Ovintiv Inc. (NYSE:OVV) Q4 2022 Earnings Call Transcript

Ovintiv Inc. (NYSE:OVV) Q4 2022 Earnings Call Transcript February 28, 2023

Operator: Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv’s 2022 Fourth Quarter and Year-End Results Conference Call. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Jason Verhaest : Thanks, Michelle, and welcome, everyone, to our fourth quarter and year-end ’22 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of their slides and in the disclosure documents filed on SEDAR and EDGAR. Following prepared remarks, we’ll be available to take your questions. Please limit your time to 1 question and 1 follow-up. I will now turn the call over to our President and CEO, Brendan McCracken.

Brendan McCracken : Good morning. Thank you for joining us. 2022 as a milestone year for Ovintiv. Our team generated a record free cash flow of $2.3 billion and net earnings of $3.6 billion. This achievement was underpinned by our leading capital efficiency. We returned nearly $1 billion to our shareholders through our base dividend and share buybacks, and we reduced our long-term debt by $1.2 billion. We also expanded our future runway with the addition of approximately 450 new premium return locations. These additions were mostly in the Permian, and the acreage offsets our existing positions in Martin, Midland, Upton and Howard Counties. These inventory additions mean that we added more than twice the number of wells that we drilled last year.

Our team successfully delivered 10% year-over-year capital efficiencies, which acted to offset significant inflationary pressures. Our team drilled and completed wells faster than ever before and our cube development approach continued to deliver consistent well results while maximizing the value and returns from every acre we developed. The combination of these efforts delivered total annual production of 510,000 BOEs per day. While holding the line on our capital guidance of $1.8 billion. We also made significant gains elsewhere in our business. We were recently included in the Bloomberg Gender Equality Index. In addition, we made significant progress towards our GHG emissions reduction target. We’ve now reduced emissions intensity by more than 30%, and we are well on our way to meeting our goal of a 50% reduction.

In short, in 2022, we delivered tremendous profitability, increased direct returns to our shareholders, bolstered our financial strength, extended our future inventory runway and continued our strong social and emissions performance. These results demonstrate that our strategy is working and our execution is translating into increased value for our shareholders. We had a record-breaking year, and I’m confident our team will continue to deliver leading capital efficiency and durable returns for our shareholders in 2023 and beyond. Our fourth quarter performance meant we ended the year with great momentum, with net earnings of $1.3 billion, adjusted EBITDA of $918 million, free cash flow of $537 million and cash flow per share of $3.55, modestly ahead of consensus estimates.

Our fourth quarter production came in at 524,000 BOEs per day. Strong well performance across our portfolio drove us to the top end of guidance on oil, gas and NGL. This was despite extreme winter weather across North Dakota, Oklahoma and Western Canada. Kudos to our team, where the weatherization efforts made by our experienced field staff kept our volumes flowing safely and reliably with minimal interruption. We also delivered approximately $250 million to our shareholders through share buybacks and base dividends. And this will increase to $300 million in the first quarter as a result of the strong free cash flow we generated in Q4. We believe that long-term value creation in the E&P space will come from companies that can demonstrate durability in both their return on invested capital and the return of cash to shareholders, generating durable returns requires a deep inventory of premium return drilling locations, disciplined capital allocation and highly efficient conversion of resource to cash flow.

We check all 3 boxes. Our capital efficiency is underpinned by our multi-basin multiproduct portfolio. Our uniquely balanced portfolio provides operational and commodity diversification, cross-basin learnings and premium inventory depth. Our ability to shift capital to maximize corporate returns is a competitive advantage. We did this in 2022 in response to the Montney permitting slowdown, which is now behind us, and we are making use of this option again in 2023 in response to weaker short-term North American natural gas fundamentals. In our business, access to premium resource is another essential component to generating durable returns. We are continuously evaluating opportunities to extend our runway through both organic appraisal and assessment efforts as well as through bolt-ons.

Over the course of the year, we made significant additions to our premium inventory across our asset base. Through organic appraisal and more than 90 transactions, we cost effectively added approximately 450 inventory locations. The biggest focus of this program was in the Permian and where we added about 8,000 net acres to our core positions in Midland, Martin, Upton and Howard. The next biggest additions were condensate in oil locations in the Montney. All told, we replaced 2x the number of wells we drilled last year. We’re committed to staying disciplined and opportunistic in our bolt-on efforts, and only transacting when we can generate strong full cycle return at mid-cycle pricing. Our inventory renewal efforts make our business more sustainable and help us extend our premium inventory runway across the portfolio.

It’s worth noting that these inventory adds did not result in incremental proved reserves, both because of the timing of the ads late in the year and the SEC booking rules. It’s also worth pointing out that our U.S. oil reserves were flat year-over-year after accounting for the sale of our high-cost mature waterflood in the Uinta Basin in the third quarter. I’ll now turn the call over to Corey to discuss our 2023 outlook.

Corey Code : Thanks, Brendan. Our 2023 capital plan provides continued strong shareholder returns while keeping our production volumes flat year-over-year. Greg will speak more to the details of the plan later in the call. But at a high level, we intend to execute a resilient, load leveled program, which we’ve optimized to generate significant free cash flow, maximize capital efficiency and maintain balance sheet strength. We are leveraging our multi-basin multiproduct portfolio and focusing 100% of our investment in oil and condensate ridge areas. But as always, we have the optionality to shift capital to other parts of our portfolio. If economic factors dictate over the course of the year. With 25% of our 2023 oil and gas volumes covered by WTI and NYMEX benchmark contracts, our greatly reduced hedge position allows us to participate in commodity price upside up to $110 a barrel for oil and $8 per MMBtu for natural gas.

This is a huge tailwind for us compared to last year. We are well underway today on our first quarter buyback program of $238 million. Collectively, we will return approximately $300 million to shareholders in the first quarter across our base dividend and share repurchases. Our first quarter cash return yield of approximately 11% is very competitive in today’s market across both industry peers and the broader economy. We remain committed to delivering substantial returns to our shareholders. Since implementing our capital allocation framework in the fall of 2021, we’ve returned more than $1.4 billion to shareholders. We see this momentum continuing in 2023 and beyond as we continue delivering a highly efficient development program and removing legacy costs from the business.

We also reduced long-term debt by $1.2 billion, and as a result, our leverage at year-end was 0.8x. As expected, we continue to see our U.S. business being cash taxable starting in 2024, as we expect to be subject to the corporate alternative minimum tax at current prices. Our cash tax included in our guidance relates to our Canadian business. It is likely to attract cash tax this year based on stronger-than-expected performance in 2022 that consume more tax pools than initially expected. We ended the year with a $381 million of NOLs there. Assuming a $75 WTI price and a $3 NYMEX gas price, we would see $200 million to $250 million of cash tax in Canada. This cash tax will not be payable until early 2024 and will be working capital rather than actual cash used in 2023.

I’ll now turn the call over to Greg to talk more about our 2023 plan and provide some operational highlights.

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Greg Givens : Thanks, Corey. The development program we implemented last year has strategically positioned Ovintiv for success in 2023. Capital efficiency remains a primary focus for our teams as we work to efficiently convert our inventory into cash flow and generate durable returns for our shareholders. Our 2023 10-rig program delivers annual total production volumes of 513,000 BOE per day, split evenly between liquids and natural gas. This production profile is flat versus 2022 despite selling some noncore assets last year. As Corey mentioned, given the weak outlook for natural gas and NGL prices this year, we have chosen to allocate our capital to the oil condensate rich parts of our portfolio as is evidenced by the lower activity in the Anadarko Basin.

As we expected, our first quarter production is set to be the low point for the year, at about 500,000 BOE per day. This profile is driven by a couple of factors. First, and as we outlined in our third quarter call, we intentionally built a drill but uncompleted or DUC well inventory in the fourth quarter. We are limiting our usage of spot crews and taking a methodical approach to bringing these wells online through the first half of 2023. Second, the wells that were brought online at the end of last year were weighted towards the front end of the fourth quarter. This affected production in January and February as we ramped activity back to levels normalized with the rest of 2023. Our Q1 guide also includes the impact of known weather events.

We have been thoughtful in our approach to increasingly load level our development programs. And in 2023, we expect to see less variation in turn-in-line cadence setting us up for a more ratable production profile in the second half of the year and going forward. Permian well performance continues to be topical. So I’d like to take a moment to discuss what we’ve been seeing in the play. We’ve been active in the Permian for over 8 years and have studied the basin extensively. We’ve drilled across our entire acreage footprint to delineate the play, and we’ve entered into numerous data trades with our peers. We led the industry to cube development, which maximizes both recovery and returns. Our approach to stacking and spacing has been very consistent through time.

We take a customized concurrent multi-zone development approach in each of our tubes to optimize resource recovery and deliver the highest NPV for every acre of land we develop. The chart on the right shows a tight dispersion of full field development results. Our Permian program, like all development programs, has a statistical variance across wells. But on average, the program delivers consistent performance year in and year out. In the early part of 2022, we had a few pads that performed towards the lower end of the distribution. But as expected, those wells are offset by outperformance seen in the latter part of the year. Heading into 2023, we expect to see consistent performance across our program. And as always, we are actively working to increase resource recovery through our culture of innovation and our cross-basin learning approach.

Moving north to the Montney. We’re very excited to get back to a more normalized level of activity in the BC part of our acreage. With the recent resolution of the legal dispute between the BC government and the First Nations, we are well positioned to execute a highly optimized program in the play this year. We have in hand all of the permits required for our 2023 program, and we continue to build our bank of permits for 2024. As a reminder, the vast majority of Ovintiv’s position in all our 2023 activity is on freehold lands and therefore, will not be subject to the restrictions that were announced as part of the new consultation agreement. We are continuing to deliver industry-leading results in the play. Over the last 12 months, Ovintiv has brought online 17 of the top 20 wells in the Montney on a BOE basis.

We hold a premier acreage position with substantial product optionality. Our premium inventory runway is more than 10 years in the oil and condensate window and more than 30 years in the natural gas window. This year’s 4-rig program of 70 to 80 net turn in lines will be largely balanced between our BC and Alberta acreage with a focus on our more liquids-rich areas. The economics on these wells remain outstanding. Even with current strip pricing, we expect to generate well level returns of more than 100%. These great returns are driven by our superior well results, low drilling and completion costs and strong price realizations. As a reminder, our condensate trades in line with WTI and more than 90% of our natural gas volumes are priced outside of the AECO market.

Our Uinta Basin has been generating some top-tier well results, and we are excited to continue development in the play this year. When we look at our resource in the basin, it has all the right characteristics to be to be highly competitive, both within our portfolio and among the top shale plays in North America. Our large contiguous land base of approximately 130,000 net acres is primed for cube development. It has multiple horizontal intervals with about 1,000 feet of collective pay. This translates into a significant inventory runway. Our Uinta team has delivered impressive well results recently, outpacing the peer average by about 50% and going toe-to-toe with core Delaware Basin results. We have long-term takeaway capacity out of the basin to the local Salt Lake City refining complex, and we recently secured additional scalable rail capacity to the Gulf Coast.

As a result, our Uinta oil receives an average price of about 85% of WTI and generates impressive margins. In 2022, the Uinta match the Permian for the highest operating margin in our portfolio. This year, we plan to share 2 rigs between the Uinta and the Bakken to bring on a combined total of 40 to 50 net wells. We’ve reserved some flexibility around the timing of rig moves between the assets. But at a high level, we currently expect to execute about 60% of our activity in the Uinta and 40% in the Bakken. We continue to be very pleased with the results from our Bakken play. Our recent 10-well vastly outperformed our expectations and produced an outstanding 2 million barrels of oil in just 200 days. Our Bakken team also did a great job in responding to extreme weather over the last few months and successfully kept our operations running with minimal downtime while bringing on 3 separate pad development projects.

We also continue to see strong well results in the play with our recent Kramer development projected to outperform our initial outlook by 25% through 360 days. With the resumption of normalized activity levels in the BC Montney, we have chosen to allocate less capital in the Bakken this year. But as I mentioned, we are taking a flexible approach to our activity by sharing rigs and a frac crew with the Uinta. At roughly 2/3 natural gas and associated NGLs, our Anadarko asset provides great product optionality and provide stable base production with ample market access and strong price realizations. As mentioned earlier, we’ve chosen to reduce our activity in the play and focus on optimizing asset level free cash flow and operational efficiencies, given the weaker outlook for gas and NGLs in 2023.

That said, I’m incredibly proud of the actions taken by the Anadarko team to reduce cycle time. During the fourth quarter, we achieved our best cycle time yet at 94 days, a 30% reduction compared to our 2021 average. They’ve also done a great job in shallowing out the base decline rate in the play to about 20%, further bolstering the cash generation capabilities of the asset. I will now turn the call back over to Brendan.

Brendan McCracken : Thanks, Greg. We’re delivering outstanding results, and we’re well positioned for today’s volatility. And with our balanced portfolio, we are also well positioned for the long-term needs of the global energy market. We take great pride in producing safe, affordable, reliable and secure energy while delivering superior returns to our shareholders. In 2023, we’ll continue to focus on the following key priorities. Safe work always, executing a disciplined development program focused on maximizing capital efficiency, generating significant free cash flow to enhance returns to shareholders maintaining our strong balance sheet and continuing to enhance our premium return drilling inventory. Our focus on execution, disciplined capital allocation, responsible operations and leading capital efficiency have positioned our business to thrive on the road ahead. This concludes our prepared remarks. Now operator, we’re now pleased to take questions.

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Q&A Session

Operator: Your first question will come from Neal Dingmann at Truist Securities.

Neal Dingmann: I’m just wondering, it seems like your shareholder’s plan seems to be not very stable. I’m just wondering what would it take to cause you to either decide to ramp that payout and change the capital return? I’m just wondering how maybe Corey, for you or Brendan, how stable is that is there things that could cause that to ramp even further?

Brendan McCracken: Yes, Neil. I appreciate the question. We’ve been very consistent with that capital allocation plan and the resulting shareholder returns since we launched it all the way back in the third quarter of 2021. And so we’ve really kind of followed our playbook there. If you remember, the foundation of that capital allocation model is our base dividend. And we’ve been pretty clear with our investors that we want to continue to see that base dividend going up with time. We’ve still got some headroom on the kind of notional level that we set for that to be around $300 million to $350 million a year, which really floats back to the 10% of EBITDA to mid-cycle price range. And so that’s probably the first place I’d start and then the second place is the one that you’re maybe pointing to, which is does that percentage of free cash flow march up with time?

And really, the plan we’ve been following there is to both be reducing debt and paying back 50% of that free cash flow to shareholders. And so that’s the mode we’re in today, but it’s something we’re always looking at to see what’s going to drive the valuation of the equity and be the right thing for the shareholders. So yes, maybe I’ll leave it there.

Neal Dingmann: No, that’s well said. And then maybe just 1 last 1 for Greg. How different than when you’re seeing inflation out in the market versus your different plays when I’m looking at Uinta versus firm versus Anadarko. I’m just wondering how different is inflation out there today for you?

Greg Givens: Thanks for the question, Neal. And so we saw quite a bit of inflation throughout the year in 2022. As we ended the year and started into the fourth quarter — sorry, first quarter, it feels like the rate of change is really subsided, and we’re seeing a leveling off. As far as how that affects us across our different plays. We are seeing less inflation in Canada as compared to the U.S. And so we’re — that’s one of the reasons why we really like the play there, as I noted in my prepared remarks.

Operator: Your next question comes from Greg Pardy at RBC Capital Markets.

Greg Pardy : I wanted to — Brendan, sorry, I’m catching my voice here. want to come back to the reserve report a little bit, just on the oil side. So pretty significant revisions and so forth that we saw. I’m just wondering where did they — were they concentrated in any one plan? Is there a little bit more that you could frame around those?

Brendan McCracken: Yes, Greg. No, I appreciate it. So the first place to start is on the U.S. oil reserves, total proved year-over-year, it’s flat after you adjust for the sale of that you went to waterflood. And there’s really a couple of moving parts to talk to, and I’ll get Corey to chime in here, too. But the 2 categories you want to look at are the extensions and discoveries and then the revisions and improved recoveries categories. And if you net the 2 of those together, our approved reserves actually go up by 30 million barrels year-over-year and then you take off the production that we produce through the year, and that’s how you get to flat year-over-year after adjusting for that, you into sale. So maybe, Corey, you want to talk just a little bit about how the process works there and why those 2 categories net together?