Q2 2020 QEP Resources Inc Earnings Call

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Greetings and welcome to make sure E. P resources second quarter 2020 earnings conference call. At this time, all participants starting to listen only mode. A question answer session will follow the formal presentation. If any what's your acquire operator assistance during the call. Please press star zero on your telephone keypad. Please note. This call is being recorded.

I would now like turn the conference overdose since William Kent Director of Investor Relations. Thank you you may begin.

Thank you David Good morning, everyone. Thanks for joining us today for the GP resources second quarter 2020 results conference call.

With me today, or Tim Conway, President and Chief Executive Officer.

No easy Chief Financial Officer, Treasurer, and Joe Redmond, Vice President of Energy Knockdowns already. Please go to our website Q U P. R. Yes, dotcom to attain copies of our earnings release, what do you think tables with our financial results along with a slide presentation with supporting materials.

In today's conference call, we use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA and earnings release, and if you could see filings and free cash flow.

These measures are reconciled to the most comparable GAAP measure in the earnings release NFI C.

In addition, we make numerous forward looking statements remind everyone that our actual results could differ materially from our forward looking statements for a variety of reasons many of which we honor control.

Sure for everyone, who are more robust forward looking statements Famer discussion of these risks facing our business and our earnings release NFCC fine with that let's turn the call over to Jeff.

Thanks will and good morning, and thank you for joining the call today I'll begin with an overview of our second quarter operational performance. We continue to focus on delivering value over volume and we are holding firm to this principle through these unprecedented times.

Following my update I will turn the call over to build to discuss our first quarter financial performance and to provide an update on our credit facility and improved liquidity position.

We continue to running one rig in the Permian and plan to pick up a second rig in September and resume fracking in November operated drilling and completion activity in the Wilson is complete for the year, we remain focused on lowering costs, while generating significant free cash flow to pay down debt.

Production for the second quarter was up slightly from the first quarter production began to decline in April after holding fracking in mid March and shutting in approximately 4000 barrels of oil per day.

Economic production.

The decline flatten during may as we made the decision to bring on the 11 completed wells, India issue 11, 25 to ensure good productivity from the wells and the meet our contractual obligations for oil sold into May.

About 80% of the shut in volumes were returned to production during June as price return to economic levels.

We will now be on a steady decline until late in the fourth quarter. When we start to turn on wells in the Permian completed during November and December. We also expect benign nonoperated wells being drilled on core acreage in south Antelope in the Williston them to be brought online during the fourth quarter.

We are resuming or production guidance and have provided quarterly information highlighted on slide nine of the IR deck to allow models to be updated.

Although 2020 capital is expected to be down 35% from our original guidance, we only expect a reduction of oil production of 12% given the strong performance of wells put online.

In County line during the first half of the year.

The issue O 312, which has brought online during the first quarter continues to perform strongly as shown on slide 10, and 11 of the IR deck.

Overall, the average 60 day cumulative oil production from the 25 wells in the deal shoe was 62000 barrels of oil and 120 day was 115000 barrels of oil normalize to 10000 feet.

As described during the last call. The tank is performing as expected with a deeper benches, producing a little more quickly while the shallower zones take time to do what are the tank before producing all the type curve rights 18 wells in the deeper benches, including the Wolfcamp, a sprayberry B and C achieved 60 day cumulative production of 76.

Sales and barrels of oil compared to an industry medium of 40000 barrels of oil normalized 10000 foot lateral lengths to 120 day production of 131000 barrels of oil compares favorably to an industry medium of 81000 barrels of oil the entire DS use producing approximately 40% higher.

And then the industry medium at 100, 120 days with the deeper zones outperforming by approximately 60% in the same timeframe.

We deferred turning on wells. The newest you 11 25 until May when the volume was required to meet our contracted sales obligations also pressure monitoring indicated that the pressure in the tank was declining and we did not want to take the risk of impacting the EU. Our of these wells as you can see from slide 12, and the IR deck via issues, but.

Forming as anticipated with wells building to full rates faster than expected.

The impact of stopping fracking out in front of the half the issue and the delay in the startup was very evident and how these wells produced as compared to the as you go through 12.

I have to issue could I will quickly and all wells were taken strength Sps as compared to the issue through 12 that experience free flow periods of up to a month.

We expect to meet our pre deal you or expectations and we'll take the opportunity to compare the adjacent to the issues for overall economic performance as we move forward.

Our preference remains to build the pressure wall and bring wells on sequentially.

This positive performance in each bench of both the issues as demonstrated on slide 13 of the IR deck as a strong affirmation of the modifications that we've made to our limited entry Frac design reduced cluster spacing, along with fewer and smaller appropriate preparation as a resulted in a higher perforation friction and most importantly improve.

Cluster efficiency.

Our drilling completion team also continues to improve on both cost and efficiency as you can see from slide 14 of the IR deck, well drilled and completed in the Permian during the first half the year were delivered to the costs of less than $450 per foot and frac at an average pace exceeding 3800 lateral feet per day, which remains peer.

Leading.

In the Williston them, we have completed two of the six disco wells to retain the lease and the successfully re frac five wells as shown on slide 15 of the IR deck.

Overall Wilson production is expected to remain steady through the third quarter, an increase in the fourth quarter with the completion of nine non operated wells adjacent to the core of our south Antelope acreage.

Let me with them for the quarter, primarily as a result of significant reduction to workover activity and the deferral of all discretionary spend in the Permian Ela, we was close to $3 per via Weve for the first half the year and we expect the finished the full year at approximately $3. A 50 cents per via we primarily due to increase in work active tivity in the second.

Half of the year.

DNA continues to come down as demonstrated on slide 16 of the IR deck, and we spent 55% less in the first half of 2020 as compared to the same timeframe and 29 team.

I will now discuss our current outlook for 2021 is demonstrated on slide 17 of our IR deck.

Although we plan to complete the remaining four wells on the disco pad in the Wilson, Our 2021 development program will be primarily focused in the county line areas the Permian.

We expect this program to deliver modest production growth and positive free cash flow at a double 50 odd price of approximately $38 per barrel. It is important to note that even with a significant reduction in capital deployed in the Permian since 2018, we continue to deliver month modest volume growth.

This underscores the exceptional cost efficiencies at our operational teams delivered over the past two years the program could be adjusted as we move through the second half of 2021, sorry, 2020, but we thought it was critical to show an early look.

To help the market understand the strength of our program moving into 2021.

I will now move to slide 18 of the IR deck, where we provide a loan side to our expected economic outcomes from our 2021 development program at various price scenarios as I. Just mentioned there are 2021 development program will be focused in the county line area of the Permian, where we anticipate delivering greater than 32%.

Right of return for deal she has drilled and completed at a $40 oil price. We believe that these expected returns justify initiating fracking activity during the fourth fourth quarter of this year.

In summary, we have adjusted our development pace continued to lower cost and expect to deliver more than $150 million of free cash flow at strip prices in 2020, we've modified our 2021 development program to deliver strong individual low returns and positive free cash flow is approximately $38. So.

Our recent development activity and county line demonstrates our ability to be a low cost developer core acreage, while delivering outstanding well results. We believe we are well positioned to move through this unprecedented reduction in demand and we look forward to things gradually returning normally I'll now turn the call over to bill to discuss.

Second quarter financial results, along with information on our liquidity position and the restructuring of our credit facility or do you Bill.

Thank you Jim and good morning, everyone I will spend my time. This morning, providing you with some details about our second quarter results, including our improved liquidity position and updating you on our 2020 guidance before opening the call up for Q anyway.

But before I do that I wanted to provide some color around our recent credit facility Amendment.

In June we announced an extensive amendment to our credit agreement. We believe that the amendment provides the financial flexibility we need to execute our business plan for the next several years. Despite the current volatile commodity price environment.

One of the most important outcomes of the amendment was that our liquidity position increased by more than $500 million, leaving us with more than $740 million of liquidity at the end of the second quarter.

The aggregate commitments reduced from 1.25 billion to 850 million and the credit agreement now requires that the company's materials subsidiaries guarantee the obligations under the credit facility.

The facility remains unsecured is not or is there based loan and still matures in September of 2022.

The agreement still includes three financial covenants. However, those covenants are now calculated using only the borrowings under the credit facility rather than the company's total outstanding debt.

The new covenants are the main drivers behind our liquidity, increasing by the more than $500 million.

Two of the three financial covenants were modified the leverage NPV nine ratios, while the third covenant debt to cap ratio was replaced with a minimum liquidity covenant.

In addition to the modified financial covenants. The amendment added a couple of provisions that we believe will be useful in our liability management strategy going forward first in addition to our ability to use any cash on hand free cash flow generation and proceeds from divestitures to retire outstanding senior notes. The senior note redemption basket provision allows us to.

Our up to $500 million under the credit facility to repurchase outstanding notes, regardless of the amount of notes purchase using the sources of funds mentioned earlier.

Additionally, the amendment provides us the ability to issue up to $500 million of subordinated subsidiary guaranteed debt.

This indebtedness would be subordinate to the credit facility, but the junior guarantees that provides structural senior already over our existing unsecured senior notes.

Combined the two new baskets provide the company with a $1 billion a flexibility to help us manage our senior note maturities over the next couple of years.

While there were other modifications to the credit credit agreement. This should give you a good feel for some of the key items addressed overall, we think the amendment was an extremely positive outcome for the company and couldn't be more pleased with the result.

Turning now to our second quarter results during an extremely challenging time for our industry, we were still able to deliver a strong financial results for the quarter.

During the second quarter, we generated net cash provided by operating activities of $72.5 million.

We reported free cash flow of $95.3 million, a $127 million improvement compared with the outspend in the second quarter of 2019.

Improvement was primarily due to decreases in accrued and capital expenditures and increased unrealized derivative gains and and a decrease in elouise, which were partially offset by decrease in oil and NGL sales.

We reported a net loss of $184 million in the second quarter compared to net income of 367 in the first quarter 2020.

The $551 million decrease was primarily driven by a $626 million increased an unrealized derivative losses, partially offset by $78 million increase unrealized derivative gains both due to the significant volatility of commodity prices during the quarter.

In the second quarter 20, we generated $157.3 million of adjusted EBITDA, a decrease from the 173.9 million generated in the first quarter. The decrease was driven by lower average field level prices, which were partially offset by modest increase in both oil and equivalent production in the quarter.

Combined total Lowi and transportation expense was down nearly $13 million two combined $41 million for the quarter, while DNA increased by more than $10 million quarter over quarter, primarily due to an increase in the mark to market adjustments of our deferred compensation plan.

On the derivative front, we continued to enter into commodity derivative contracts during the quarter and we currently hold contracts totaling 8.6 million barrels of oil at $57 in 29 cents per barrel for the remaining six months of 2020, and 8.6 million barrels at $43.47 per barrel for 2021. Please see the 10-Q four.

Additional details on our derivative portfolio.

Turning now to our balance sheet at the ended the second quarter total assets were approximately $5.5 billion and total shareholders equity was approximately $2.8 billion total gross debt was was approximately 1.9 billion. We had no borrowings outstanding under our credit facility $11 million of letters of credit outstanding and $3 million the cash on hand.

During the second quarter, we repurchased approximately 57 million in principle amount of our 21 senior notes.

During the first half of the year, we have repurchased 107 million of the 21 notes 35 million of the 22 notes and 13 million of the 23 nodes.

Finally at June Thirtyth June Thirtyth, we had a current tax receivable on our balance sheet, which is primarily comprised of our $165 million AMTI credit refunds.

The refund claim was filed with the IRS in the second quarter and while we remain confident the full refund will be received within next 12 months, possibly even in 2020, we are unable to predict how quickly it will be received from the IRS.

On the liquidity front, we exited the second quarter with over $743 million in total liquidity made up a 3 million of cash and approximately 740 million of borrowing capacity under the revolver.

We can you can find more details of our liquidity on slide 19 of the slide deck.

We continue to believe that the generation of free cash flow cash on hand, the anticipated AMTI credit refunds and to the extent necessary borrowings under our credit facility will be sufficient to fund our operations capital expenditures interest expense and the repayment of our 21 notes over the next 12 months.

Finally, moving on to guidance as provided in Yesterdays release, we have updated the Companys 2020 guidance to reflect our current expectations.

Excluding acquisition and divestiture activity the midpoint of our 2020 capital investment guidance is now $360 million, which includes capital for midstream and infrastructure, a 30% decrease from the midpoint of our original guidance.

The Permian basin will be allocated approximately 75% of this investment.

We currently plan to spend approximately 145 million over the balance of the year with nearly 95 million expected to be spent in the fourth quarter, assuming we continue to see the necessary price levels.

The midpoint of our 2020 oil volume guidance is now 19.25 million barrels a 12% decrease in the midpoint of our original guidance.

The midpoint of our guidance for lease operating expense is $5 in 15 cents per Boe, a while the midpoint for adjusted transportation and processing costs is $3 and 75 per cent per Boe.

This results in 2020 total lifting cost guidance of $8 in 90 cents per BOE, we at the midpoint.

Finally, our 2020 guidance the Gionee expense is $87.5 million at the midpoint of which approximately 12 million share based in deferred compensation expense, which can fluctuate with cubic feedstock and the general stock market changes.

Please see our earnings release for a few additional details on a 2020 guidance.

With that I would now like to open the call up for questions.

At this time, we will be conducting a question answer session. If you like to ask questions. Please press star one on your telephone keypad.

Information total indicate your line is in a question Keith.

Let me start to feel like to move your question from the Q.

For participants using speaker equipment, it may be necessary to pick opinion simple questions. Keith one moment, please as we pull for questions.

Our first question comes on line of Neal Dingmann.

Central's. Please proceed with your question.

Good morning, all great free cash flow I guess to my first question is just.

You guided back a little bit on the.

Production for the year, but again it seems like your full year free cash flow continues to be strong restrike could you just maybe give your.

Strategy or opinion of is that sort of the plan into 21 is to really free cash flow first as long as you can kind of keep production stable or get I'm, just trying to get at how you're sort of viewing a balance between pre cash funding and sort of production growth.

Now that Neil that's exactly right. So our primary focus was on free cash flow generation I mentioned, the approximately $38 a barrels. So the entire team is focused on getting our our DNA to our operating costs are drilling completion costs down to where.

We can operate.

At a lower and lower dollar per barrel of development costs in operating costs to where.

We can kind of whether this so bill mentioned, we've put on hedges now kind of averaging in the 43 plus dollar range. So between the 38 and 43, we create period some headroom.

On the.

For some cash flow, we want to make sure Thats why we put the additional slot in there that the investments we put forward our economic as Standalone.

So we're not going to just produce volume for volume study, but I think it is important to keep our volume steady.

Slight growth I think is a good positive thing and we remain positioned for as price hopefully recovers overtime.

Then we can move quickly and I think you can see from our first quarter results.

How many lawn and we're going to be there for the next couple of years, we can move really fast with our fracking of pace.

We can move fast we're going to have 55.

Ducs ready to go by this time, we start tracking in the fourth quarter and the additional four wells up in the Woolston. So we've got we're confident of building volume into the first quarter next year and then we'll watch it and we will see kind of where it is but the idea is generate free cash flow.

Price gives us headroom to do more we might do a little bit more but we're willing to pull back just like we show this year.

And it kind of what you said leasing that my second question just just on on the Bakken.

Continue to it appears that you still have some of the best acreage there I know you've kind of because of spending reasons dial back completions, a little bit, but I'm just wondering.

Plans later, this year or I guess, you'd kind of the outlined that but I'd say you plan to 21 would you consider it drillco, which consider.

Just wondering what it what sort of on the table because again as I've mentioned I still think.

Bakken acreage is quite economical and I think you'll have some among the best So just kind of wondering how you have you sort of view that longer term.

Yes, I mean, we like to lock in a lot is cash flow generating.

One of the things we have as the is the is the re frac.

Inventory about 100 wells, we put on five before we pull back those are really competitive there they are competitive with the the Permian drilling both.

We can those are very fungible, we can turn long term offered quickly and we've decided to generate free cash flow you asked about to go ahead and slow that down so we're going to be we're going to be keeping an eye on that.

We would prefer to drill the wells the next wells up or are.

The remaining wells in the disco pad. The first two wells we've turned on the alternate talked a lot more balance we have more runway in the in the next quarter, but for two wells are really really encouraging and what we've been I'll do so.

Right now we're not considering girl codes that we stayed open to all options right.

Our long term primary focus for development remains in the Permian.

We like the Bakken a lot the folks are doing great job developing it up there and operating and and as we can move pretty quickly on that is little slower to get into drilled wells that we have all the all the permits we need to drill the next I think 10 wells on the discussed so I think where we'd like it. It's a it's pretty funded losses for us and remain hope.

And really to what the best way to extract maximum value out of the Boston.

Great details thanks much.

Once again, if you like to ask questions. Please press star one on your telephone keypad. Once again, if you like to ask questions. Please press star one on your telephone keypad, one more seasonally pull for questions.

Our next question comes the line of key dealt with Cowen. Please proceed with your question.

Hey, Good morning, guys I guess was just curious Tim on.

Obviously pretty pretty attractive DNC cost per foot in the Permian.

And on a go forward basis, let's say.

Oil prices were to increase in perhaps you lose some pricing.

From your from your service providers, what what do you think are no longer term bases that dollar per foot number could end up looking like.

Again, if you really get back some pricing on a potential rebound scenario.

Yes, I think that's a good question and they were working with all of our vendors to make sure we try and lock in a little bit longer term rate. So we don't just rely on the daily rate.

Obviously as things get better all all of the suppliers are going to come back for some more.

I think we've convinced ourselves we can kind of stable in that $500 foot drill and complete and if you asked me that question just two years ago, and I'd say, we get down to 750. The now we're confident that 500 below the first part of this year was incredible we're still doing things creatively on our on our drilling we.

Just recently.

Drill the well the PD.

In nine days.

Into the into the Dean Horizon in County line. So I don't think would repeat that every time, but that takes us and 12 nine I mean, if you could get that consistently you stay very confident as low cost. So we've not set of bottom we're going to protect ourselves about.

On creep back up as a service costs go up a little bit, but we're pretty small company with a few vendors and they're working with us very well.

Thanks, and that's helpful and I'm just a follow up I guess as we're looking to the rest of 20 to 21. The guidance that you guys have laid out very detailed definitely appreciate that but would you say guided currently.

Embed that.

Productivity improvements, you're seeing a county line and also the capital side of the guidance currently bake in that 400.

$3 per foot in terms of Idmc costs.

No. We haven't you know we since we we got down to one rig.

We haven't we haven't baked all lending going forward, we have a little bit higher.

Cost in the budget, we think Thats fair and then will absorb some of the rebound as prices come back on service cost increase.

We have not planned in risk to 2020 and into 2021 that local cost.

But again, we are costs are down there their competitive.

And we're aiming at a pretty competitive cost in a forecast but.

Hopefully more to come.

Great I talk us.

Okay. Thanks.

Yes, or no further questions left in the queue I would like to turn the floor back over to Mr., Tim Cook for any closing remarks.

All right. Thanks for joining the call that I think there are lot of earnings calls this morning that we're competing with.

Glad that you know if you guys get online and ask some questions. We're super pleased with.

What we were able to do during a very very difficult quarter. The only thing I'm going to say thanks for the organization.

We're working primarily remotely the organization stepped up we've continued to focus on the balance sheet continued to take cost down and to continue to deliver and our safety performance and environmental performance and health performance has remained outstanding through all this period of time, so really big Thanks, The organization and thanks again for joining the call.

Okay.

This concludes today's teleconference. You may now disconnect. Your lines at this time. Thank you for your participation and have a wonderful day [noise].

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