Stocks breaking to new annual highs
S&P 500 oversold value screener
Relative strength momentum leaders
Upcoming earnings dates & reports
Filter and sort all 500 stocks
Continuous multi-factor scoring & catalyst forensics
Today's biggest gainers and losers
Operator: Greetings, and welcome to the QEP Resources Second Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] Please note this call is being recorded. I would now like to turn the conference over to your host, Mr. William Kent, Director of Investor Relations. Thank you. You may begin.
William Kent: Thank you, Devin, and good morning, everyone. Thank you for joining us today for the QEP Resources second quarter 2020 results conference call. With me today are Tim Cutt, President and Chief Executive Officer; Bill Buese, Chief Financial Officer and Treasurer; and Joe Redman, Vice President of Energy. If you’ve not done so already, please go to our website, qepres.com, to obtain copies of our earnings release, which contains tables with our financial results, along with a slide presentation with supporting materials. In today’s conference call, we will use certain non-GAAP measures, including EBITDA, which is referred to as adjusted EBITDA, in our earnings release and SEC filings and free cash flow. These measures are reconciled to the most comparable GAAP measure in the earnings release and SEC filings. In addition, we’ll be making numerous forward-looking statements. We remind everyone that our actual results could differ materially from our forward-looking statements for a variety of reasons, many of which are beyond our control. We refer everyone to our more robust forward-looking statement disclaimer and discussion of these risks facing our business in our earnings release and SEC filings. With that, I’d like to turn the call over to Tim.
Timothy Cutt: 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 Bill to discuss our first quarter financial performance and to provide an update on our credit facility and improved liquidity position. We continue to run 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 Williston 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 4,000 barrels of oil per day of uneconomic production. The decline flattened during May, as we made the decision to bring on the 11 completed wells in DSU of 11.25 to ensure good productivity from the wells and to meet our contractual obligations for oil sold into May. About 80% of the shut-in volumes were returned to production during June, as price returned to economic levels. We will be – now will be in 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 the nine non-operated wells being drilled on core acreage in South Antelope in the Williston to be brought online during the fourth quarter. We are resuming our production guidance and have provided quarterly information highlighted on Slide 9 of the IR deck to allow models to be updated. Although in 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. DSU 0312, which was brought online during the first quarter, continues to perform strongly, as shown on Slides 10 and 11 of the IR deck. Overall, the average 60-day cumulative oil production from the 25 wells in the DSU was 62,000 barrels of oil and 120-day was 115,000 barrels of oil normalized to 10,000 feet. As described during the last call, the tank is performing as expected, with a deeper benches producing oil more quickly, while the shallower zones take time to dewater the tank before producing oil at tight curve rates. 18 wells in the deeper benches, including the Wolfcamp B, Sprayberry B and C achieved 60-day cumulative production of 76,000 barrels of oil compared to an industry medium of 40,000 barrels of oil normalized 10,000 foot lateral length. The 120-day production of 131,000 barrels of oil compares favorably to an industry medium of 81,000 barrels of oil. The entire DSU is producing approximately 40% higher than the industry medium at 120 days, with the deeper zones outperforming by approximately 60% in the same timeframe. We deferred turning on wells in DSU of 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 EUR of these wells. As you can see from Slide 12 in the IR deck, the DSU is performing as anticipated with wells building to full rates faster than expected. The impact of stopping fracking out in front of the half DSU and the delay in the startup was very evident on how these wells produced as compared to DSU 0312. The half DSU cut oil [ph] quickly and all wells were taken straight ESPs, as compared to DSU 0312 that experienced free flow periods of up to a month. We expect to meet our [indiscernible] EUR expectations and we’ll take the opportunity to compare the adjacent DSUs for overall economic performance as we move forward. Our preference remains to build a pressure wall and bring wells on sequentially. This positive performance in each bench of both DSUs was demonstrated on Slide 13 of the IR deck is a strong affirmation of the modifications that we’ve made to our limited entry frac design; reduced cluster spacing, along with fewer and smaller perforations, has resulted in a higher perforation friction, and most importantly, improved cluster efficiency. Our drilling completion team also continues to improve on both costs and efficiency. As you can see from Slide 14 of the IR deck, wells drilled and completed in the Permian during the first-half the year were delivered at a cost of less than $450 per foot and fracked at an average pace exceeding 3,800 lateral feet per day, which remains peer leading. In the Williston, we have completed two of the six Disco wells to retain the lease and have successfully refracked five wells, as shown on Slide 15 of the IR deck. Overall, Williston production is expected to remain steady through the third quarter and increase in the fourth quarter with the completion of nine non-operated wells adjacent to the core of our South Antelope acreage. LOE was down for the quarter, primarily as a result of significant reduction to workover activity and the deferral of all discretionary spend. In the Permian, LOE was close to $3 per Boe for the first-half of the year, and we expect to finish the full-year at approximately $3.50 per Boe, primarily due to increase in work activity in the second-half of the year. G&A 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 in 2019. I will now discuss our current outlook for 2021, as 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 area of the Permian. We expect this program to deliver modest production growth and positive free cash flow at a WTI 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 modest volume growth. This underscores the exceptional cost efficiencies that our operational team has delivered over the past two years. The program could be adjusted as we moved 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 line of sight to our expected economic outcomes from our 2021 development program at various price scenarios. As I just mentioned, our 2021 development program will be focused in the County Line area of the Permian, where we anticipate delivering greater than 32% rate of return for DSUs drilled and completed at a $40 oil price. We believe that these expected returns justify initiating fracking activity during the fourth quarter of this year. In summary, we have adjusted our development pace, continue to lower costs and expect to deliver more than $150 million of free cash flow at strip prices in 2020. We have modified our 2021 development program to deliver strong individual low returns and positive free cash flow of approximately $38 WTI. Our recent development activity in County Line demonstrates our ability to be a low-cost developer of 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 to normal. I’ll now turn the call over to Bill to discuss the second quarter financial results, along with information on our liquidity position and the restructuring of our credit facility. Over to your, Bill.
William Buese: Thank you, Tim, 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&A. 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 material subsidiaries guarantee the obligations under the credit facility. The facility remains unsecured is not a reserve base 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 two [ph] covenants are the main drivers behind our liquidity, increasing by more than $500 million. Two of the three financial covenants were modified, the leverage and Pv-9 ratios; while the third covenant, the 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 borrow up to $500 million under the credit facility to repurchase outstanding notes regardless of the amount of notes purchased 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 subordinated to the credit facility, but the junior guarantees would provide structural seniority over our existing unsecured senior notes. Combined, the two new baskets provide the company with $1 billion of flexibility to help us manage our senior note maturities over the next couple of years. While there were other modifications to the 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 results. Turning now to our second quarter results. During an extremely challenging time for our industry, we were still able to deliver strong financial results for the quarter. During the second quarter, we generated net cash provided by operating activities of $72.5 million and we reported free cash flow of $95.3 million, a $127 million improvement compared with the outspend in the second quarter of 2019. The improvement was primarily due to decreases in accrued capital expenditures, an increase in realized derivative gains and a decrease in LOE, which were partially offset by a decrease in oil and NGL sales. We reported a net loss of $184 million in the second quarter, compared to net income of $367 million in the first quarter of 2020. The $551 million decrease was primarily driven by a $626 million increase in unrealized derivative losses, partially offset by a $78 million increase in realized derivative gains, both due to the significant volatility of commodity prices during the quarter. In the second quarter 2020, 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 a modest increase into oil and equivalent production in the quarter. Combined, total LOE and transportation expense was down nearly $13 million to a combined $41 million for the quarter, while G&A 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 continue to enter into commodity derivative contracts during the quarter and we currently hold contracts totaling 8.6 million barrels of oil at $57.29 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 for additional details on our derivative portfolio. Turning now to our balance sheet. At the end of the second quarter, total assets were approximately $5.5 billion and total shareholders’ equity was approximately $2.8 billion. Total gross debt was approximately $1.9 billion. We had no borrowings outstanding under our credit facility, $11 million of letters of credit outstanding and $3 million of cash on hand. During the second quarter, we repurchased approximately $57 million in principal amount of our 21 senior notes. And 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 notes. Finally, at June 30, we had a current tax receivable on our balance sheet, which is primarily comprised of our $165 million AMT credit refund. The refund claim was filed with the IRS in the second quarter. And while we remain confident, the full refund will be received within the 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 of total liquidity, made up of $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 AMT 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 yesterday’s release, we have updated the company’s 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 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 from the midpoint of our original guidance. The midpoint of our guidance for lease operating expense is $5.15 per Boe, while the midpoint for Adjusted Transportation and Processing Costs is $3.75 per Boe. This results in 2020 total lifting costs guidance of $8.90 per Boe at the midpoint. Finally, our 2020 guidance for G&A expense is $87.5 million at the midpoint, of which approximately $12 million is share-based and deferred compensation expense, which can fluctuate with QEP stock and the general stock market changes. Please see our earnings release for a few additional details on our 2020 guidance. With that, I would now like to open the call up for questions.
Operator: At this time, we will be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Neil Dingman with SunTrust. Please proceed with your question.
Neil Dingman: 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 free cash flow continues to be strong and strong. Could you just maybe give your strategy or opinion of – is that sort of the plan into 2021 is to really free cash flow first, as long as you can kind of keep production stable? Or again, I’m just kind of get that how you’re sort of viewing the balance between free cash flow and sort of production growth?
Timothy Cutt: That’s – Neil, that’s exactly right. So our primary focus is on free cash flow generation, I mentioned the approximately $38 a barrel. So the entire team is focused on getting our G&A, our operating costs, our drilling completion costs down to where we can operate at a lower and lower dollar per barrel of development costs and operating costs to where we can kind of weather this. So, Bill mentioned, we put on hedges now, kind of averaging in the $43-plus range. So between the $38 and $43, we’ve created some headroom on the – for some cash flow. We want to make sure, that’s why we put the additional slide in there that the investments we put forward are economic and standalone. So we’re not going to just produce volume for volume sake. But I think it is important to keep our volumes steady. A slight growth, I think, is a good positive thing. And we remain position for as price hopefully recovers over time, though, we can move quickly. And I think you can see from our first quarter results in County Line, 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 ducks ready to go, by the time we start fracking in the fourth quarter and the additional four wells up in the Williston. So we’ve got – we’re confident of building volume into the first quarter next year and then we’ll watch it and we’ll see kind of where it is. But the idea is, generate free cash flow. If price gives us headroom to do more, we might do a little bit more. But we’re willing to pull back just like we showed this year.
Neil Dingman: And, Tim, kind of what you said leads me to my second question just on the Bakken, continue to appear is that you still have some of the best acreage there. I know you’ve kind of – because of sort of spending reasons dial back completions a little bit. But I’m just wondering plans later this year, or I guess you’ve kind of outlined that. But I’d say, you would plan to 2021. Would you consider a DrillCo [ph]? Would you consider – I’m just wondering what sort of on the table? Because again, as I mentioned, I still think Bakken acreage is quite economical and I think you all have some among the best. I’m just kind of wondering how you – how do you sort of view that longer-term?
Timothy Cutt: Yes. I mean, we like the Bakken a lot, which is cash flow generating. One of the things we have is the refrac inventory of about 100 wells. We put on five before we pulled back. Those are really good competitive. They’re competitive with the Permian drilling. But we can – those are very fungible. We can turn them on, turn them off very quickly and we’ve decided to generate the free cash flow. You asked about to go ahead and slow that down. So we’re going to be keeping an eye on that. We would prefer to drill the wells, the next wells up or the remaining wells in the Disco pad, the first two wells we’ve turned on. We’ll sort of talk a lot more about once we have more runway in the next quarter. But the two wells are really, really encouraging and what we’ve been able to do. So, right now, we’re not considering DrillCo, but we stay open to all options, right? Our long-term primary focus for development remains in the Permian. We like Bakken a lot. The folks are doing a great job developing it up there and operating. And it’s – we can move pretty quickly on that. It’s a little slower to get into drilled wells, but we have all the permits we need to drill the next, I think, 10 wells on the Disco pad. So I think, we’re – we like it. It’s a pretty fungible asset for us. And we remain open early to what’s the best way to extract the maximum value out of the Bakken.
Neil Dingman: Great details. Thanks so much.
Operator: [Operator Instructions] Our next question comes from the line of Gabe Daoud with Cowen. Please proceed with your question.
Gabe Daoud: Hey, good morning, guys. I guess, I was just curious, Tim, on, obviously, pretty attractive D&C costs per foot in the Permian. On a go-forward basis, let’s say, if oil prices were to increase and perhaps you lose some pricing from your service providers, what do you think on a longer-term basis, that dollar per foot number could end up looking like? Again, if you were to give back some pricing on a potential rebound scenario?
Timothy Cutt: Yes. I think that’s a good question. I mean, we’re 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, if things get better, all of the spires are going to come back for some more. But I think we’ve convinced ourselves. We can kind of stay low on that $500 a foot drill and complete. And if you would ask me that question, just two years ago, I’d say, we get down to $750. But now, we’re confident that $500 below the first part of this year was incredible. We’re still doing things creatively on our drilling. We just recently drilled well to PD in nine days into the end of the deep [ph] horizon and County Line. So, I don’t think we’re going to repeat that every time, but that’s takes from 12 to nine. I mean, if you could get that consistently, you stay very confident in that low-cost. So, we’ve not set a bottom. We’re going to protect ourselves about the – on Creek backup as the service costs go up a little bit. But we’re a pretty small company with a few vendors and they’re working with us very well, so.
Gabe Daoud: Thanks. And that’s helpful. And then just a follow-up, I guess, as we’re looking to the rest of 2020 and into 2021, the guidance that you guys have laid out very detailed. Definitely I appreciate that. But would you say guidance currently embed the productivity improvements you’re seeing at County Line and also the capital side of the guidance currently bake in at $403 per foot in terms of D&C costs?
Timothy Cutt: No, we have – we – since we got down to one rig, we haven’t baked all that going forward. We have a little bit of higher cost than the budget. We think that’s fair and it will absorb some of the rebound if prices come back up, service costs increase. So we have not planned in the rest of 2020 and into 2021 that low of a cost. But again, we’ve – our costs are down there. They’re competitive. And we’re aiming at a pretty competitive cost in that forecast. But hopefully more to come.
Gabe Daoud: Great. Thanks a lot, guys.
Timothy Cutt: Okay. Thanks, Gabe.
Operator: Since there are no further questions up in the queue, I would like to turn the floor back over to Mr. Tim Cutt for any closing remarks.
Timothy Cutt: All right. Well, thanks for joining the call today. I think there are a lot of earnings calls this morning that we’re competing with. Glad that, a few guys got online and asking 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 is thanks to the organization. We’re working primarily remotely. The organization stepped up. We’ve continued to focus on the balance sheet, continue to take costs down and we continue to deliver in our safety performance and environmental performance and health performances remained outstanding through all those period of time. So really, big thanks to the organization and thanks again for joining the call.
Operator: This concludes today’s teleconference. You may now disconnect your lines at this time. Thank you for your participation, and have a wonderful day.
No analyst estimates available
