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Operator: Good morning. My name is Julie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Q2 Conference Call. All lines that in place don’t mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Dion Hatcher, you may begin your conference.

Dion Hatcher: Well, thank you, Julie. Well, good morning, ladies and gentlemen. Thank you for joining us. I’m Don Hatcher, President and CEO of Vermilion Energy. With me today are Lars Glemser, Vice President and CFO; Darcy Kerwin, Vice President, International and HSE; Bryce Kremnica, Vice President of North America; Jenson Tan, Vice President, Business Development; and Kyle Preston, Vice President of Investor Relations. We’ll be referencing a PowerPoint presentation to discuss our Q2 2023 results. Presentation can be found on our website under Invest with Us and Events & Presentations. Please refer to our advisory and forward-looking statements at the end of the presentation. It describes forward-looking information, non-GAAP measures and oil and gas terms used today, and it relies to risk factors and assumptions relevant to this discussion.

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Production during the second quarter averaged 83,152 BOEs per day, which was at the top end of our Q2 guidance range of 80,000 to 83,000. We revised our Q2 production guidance in mid-May to reflect the temporary shut-in of approximately 30,000 BOEs a day in West Central Alberta due to forest fires, defined impact of Q2 volumes from the wildfires and — the Australia downtime was approximately 8,000 BOEs per day. Our team was quick to respond to the fire situation in Alberta and was able to safely restore all of the production within weeks of the initial shut-in, which minimized the impact of the fire. In addition, we achieved strong operational performance across many of our other assets. We generated $247 million of fund flows and invested $167 million of E&D capital, resulting in $80 million of free cash flow of which we returned $40 million to shareholders via the base dividend and share buybacks, representing a return of capital payout of approximately 50%.

During the first half of 2023, we have declared $33 million in dividends and repurchased $54 million of our common shares, representing $87 million return to our shareholders. We continue to target shareholder returns of 25% to 30% of free cash flow for 2023 with debt reduction remaining the priority until we achieve our next net debt target of $1 billion. Net debt at the end of Q2 decreased slightly to $1.3 billion, representing a trailing net debt to fund flow ratio one times, given the front-end weighting of our capital program, combined with higher forecast production and cash flows in the back half of the year, we anticipate generating more free cash flow in the second half, which should translate to accelerated debt reduction. Production from our North American operations averaged 54,000 64 BOEs today in Q2, a decrease of 10% or 6,000 BOEs per day from the prior quarter, mainly due to the disposition of approximately 8,500 BOEs a day of higher cost assets in our Southeast Saskatchewan and approximately 4,000 BOEs today of fire-related downtime in West Central Alberta.

We’re able to partially offset this impact with organic production growth from Mika, Montney, Southeast Saskatchewan and the US assets, which added approximately 3,400 BOEs a day combined in Q2. All the production that was temporary shut in as a result of the wildfires has been restored, thanks to the hard work of our employees and contractors. Although, there was no major damage to our facilities or well sites, we will continue to monitor the forest fire and take any necessary action to ensure the safety of our people and assets. We again want to thank our operations staff for the safely restoring production during this difficult period. In West Central Alberta, we completed one and brought on production five Mannville liquids-rich gas flows by Mica, we drilled two, completed four and brought on production on Montney liquids-rich gas well.

In Saskatchewan, we drilled, completed and brought on production on oil well. In the US we drilled seven, completed 10 and brought on production five oil wells mildly. As part of our activity in the quarter, we participated in the drilling of two non-operated Parkman wells and one non-operated Niobrara well. We continue to evaluate these formations as it relates to future development prospects on our Powder River Basin acreage in Wyoming. Across North America, we are seeing strong overall performance from our capital program and ongoing operations, which has helped in mitigating the impact of fire-related downtime in Alberta. Our recent BC Montney wells at Mica continued to perform very well with minimum decline seen over the first 120 days of production.

BC pad results validates our Tier 1 inventory in BC and presents an opportunity for future down spacing. Our 2024 program will be focused exclusively on our BC land with approximately 10 wells on or outsetting the 16 to 28 pad. We recently received the final permit required for the construction of the 16,000 boes day battery on the BC lands and are planning to start site preparation later this year. The majority of this construction will occur in the first half of 2024, and we fund it through a financing agreement with a third party midstream company. This agreement was part of the Mica acquisition. We are excited to execute the next expansion phase and look forward to providing future updates in the quarters ahead. Production from our international operations averaged 29,087 BOEs per day, an increase of 30% from the prior quarter, mainly due to the acquisition of additional working interest in Corrib, which closed on March 31 of this year.

This acquisition added approximately 7,000 boes a day of premium priced European natural gas production. Ireland’s production more than doubled in Q2 to an average of 11,251 boes a day into the due to the closing of this acquisition as well as better than forecast operational run rates. In the Netherlands, we completed on conventional gas well from our Q1 drilling program. In Germany, we continue to advance our deep gas exploration and development plans as we prepare for our first well to be drilled in the fourth quarter of this year. In Australia, we completed all remaining inspections and repair work within the primary systems of the platform at the end of Q2 and made preparations to restart the facility. As a result, we expect higher operational run rates with less online downtime in the future.

inspections and repair work completed on the platform was conducted in a safe and efficient manner without incident. We would again like to thank our staff and contractors for their diligence in executing a safe and successful program. After completing all inspection repair work within the primary system building platform, we proceeded to function test all systems as part of the facility restart in early July. During the step, we noted that leak supplying seawater to a secondary area of the dilate virus suppression system to ensure we have addressed any outsetting items, we elected to replace the seawater piping at this time, which will delay start-up to the end of Q3. This is the longest period that the Wandoo platform has been offline since Vermilion has operated it.

The scope of the repair work itself was mainly pipe valves and fittings and replacements. It was time-consuming process given the logistics associated with working on an offshore platform. In particular, there are a limited number of beds, accommodate workers and the work itself require the assembly and the disassembly of complex gaffing through the platform. Although major work is now behind us, system of the platform are function tested and ready for start-up once the seawater piping is replaced. With these delays impact short-term production and cash flow, it is the right long-term decision as it enhances the safety and the integrity of our asset while improving future operational run rates. The Wandoo asset has been in our portfolio since 2005 and has generated significant amount of free cash flow over this timeframe.

2022, Wandoo crude sold at a US$14 premium to Brent, which drives very strong netbacks. Under current strip pricing, we are forecasting over CAD 100 million of free cash flow from Australia in 2024. I will now pass it over to Lars to discuss our guidance and financial outlook.

Lars Glemser: Thank you, Dion. As a result of the increased scope of repair work on the Wandoo platform in Australia as well as the planned turnaround at the core facility in Ireland, we expect Q3 volumes to be consistent with Q2 guidance of 80,000 to 83,000 BOE a day. As we complete the Australia integrity work and core turnaround, we will be positioned to deliver Q4 production in the range of 86,000 to 89,000 BOE a day. As a result of strong operational execution and performance across our portfolio, we are maintaining our 2023 annual production guidance of 82,000 to 86,000 BOE a day as we have been able to offset much of the impact from the Alberta wildfires and extended Australia downtime. The rest of our annual financial guidance remains unchanged from our last revision.

Our disciplined approach towards debt reduction, combined with our asset high-grading initiatives over the past three years has made Vermilion a more resilient business today. By the end of this year, we will have nearly cut our debt in-house while also funding over CAD 1 billion of strategic acquisitions and have significantly increased our average annual FFO from pre-COVID levels. While strong commodity prices have contributed to this improvement, we believe the company is much better positioned. Our top decile netbacks, low-base decline, diversified commodity exposure and capital-efficient asset base combined with our modest base dividend payout, translates to a very resilient business that could be managed through low commodity cycles and is well positioned for increased return of capital to shareholders as debt is reduced.

As we look out to 2024, we are currently forecasting a significant increase in FFO to over CAD 1.4 billion, assuming a flat production profile. With this, we expect to achieve our next net debt target of CAD 1 billion during the first half of 2024. Consistent with our previous messaging, we plan to increase shareholder returns upon achieving this debt target and we’ll communicate the method and targeted payout range at that time. We anticipate that share buybacks will remain the primary mechanism for returning incremental capital beyond the base dividend. And as such, we renewed our normal course issuer bid in early July and continue to buy back shares. Since July of last year, we have bought back 5.7 million shares. Lastly, I wanted to provide a brief update on our hedge position, in particular, our European gas hedges.

European gas has been trading at elevated levels for the past few years, and we believe there has been a structural positive shift in European gas fundamentals as you can see in the forward price on this chart. European gas prices are currently trading approximately 7 times higher than April gas prices and the forward curve is holding in at around CAD 20 per MMBtu. This is a very attractive price as it generates high project returns and significant free cash flow from our European gas assets. As such, we have been actively hedging our forward European gas production at or above these levels. For the upcoming periods on European gas in Canadian dollar terms, we have 51% hedged for second half of 2023 at an average price of $30 per mmbtu 30% hedged for the first half of 2024 at an average floor of $47 per mmbtu and 16% hedged for second half 2024 and at an average floor of $25 per mmbtu.

We have also been starting to layer in some oil hedges and intend to increase our corporate hedge position from current levels with a view to lock in a reasonable amount of cash flow to provide greater certainty in achieving our debt targets and in support of executing our operational and return of capital plans. With that, I would like to pass it back to Dean for his closing remarks.

Dion Hatcher: Thanks, Lars. To further expand Lars’s comments on free cash flow generating capacity. I would like to highlight the following chart, which shows our free cash flow allocation over the past few years. The blue bar shows the total amount of free cash flow generated by the stack parcels, how this free cash flow was allocated in each of the years. As you can see, the majority of our free cash flow, a total of $1.6 billion between 2021 and 2023 was allocated to debt reduction and acquisitions — is aligned with our strategy of ensuring a strong balance sheet and robust asset base. Going in 2024, most of that heavy lifting on debt reduction will be behind us, which means we have more free cash flow to allocate the shareholder returns in the years ahead.

As you look into 2024, we are positioned to generate significantly higher free cash flow. As I mentioned earlier, we intend to increase the amount of return to our shareholders once we achieve our $1 billion debt target expected during the first half of 2024. Well, that concludes my prepared remarks. And with that, we would like to open it up for questions.

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Operator: Thank you. [Operator Instructions] Your first question comes from Amir Arif from ATB Capital. Please go ahead.

Amir Arif: Thanks. Good morning, guys. Just a few quick questions. First of all, just on the Montney side. I think you’re planning 10 wells next year. Were you planning on drilling those currently with the construction in the first half. So should we expect Montney production to start being meaningful in the second half in terms of growth, or is it — all the drilling be happening once you’ve got better clarity on start-up of the facility.

A – Dion Hatcher: Maybe I can take that high-level question here. It’s Dion. Thanks for the question. As noted on the call, the construction of the battery itself will — some of that site prep work will initiate second half of this year, but the bulk will be in the first half of 2024. So from a planning point of view, we would initiate that drilling. But realistically, I think the time line for that production coming on would be closer to midyear. So that’s our assumption, our plans right now.

Amir Arif: Okay. And then so Dion, would you drill all 10 wells in the first half, or the 10 is spread throughout the year for next year?

A – Dion Hatcher: These well, there’s basically two — mainly two pads, and so this would be back-to-back drilling. As you can imagine, there’s some cost synergies and efficiencies. So yes, we would look to drill those pads back to back and line up midyear.

Amir Arif: Got it. Appreciate that. And then just a quick question on the German — Germany. I know you continue to drill that deep exploration gas well over there. Can you just give us an update on when you expect to hit TD? And when do you expect to have some results on that?

Dion Hatcher: Sure. I’m going to ask — pass it over to Darcy Kerwin, our Vice President of International. Darcy, do you want to take that one?

Darcy Kerwin: Yes. Thanks, Amir. I think as you know, we’ve been excited about the deep gas exploration potential in Germany. We have successfully drilled deep gas wells there before, we drilled Burgmoor [ph] in 2019, that well is still producing nicely for us. And so we’re kind of after some pause during the COVID downturn, put renewed focus on that exploration program, both on the GSI side and on the permitting side. So we have a number of interesting prospects to look out there in Germany, and we’ll kick off kind of the first of that set of prospects starting here in Q4 2023 with the first exploration well that we plan to drill.

Amir Arif: So I guess from a TD point of view, Darcy, we’re really looking at early next year with the time we take to spud the well and get those well results.

Darcy Kerwin: Yes, we’ll spud the well in Q4, and then that well will drill through the end of the year and TD early in 2024.

Amir Arif: Okay. I appreciate that. And just a final question on the windfall taxes, the TTF gas price was down sequentially quarter-over-quarter, yet windfall taxes were up. Can you just help me understand, why would it move with the TTF prices? Is there just a lag in terms of the payments?

Dion Hatcher: Yes. Let me pass over to Lars to address that question.

Lars Glemser: Yes. Thanks, Amir. The big reason for the increase in windfall taxes from Q1 to Q2 of this year is the fact that we closed the Corrib acquisition on March 31 of this year. And so, in Q2, we started to recognize the production and FFO or free cash flow impact of the incremental 36.5%. So that would explain the bulk of the increase Q1 to Q2.

Amir Arif: Appreciate that. Thanks.

Operator: [Operator Instructions] There are no further questions at this time. Please proceed with your closing remarks.

Dion Hatcher: With that, thank you again for participating in our Q2 conference call.

Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for joining, and you may now disconnect.