing the midpoint of our guidance range by 250 Boe per day after accounting for divested Citron El production for the second half of the year and we're also tightening the guidance range to <unk> 57 to 59 500 Boe per day.

Yes.

I am excited to say that performance at Bell Creek, just keeps getting better.

The second quarter 2019 production of nearly 6000 barrels per day and made it the company's highest producing EUR field.

As we expected phase five performance has been the best of any phase completed to date and.

And we have now substantially completed the development of phase six which has similar characteristics to phase five setting up additional field production growth in 2020.

Developed Creek team has also looked back at the initial development phases of the field.

And by using high resolution seismic imaging has identified untapped incremental oil accumulations, one of which we drilled in the first quarter.

That well has been a strong producer at around 500 barrels of oil per day.

And we've identified a handful of additional similar opportunities that we plan to begin testing later this year and into 2020.

Our operating teams made excellent progress in reducing costs in the second quarter.

Unit costs were lower than anticipated at $21 70 per Boe.

8% below the first quarter level.

The key improvements were realized in <unk> power and fuel and Workovers, which are based on value, adding sustainable low management strategies.

<unk> costs have benefited from ongoing utilization optimization in several fields, along with an improved tariff structure in the Rockies.

Renegotiated electricity demand charges in several fields, lower natural fuel gas gas fuel prices and fewer well failures and the Gulf Coast are also pushing cost lower.

Given the momentum of our per BOE cost reductions, we expect that our full year 2019, <unk> will fall in the lower half of the previously guided LOE range of 22% to $24 per Boe.

During the second quarter, we tested our first horizontal well in the Conroe field.

We're pleased with the initial results of this test well with a high oil cut at around 50% and a peak production rate of over 200 Boe per day.

We next plan to drill a second well in an adjacent fault block that considers learnings from the first well, it's likely that the second well will be drilled in 2020.

As I previously mentioned, we believe that this exploitation concept can be applied across many of our Gulf coast fields and our teams are conducting the technical work to prepare for next steps in this play.

At Tinsley, we tested the cotton valley interval of our recently drilled exploitation well.

While we were pleased to achieve a $2 5 million cubic feet per day gas rates and high liquid yield of 100 barrels of oil per day. These.

These test results coupled with current commodity prices would make a standalone lower cotton valley development fall below our investment threshold.

We're working plans to test the identified uphold pay intervals, which we believe to be higher in liquid content.

Once we've completed those plans and tests will determine the next best steps, which could include self development or potentially farming out the discovery to a third party.

In late August we plan to resume exploitation drilling at CCA over the past two years, our exploitation investments at CCA have proven very successful with strong production and outstanding economics.

Later this year, we plan to drill two new mission Canyon Wells, one in cabin Creek and another in Coral Creek as well as the new Charles B well also in cabin Creek.

We are intrigued by the performance of the initial Charles B well, while its initial oil rate was lower than a typical mission canyon well, it's sustained high oil cut makes a horizon a good candidate for both water and Cotwo flooding.

Moving to our divestment program, we made good progress on monetizing noncore assets in the second quarter.

Starting with our Houston area property sales, we now have an additional $38 million and multiple parcels at conroe and Webster under firm contract with closing structures that result, and the receipt of proceeds in 2019 through 2022.

This brings our total sold or under contract to a total of 53 million to date with significant remaining value on the property is still being marketed.

Also as I mentioned earlier on July one, we divested of our noncore citronellol field for $10 million in cash and the elimination of an abandonment obligation estimated at about $40 million or $9 million when discounted to today's dollars.

This field was expected to produce an average of 400 net barrels per day in 2019.

We considered it noncore both due to its higher operating cost and our technical and economic analysis that it was not a good candidate for a cotwo flood.

We will continue to evaluate the remaining mature properties for sale or retention and will proceed in a manner that generates the greatest value for the company and our shareholders.

In summary, I'm thrilled with our performance so far this year our business at Danbury continues to outperform our assets are located in the right basins to optimize our unique cotwo our techniques and our teams across the company are highly skilled and experienced and importantly, we remain focused on.

The challenges that lie ahead with <unk> unique capability to not only meet those challenges but to benefit from them.

Next I'll turn it over to Mark for a financial update.

Yes.

Thank you Chris My.

My comments today will highlight some of the financial items in our release, primarily focusing on the sequential changes from the first quarter of 2019 I'll also provide some forward looking guidance to help you in updating your financial models.

Starting on slide 18 second quarter 2019, adjusted net income was $59 million or <unk> 13 per diluted share ahead of analysts' expectations and a nice improvement from first quarter earnings. This quarter, we recognized a noncash gain on debt extinguishment related to our recent debt exchange transactions of 100.

And noncash income of $26 million for fair value changes in commodity derivatives. We were the primary these were the primary differences from our GAAP net income.

Please note that in computing diluted income per share going forward interest on the convertible notes will be added back to net income and the potential shares to be issued upon conversion will be added to the shares outstanding.

More detail on that calculation is included in our press release.

Turning to slide 19, our non-GAAP adjusted cash flow from operations, which excludes working capital changes was $145 million for the second quarter, our highest level of adjusted cash flow since the third quarter of 2015, adjusted cash flow was up $26 million from the first quarter of 2019 driven primary.

Really by higher oil prices and lower lease operating expenses, we generated free cash flow of $38 million in the second quarter. After considering $22 million of interest that is included as repayment of debt in our financial statements $77 million of development capital.

<unk> and $8 million of capitalized interest.

Our second quarter average realized oil price before hedges was approximately $62 per barrel.

10% increase from our realized price in the first quarter, we paid approximately $2 million on hedge settlements this quarter as compared to receiving $8 million in settlements last quarter, making our average realized price per barrel, including hedges seven 7% higher than last quarter.

Slide 20 provides a summary of our oil price differentials, excluding any impact from hedges for the seventh consecutive quarter, our realized oil price was higher than Nymex prices, averaging $2 35 above Nymex, our highest level since the second quarter of 2013.

Premium prices, we receive for our Gulf Coast production strengthened from the first quarter and in the Rockies. Our differential also continued to improve from the levels realized last quarter.

For the third quarter, we expect that our overall oil differential will remain positive timex, but lower than the levels realized in the second quarter due to the weakening of the LLS differential in the Gulf Coast region, and moderately lower differentials in the Rockies region. We currently estimate that our overall Q3 Nymex differential will be in the range of flat to Nymex.

<unk> to $1 above Nymex prices.

On slide 21.

We review some of our expense line items since Chris already addressed LOE I will start with G&A. Our G&A expense was $18 million for the second quarter down about $1 million from last quarter, our G&A related to stock based compensation was approximately $4 million this quarter and we expect G&A expense will generally be in the upper teens to 20 million.

Dollars range per quarter for the remainder of 2019 with stock based compensation anticipated to represent roughly $4 million per quarter.

Net interest expense was $20 million this quarter, an increase of about $3 million over last quarter, primarily due to lower capitalized interest on the bottom portion of the slide you will see there is a detailed breakout of the components of interest expense and you will note cash interest remained steady.

Capitalized interest was approximately $8 million for the second quarter and we currently expect our capitalized interest to be in the $7 million to $9 million range for the third quarter of 2019.

In connection with the recent notes exchange transactions, the new second lien notes and convertible notes issued were recorded on our balance sheet at a total discount of approximately $110 million to their principal amounts.

These debt discounts will be amortized as interest expense over the terms of the notes therefore future interest expense reflected on our income statement will be higher than the actual interest payments for the new notes by approximately $4 million per quarter for 2019, and 2020 and $5 million per quarter in 2021.

Our depletion our depletion and depreciation expense this quarter was $58 million a slight increase from the prior quarter. We expect this expense will increase somewhat and we will be in the $60 million range for the remaining quarters of 2019.

The next slide provides a current summary of our oil price hedges. The remainder of 2019 is protected with hedges covering around 70% of the midpoint of our 2019 estimated production range, including weighted average price floors of roughly $57 for <unk> and $64 for LLS per barrel.

Since our first quarter conference call. We have continued to layer in hedges for 2020, and now have more than 22000 barrels of oil per day hedged for the year or roughly 40% of the midpoint of our 2019 estimated production range for 2020, our hedges have weighted average floor prices approaching 59.

For <unk> and $63 for LLS and similar to 2019 over two thirds of our contracts provide for upside exposure of close to $66 for WTO and $72 for LLS. We plan to continue to add to our 2020 hedges as we deem appropriate in the market.

Depending on market conditions.

During June and July we completed a series of debt exchanges that reduced the principal balance of our subordinated notes by $120 million and extended maturities on debt principal of $348 million through 2020 for.

The details of the exchanges are shown in the lower right portion of this slide.

But in summary, we exchanged a total of $468 million of existing subordinated notes for $103 million of new 7% and three quarter percent senior secured second lien notes due 2024 to.

$246 million of new six and three 8% convertible senior notes due 2024 and $120 million of cash.

In addition in order to create a more liquid issue of secured debt due in 2024, we also exchanged for $129 million of our previously outstanding seven 5% senior secured second lien notes due 2024 for roughly the same amount of seven and three quarter percent senior secured second lien notes also due 2024.

We ended the second quarter was $80 million drawn on our $615 million Bank line, giving us $480 million of liquidity after considering outstanding letters of credit our.

Our debt principal is just under $2 5 billion, which is right around a $1 1 billion principal reduction over the last four five years.

Based on current 2019 projections using recent oil prices, we expect to generate sufficient free cash to pay down the $80 million on our bank line by the end of 2019.

Our last slide shows the improvement in our leverage metrics over the past year, our trailing 12 months debt to EBITDAX ratio has improved to four one times half turn better than the comparable metric a year ago, and if you exclude hedging impacts our trailing 12 month ratio would be three six times.

We are pleased with the steady progress we have made with our leverage metrics and based on recent price futures. We would expect our leverage ratio to continue to hold around four times or possibly slightly lower throughout 2019.

We also want to highlight the strong coverage ratio, we have when measuring the PV 10 value of our oil and gas reserves against our debt principal.

Note that we the PV 10, we are using here is our year end 2018, SEC proved reserves, which is over 80% proved developed producing.

Reducing our leverage and improving our debt maturity profile remain top priorities. We are pleased with the results of the recent debt exchange transactions, which largely address near term subordinated debt maturities, although bond market conditions are challenging at the current time, we plan to continue our disciplined focus while seeking opportunities to further reduce our leverage.

<unk> and extend maturities of our second lien debt well in front of the first maturities in 2021.

In the back half of 2019, we also plan to evaluate options for funding all of our portion of our CCA Cotwo pipeline, which can include a JV structure with our entire <unk> pipeline system in the Rockies. We are also continuing to progress sales of noncore assets, such as our nonproductive acreage positions and believe we are close.

Signing additional contracts that will further highlight the potential value and now I'll turn it back to John for some closing comments.

Thank you Mark that.

That concludes our prepared remarks.

Can you please open the call up for questions.

Of course, ladies and gentlemen, as another reminder, if you wish to ask a question over the phone. Please press Star then one you will hear a tone in makena, you've been placed into the queue humira remove yourself from the queue at any time at <unk> and the pound key.

Using a speakerphone please pick up the handset before pressing any of the numbers.

Once again, if you wish to ask a question over the phone Please press star and one.

Our first question comes from the line of Charles <unk> with Jason Rice. Please go ahead.

I haven't heard that one before.

Good morning to you.

Your whole team there.

There's a lot of questions you guys have given.

So lots to AWN and you've made some lubbock.

Put up a lot of good good points in this last quarter, but I'm just going to pick two real quick one could you talk about what your.

Capex is going to look like.

Using kind of <unk> is <unk> 19, as a baseline what's it going to look like per quarter in the back half of this year and then.

I know Theres a big decision.

A decision point about how you how you finance the deal.

CCA pipeline, but Keith, but assuming that you don't have any kind of outside partner there what would be what would the gross capex per quarter look like in 'twenty.

You bet Charles so.

Take the first question first just looking at our <unk> Capex for for 2019.

The vast majority of what you see there is the.

CCA pipeline in the procurement and coding of the line pipe this year and the bulk of that.

I believe we're looking at about 30 million the bulk of that over $20 million has already been incurred through the first half of this year. So you would see that.

<unk>.

Weighted disproportionately towards the front of the year with the remainder to be spent in the final two quarters of the year.

Not really to point to give the quarterly.

Quarterly guidance for how we'd see 2020 shape up but.

Again, the bulk of the investment you'd see around that in 2020 would be the installation of the pipe and so thats about $100 million line item that we'd see taken place over the course of the year and then of course.

The great question that you added in there is how does that fit into how we'd set up our capital for next year.

And for that dial back a bit and just.

Ask you to take a look at this year and how our operations have performed and how what I see as our team is doing a great job.

At holding our production.

Close to flat at an ever reducing level of capital.

I feel that $30 million of CCA pipeline type capital out we're spending about $220 million, let's say on maintenance capital this year and holding production close to flat we're.

We're committed to driving free cash and living within cash flow as we approach 2020, you'll see the same thing and of course, we're going to have to see where prices are at that point to decide how to allocate capital.

But as we.

As we look at our two key commitments here one is to live within cash flow. The other is to progress this great CCA project, which.

Bill to us is very strong at $50 oil.

The interest that we've had from the outside in terms of helping fund that in various ways is very high and we're going to continue to work that through the remainder of this year and look at just what is that best option there as.

As we said before.

We're open to funding it ourselves depending on on cash flow, but we're also open to bringing in some outside money and that's just a decision we're going to have to take as we get closer to the end of the year and see how how prices start to shake out.

Got it got it that's helpful. Chris and then if I could ask about the the conroe two way.

Two eight test can you talk about how that.

That came in versus your.

Versus your previous range of possible or expected outcomes in and about.

It may be as part of that calibrate what should we be looking for as you try the next fault block over.

Hey, Charles this is Matt <unk> I'll take that one well came in just.

Slightly under what kind of our midpoint of our expectations were.

Mainly due to a little bit lower reservoir pressures than anticipated.

But extremely pleased with the oil cut and as we look at it taking those lessons to the next fault block.

We're getting some intervals with higher pressure, a little bit higher quality rock and maybe a little bit slightly different completion technique.

So we expect next year to drill that well and look for some better results down the first one.

Thank you Matt this is good.

Our next question comes from the line of Jason Wangler with <unk>. Please go ahead.

Hey, good morning, guys good morning.

The operating cost reductions looks pretty significant obviously, you've kind of highlighted pointed to the lower end of the guidance in the back half of this year and for the rest of the year can you just talk about kind of what you were seeing there and what we were able to take advantage of.

Yes, Jason This is David Shepherd I'll take that.

My question good morning to you yes.

Yes, we made some significant progress and sustainable low cost reductions I would say, it's really centered around several things from a power fuel perspective, we always look at electricity.

<unk> taken the benefit of renegotiating some of our demand charge contracts. So we'll see that continue to come into the mix here for years to come.

In the Rockies too as well, we've renegotiated a better tariff strategy too as well for our <unk>.

<unk>. So we'll see that same similar benefits over a very long period of time.

From our wells and our perspective failure rate to now that's something we always look to improve we did see the benefit here in the second quarter.

Lower on our Workover numbers, primarily associated in the Gulf coast as well.

I see that probably ticking up just a little bit in the third quarter.

What we see.

Where did you see that doggone next year based on strip prices.

Yeah I think.

So we do have some limitations we work work around so obviously, we used 120 million here.

Pay down some.

And the exchange, we we have roughly 28 million remaining under the bank one in terms of additional capacity under a basket to pay down debt and potentially more under certain scenarios with flybridge ratios and and deleveraging aspects that.

Could be an additional 76 million. So obviously those are baskets, we said quite a while ago.

And I think.

They can always be revisited, but those are kind of the parameters that are in place today.

I would say.

Obviously, we have the.

Sub debt maturities in 21, and 22, I think down too.

Pretty.

Moderate reasonable levels.

Focus as we look at things really kind of turns to second lien and would like to work on extending that debt.

And as our desired.

Situation, obviously, the the debt markets are a bit challenge right now and but you don't have to do anything right today, but that's where our thoughts turn and there could be some opportunities, obviously where deaths trading too.

Take advantage of lower prices and discounts but.

Obviously, we have to bounce out with liquidity and liquidity is very important.

Just where prices are going managing cash and so we will take all that into consideration just as we have done in the past. If you look back over the last four and a half five years of living through this pretty volatile oil price environment.

I think we've been able to manage through pretty good and we plan to continue to do the same so.

So yeah, we want to continue to reduce leverage and we will continue to look at the company's best options for doing that depend.

Depending on market conditions, and where we are at any point in time so.

This is Chris just what I, what I would add to what Mark just said is even going back to the question of whether we fund the CCA pipeline internally or externally.

How we look at attacking the that will play a part in that as well or if we can see some benefits to funding the pipeline externally and attacking that with the money that we the other items have spent then that's something that will will look at strongly yep.

Yeah, obviously, a lot of moving parts there was a given all that do you have any.

Projections on where you think that even talked to go next year.

He said for the rest of the year, we kind of see that holding in a relatively stabilised I think.

If we it really just depends on where the.

Where the oil price environment.

Goes to Mike as as you know.

And where we've been at various oil price I think if you look at the slide that we <unk>.

Show in the.

On the on the slide show, they're kind of give some relatives relativity in terms of where we've been looking back a year ago through last 12 months at various oil prices there.

Where we are today, obviously if prices.

Friend lower.

It could take up some watson just to remind that roughly.

A five dollar moving oil prices about 100 million of EBITDA and.

So unhedged. So we do have hedges in place next year that will protect us Saddam.

Decent level at this point in time, but obviously, we'd like to continue to expand that but if prices stay.

Where the strip is today then I.

Would likely trend up a little bit, but I don't think it goes it goes crazy Mike it's.

Between the.

The higher where we are today between Florida, four and a half to range.

Okay got it and then another question.

Obviously, a nice response from Bell Creek.

Was all of that due to the better rock quality or did you do anything different with phase five and I guess, how do you see the.

Trajectory from that field over the remainder of the year is that rollover before phase six kicks in or or could you see some more growth out a baseline.

Yeah, Michaels, Matt day hand.

So production increase certainly phase five is performed fabulous.

It's one of the reasons, we loved this business you can take a field.

Makes virtually nothing and now we are over 2500 barrels a day in that phase alone.

It is the best quality between phases, five and six in the field.

If you remember this field was developed or this section was developed a little bit differently and at the spacing is wider taking advantage of that higher quality rock, reducing the capex too to recover those reserves.

Couple that with.

The phase four well, we drilled so Chris pointed out taken advantage of our seismic identified an area that was basically untapped.

We precisely place to well over 500 barrels a day will continue to see that well increases at C. C. O. Two response going forward.

Great seismic men have any application to any other fields again, maybe in terms of CCA as you go forward with that Oh.

Oh very much so I mean, we used seismic in the Gulf coast.

For the same same reasons understand where the C. O two is and more importantly, where it hasn't gone and then make adjustments to the field performance we.

We have shot seismic and CCA, we will continue to look at that going forward as we can begin injection.

Thank you.

Thanks Bye.

And our next question comes from the lineup Richard tell us with capital on Security. Please go ahead.

Yeah. Thanks, Good morning, everyone, Mark and Chris.

If you could maybe provide a little more detail on how you think and the structure could kind of come together for a potential J.

JV related to pipeline funding.

Oh sure.

This is mark as we have the existing Greencore line in the Rockies that would transport C O two through today to Battle Creek.

We have.

The plan line going up to CCA. So if we wanted to one option is we've kind of talked about before.

That altogether is one system and have a joint venture partner maybe.

50, 50 or something.

Around that we would contribute the existing lines the.

Partner could fund the portion of $150 million or so for the CCA line.

And and we would go forward and join ownership of that structure.

Obviously when things were focused on us we don't want to add more debt so structures an important.

But but.

But that is one.

Potential opportunity or Avenue that we see.

Thank you Mark and.

Chris in your opening remarks, you talked about and also when you release itself talked about the changing landscape and what opportunities that presents to Danbury given it.

Long history of enhanced oil recovery tertiary operations.

If you look over the next several years, how do you envision Danbury.

Evolving.

Those opportunities, perhaps result in den very contracting out its expertise in those areas for a fee or an equity position and other projects or just what are some of the potential options there.

For Richard.

See tremendous opportunities for den Barry in the future.

The.

The changes that we feel and that I see in the world and in the industry are strong.

And it's ironic with so much noise out there even in the day like today for example, I would rather be den berry than any other company because the nature of what we do.

Okay. So perfectly aligns with this drive to reduce carbon emissions when.

When we look at.

How do you go to EUR extracts oil that technique.