Evolution Petroleum Corporation (AMEX:EPM) Q2 2023 Earnings Call Transcript

Evolution Petroleum Corporation (AMEX:EPM) Q2 2023 Earnings Call Transcript February 8, 2023

Operator: Good day, everyone, and welcome to the Evolution Petroleum Second Quarter Fiscal Year 2023 Earnings Release Conference Call. . Please also note today’s event is being recorded. At this time, I would like to turn the floor over to Ryan Stash, Chief Financial Officer. Please go ahead.

Ryan Stash: Thank you, and good afternoon, everyone. Welcome to our earnings call for the second quarter of fiscal 2023. Joining me today is Kelly Lloyd, our President and Chief Executive Officer and a member of our Board of Directors. After I cover the forward-looking statements, Kelly will review key highlights along with our operational results. I will then return to provide a more detailed financial review. And then Kelly will provide some closing comments before we open it up and take your questions. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. Our discussion today will contain forward-looking statements of management’s beliefs and assumptions based on currently available information.

These forward-looking statements are subject to risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. As detailed numbers are readily available to everyone in yesterday’s earnings release, this call will primarily focus on our strategy as well as key operational and financial results and how these affect us moving forward. Please note that this conference call is being recorded. If you wish to listen to a webcast replay of today’s call, it will be available by going to the company’s website. With that, I’ll turn the call over to Kelly.

Kelly Loyd: Thank you, Ryan. Good afternoon, everyone, and thanks for joining us on today’s call. Our results in the second quarter of fiscal 2023 were solid and continued to demonstrate our assets’ ability to generate strong free cash flow. We used our cash flow to once again fund operations. We used it on capital spending and shareholder dividends. In addition, I’m pleased to report that we have delivered on our commitment to eliminate our remaining debt position during the period. We have now fully integrated multiple acquisitions, paid off our debt and are generating meaningful free cash flow to fund our strategic objectives. Of course, none of this would have been possible without the hard work of our team. I want to thank all of our team members for their continued dedication and strong execution as we remain focused on driving near- and long-term value for shareholders.

During the second quarter, we paid a cash dividend of $0.12 per common share. This was 60% higher than the same period for fiscal 2022 which we view as a clear indicator of the growth and strength of our business. Our Board recently declared a cash dividend for the third quarter of fiscal 2023 of $0.12 per share. This will mark the 38th consecutive quarterly cash dividend paid by the company since we began our return of capital program in December of 2013. Since the inception of the program, we have returned more than $94 million or $2.85 per share of capital to shareholders. As we have discussed in the past, there are very few small-cap E&P companies that can say they have consistently paid a dividend for that length of time throughout several tumultuous commodity price cycles.

We believe this reinforces the strategic view our Board takes as we prudently grow the business through the targeted acquisition of solid, long-life and low-decline assets that will continue to support a sustainable quarterly dividend for the immediate long term. In short, maintaining and ultimately growing the payment of a quarterly cash dividend remains front and center for our Board and management team. Turning now to operations. Second quarter fiscal 2023 production of 7,250 net BOE per day was down around 5% from the 7,598 net BOE per day for the first quarter of fiscal 2023. In large part, this was due to downtime associated with the severe winter storms we experienced, and to a lesser extent, some temporary compression issues and some downtime in the Barnett associated with offset operator activity.

As of now and barring any future extreme weather circumstances, operations are back on track. Looking at our second quarter results in more detail, net production at Jonah Field for the second quarter was 1,902 BOE per day. Slightly impacting production levels in the second quarter was the decision to maximize natural gas production, thus reducing NGL recoveries during the period to capitalize on relatively higher natural gas prices, which averaged $11 per Mcf for the quarter. The Jonah Field is our most recent acquisition, and we remain pleased with its performance. Similar to our other assets, the field is highlighted by long-life, low-decline reserves that generate significant cash flow. In addition, the asset base provides access to attractive Western markets.

Second quarter net production for our Williston Basin was quite flat to the first quarter at 489 BOE per day, of which approximately 76% was oil. The Williston Basin oil production was impacted by the winter storms during the quarter. However, this was offset by the reactivation of the gas pipeline. We are pleased to see the ONEOK gas pipeline come back online in late September for the first time since our acquisition. This has led to increased optionality for natural gas in NGL sales. In early January, we along with the operator, Foundation Energy Management, began operations on one of our Bakken recompletions and continue to work closely with them on high-grading opportunities in the field such as expense workovers, additional recompletions and sidetrack drilling opportunities.

Also, technical evaluations remain underway to assess our Pronghorn and Three Forks drilling locations. Net production for the Barnett Shale for the second quarter was 3,304 BOE per day, of which approximately 76% was natural gas. As discussed previously, impacting sequential production volumes were severe winter storms, temporary issues at select compression stations and certain offset operator activities, all of which have been addressed. Hamilton Dome Field net production was substantially flat for the second quarter at 413 BOE per day. We continue to support the operator, Merit Energy, in their efforts to restore production at previously shut-in wells, adjust water injection locations and volumes and execute on other targeted maintenance projects.

Additionally, in the quarter, we and Merit began upgrading facilities to proactively reduce emissions throughout the field. Second quarter net production at Delhi Field was approximately 1,131 BOE per day. Denbury, the operator at Delhi took steps to minimize the severe weather impacts, which resulted in only minor downtime during the second quarter despite the storms. They are continuing to perform conformance workovers and upgrades to the facilities. With that, I’ll now turn the call over to Ryan to discuss our financial highlights.

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Ryan Stash: Thanks, Kelly. As mentioned earlier, please refer to our press release from yesterday afternoon for additional information concerning our second quarter fiscal 2023 results. My comments today will primarily focus on financial highlights and comparative results between the second and first quarter of fiscal 2023. A key highlight of the second quarter was our continued solid generation of cash flow including adjusted EBITDA of $16.4 million. This was $24.66 on a per BOE basis, which was an increase from the first quarter. We have now generated $33.5 million in adjusted EBITDA for the first 2 quarters of fiscal 2023. As Kelly discussed, during the second quarter, we continued to fund our operations, development capital expenditures and dividends out of operating cash flow while also repaying all of our remaining debt.

Supported by our continued strong operational and cash flow outlook, we paid a dividend of $0.12 per share in the second quarter and declared a dividend of $0.12 per share for the third quarter of fiscal 2023, payable on March 31 to shareholders of record as of March 15. Our cash dividend program has and will continue to be a top priority as we clearly recognize the strategic importance of returning value to our shareholders. During the second quarter, we enhanced our already strong balance sheet delivering on our commitment to paying off our debt in the second quarter. We eliminated our remaining debt position of $12.3 million. Our borrowing base remained at $50 million, and we had cash and cash equivalents of $3.7 million and working capital of $2.9 million as of December 31, 2022.

The result was growth in our liquidity to $53.7 million, a 45% increase from only 6 months ago. This is a direct result of our targeted and immediately accretive acquisitions over the past couple of years as well as our continued focus on cost control. We are ideally positioned for the continued execution of targeted future growth opportunities that meet our strategic vision. As a result of eliminating our outstanding debt position, we are not currently required to maintain any hedges on our production and our existing hedge positions are set to expire next month. Looking at the second quarter financials in more detail. Our total revenue of $33.7 million was 15% lower than the first quarter due to a combination of factors, including lower oil revenue associated with 1% lower sales volumes and a 13% decrease in realized pricing.

Lower natural gas revenue due to a 5% decrease in sales volumes and 8% lower realized pricing despite declines of almost 30% in Henry Hub pricing. Decreased NGL revenue due to 8% lower sales volumes and a 27% decrease in realized pricing. The result was an average realized price per BOE decrease of 11% to $50.49. Lease operating expenses decreased 21% quarter-over-quarter to $15 million in the second quarter. On a per BOE basis, lease operating expenses were $22.55 for the second quarter compared to $27.35 in the first quarter. Primarily contributing to the decrease in LOE were changes in estimates from prior periods and reduced ad valorem and production taxes due to lower revenues in the current period. Also contributing to the decrease was lower work-over expense in the Williston Basin and reduced CO2 costs at Delhi Field associated with the decrease in crude oil prices from the prior quarter.

As a reminder, our CO2 costs at Delhi Field are directly impacted by the price of oil. Therefore, lower oil prices result in lower CO2 costs. General and administrative expenses were $2.6 million for the second quarter versus $2.5 million for the first quarter. The slight sequential increase was primarily due to higher noncash stock-based compensation in the second quarter that was partially offset by lower professional services fees compared to the first quarter. The end result is that on a cash basis, second quarter G&A was essentially flat with the first quarter. Net income for the second quarter was $10.4 million or $0.31 per diluted share versus $10.7 million or $0.32 per diluted share in the first quarter. Adjusted net income for the second quarter was $9.6 million or $0.28 per diluted share versus $10 million or $0.30 per diluted share in the first quarter.

During the second quarter, we invested $1.1 million in development and maintenance capital expenditures. For fiscal 2023, we continue to expect total development capital expenditures of $6.5 million to $9.5 million. This estimate includes upgrades to the Delhi Field central facility, workovers at Hamilton Dome field, the Barnett Shale and the Jonah Field and sidetrack drilling opportunities and low-risk development projects in the Williston Basin, excluding the development of Pronghorn and Three Forks locations. We expect capital spending on our existing properties were continuing to be met from cash flows from operations and current working capital. Of course, our spending outlook may change depending on conversations with our operating partners, commodity pricing and other considerations.

After repaying our outstanding debt and upon emerging from blackout, we entered into a Rule 10b5-1 share repurchase plan in December that authorized up to $5 million in buybacks, subject to limitations on trading volume and stock price. The plan is effective through June 30 and can be extended or renewed by the Board. The plan also had a 30-day cooling off period, so there were no repurchases made until January. We plan to provide an update on our buyback activity in our third quarter 10-Q to be filed in May. I will now turn the call back over to Kelly for his closing remarks.

Kelly Loyd: Thanks, Ryan. We continue to benefit from the targeted acquisitions that we have completed over the past few years, including 2 in just the last 12 months. As a result, we enjoy a larger and more geographically diverse asset base and commodity mix. This provides us with a solid platform for significant cash flow generation that we will continue to use to support and enhance our well-established shareholder capital return program. Our shareholders expect a consistent and meaningful cash return on their investment, and we remain committed to maintaining and as appropriate, increasing our dividend payout over time. Another component of our capital return strategy is the share repurchase program that we put in place and began making purchases through after having fully repaid our revolving credit facility at the end of the second quarter.

This provides the optionality to opportunistically repurchase our shares from time to time through open market transactions, privately negotiated transactions or by other means in accordance with federal securities laws. As in the past, we will maintain a conservative balance sheet and remain disciplined in our management of capital as we fully recognize the cyclicality of our business. Our ongoing commitment to remaining fiscally prudent was evidenced by our prompt pay down of our debt position following the closing of our most recent acquisitions. We are well positioned to execute on targeted high rate of return and immediately accretive growth opportunities as appropriate. We will continue to execute our strategic plan, focused on maximizing total shareholder returns and optimizing every dollar that we invest.

Our approach of building a targeted asset base of PDP reserves capable of supporting cash payments to shareholders has served us well over the past decade and will continue to benefit our shareholders for many years to come. As we’ve discussed in the past, we will closely evaluate and only execute on targeted acquisition opportunities that are immediately accretive, provide long life established production, strategically expand our base of assets and do not result in material dilution. Any transaction must also clearly support our long-standing thesis of providing a significant total shareholder return for our shareholders. With that, we are ready to take questions. Operator?

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Q&A Session

Operator: . Our first question today comes from John White from Roth Capital.

John White: Very nice results this quarter. Kelly, are you settling into your CEO Chair?

Kelly Loyd: It’s — yes, is the answer. Again, with the outstanding team we have here, it’s made a good smooth transition. So I appreciate you asking me that.

John White: On the CapEx issues, the press release and as Ryan just reiterated, provides a range of $6.5 million to $9.5 million. And then you explain what that capital spending is going to be directed to. And then there’s a phrase in the remainder of that where it says does not include any CapEx for the Pronghorn and Three Forks locations in the Williston. Could you give us a ballpark idea of the potential magnitude that some of those wells might add to the fiscal 2023 CapEx?

Kelly Loyd: Sure. It all depends on the pricing in there and one of the reasons we’ve been really going back and forth on this pricing in that part of the world has moved a lot and it’s moved up and we’re starting to see it ease a bit. But — so it’s kind of a range per well, a fully completed well. And look, I don’t want to give an exact number, but I would say, just to be safe, anywhere from $7.5 million to $10 million.

John White: Yes. That’s on an basis, right?

Kelly Loyd: Right. are working in locations, every location is different. So some of them may 50%, some of them may be more like 30%, where the ultimate location goes.

John White: So you’re saying that would change the top end of the range from 9.5% to 10%.

Kelly Loyd: I’m saying you would add another depending on the working interest, right, gross $7.5-ish to $10 million per well.

Ryan Stash: Yes. That would assume that we would drill and complete the well this fiscal year, John, right? So I mean that would obviously require decision.

Kelly Loyd: That’s right, but again, that’s sort of the concept. It depends on — every location has a different sort of working interest. You’ve got — you have prices moving around significantly for the service side of things part of the world. And you’ve got permitting process timing. All those sort of issues to play with. But just on a per well base. I think we’ve advertised for somewhere in that, and it was a broad range, but we don’t want to get too specific at this time.

John White: No. That’s perfectly acceptable and I understand. And what’s the status of some of these locations? Have wells been proposed by the operator, and have they sent you an AFE?

Kelly Loyd: So as far as Pronghorn, Three Forks wells, no, we are working with them closely. They have not proposed any wells there. We have — they have proposed AFEs on the recompletions in the Bakken, up hole vertical recompletions in some old Bakken wells, and we’ve actually recently begun one. And the other part — the other thing we’re working about — we’ve spoken about the or in the past. And I mean, John, basically the way this all jumbles together, they all have their own pros and cons, and they have their cost associated with them and expected results and risk. And so you’re putting them all in there. We’re working together, coming up with at this time what makes the most sense to do right now. And on that front, what jumped to the head of the line and we’re excited about it is the recompletion up hole vertical well, it was drilled deeper than the Bakken coming up when completing it there.