Penn Virginia Corporation
Q4 2016 Earnings Call Transcript

Published: 11 Aug 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Penn Virginia Corporation’s Second Quarter Earnings Call. [Operator Instructions] As a reminder, this program is being recorded. And now I’d like to introduce your host for today’s program, John Brooks, Chief Operating Officer and Interim Principal Executive Officer. Please go ahead.

[John Brooks:]

Thanks, Jonathan. Good morning, everyone. We appreciate your participation in today’s call. I’m joined today by Steve Hartman, our Chief Financial Officer. Prior to getting started, I’d like to remind you of the language in our forward-looking statement section of the press release, which was released yesterday afternoon. Our comments today will contain forward-looking statements within the meaning of the federal securities laws. These statements, which include but are not limited to comments on our operational guidance, are subject to a number of risks and uncertainties that could cause actual results to be materially different from those forward-looking statements including those identified in the risk factors of our annual report on Form 10-K and quarterly reports on Form 10-Q, filed with the Securities and Exchange Commission. Cautionary language is also included on Slide 1 of our presentation, which is available on our website. We will use the presentation to go through today’s discussion. Finally, after our prepared remarks, we will answer any questions you may have. So let’s start with Slide 2 of the presentation, which highlights our strong second quarter financial and operating performance. Steve will discuss our quarterly financial results in detail in a few minutes. But on the operations front, our production exceeded the top end of our guidance range by more than 450 barrels of oil equivalent per day or approximately 5%. We had 2 rigs running that drilled 7 gross wells in the quarter. The average drilling days per well was 16. All of those wells were located on the Chicken Hawk and Jake Berger pads, which we sometimes also refer to as our super pad. During the quarter, we turned to sales 4 wells from the Kudu pad located in the northern portion of our Area 1. The company has an average working interest of 43.7% in each of the Kudu wells. On average, the wells had average lateral length of 5,429 feet or spaced at approximately 400 feet. And had a 30-day IP of 806 barrels of oil equivalent per day, of which approximately 94% was crude oil. Also in response to the 4-well Kudu pad’s slickwater fracs, we observed positive frac hits on 2 offset parent wells combined for a peak rate uplift of 75 barrels of oil per day and averaged 50 barrels of per day over 5 months. Also, during the quarter, we turned to sales the Lager 3H well, which is our first test of slickwater in our down-dip, higher pressured acreage that we call Area 2. This well was completed with 40 stages over an 8,000 foot lateral targeting 2,500 pounds of proppant per foot. The Lager 3H has been online for more than 95 days with cumulative production of approximately 136,000 barrels of oil equivalent, 70% of which is crude oil. It is currently producing approximately 1,000 barrels of oil equivalent per day and is still flowing up casing at 1,700 psi. We also observed positive frac hits on 2 offset parent wells here, too, with a combined peak rate uplift of 115 barrels of oil per day and an average of 65 barrels of oil per day over 4 months. The Zebra 6H and 7H wells on the 2-well Zebra pad were also completed and turned to sales in the second quarter. These 2 wells targeted the lower Eagle Ford Shale in Area 1 and were drilled approximately 400 feet apart. We hold a 42.5% working interest and are the operator of both wells. On average, the combined wells had a 30-day IP of 1,058 barrels of oil equivalent per day, of which 94% was crude oil. This equates to 223 barrels of oil equivalent per day per 1,000 foot of lateral. The Zebra pad also resulted in positive frac hits to 2 offsetting parent wells with a combined peak rate uplift of 130 barrels of oil per day and an average of 75 barrels of oil per day over 3 months. The 2-well Zebra pad in Lager 3H are currently outperforming our current type curve. We’ve been actually – actively managing the choke size on all 3 of these wells in order to main pressure, which ultimately should increase ultimate recoveries. Given the success of the Lager 3H wells, we have accelerated drilling in Area 2. The Schacherl-Effenberger pad, which is originally designed as a 1-well pad, will now be a 2-well pad with drilling operations scheduled to commence in September. Completion operations are underway on our super pad, which consists of 2 adjacent 4-well pads, the Chicken Hawk and the Jake Berger. We’ve actually completed frac operations on the 4 Chicken Hawk wells and expect to commence from operations on the Jake Berger pad in the next week. We plan to turn these 8 wells to sales in September. 2 of the wells are in the Upper Eagle Ford and 6 wells are in the Lower Eagle Ford shale, testing co-development, sometimes also referred to as the stack and stagger completion technique. The wells are in Area 1, spaced approximately 400 feet apart, and we’re targeting pumping 2,500 pounds per foot of proppant. During the second quarter, we continue to grow our footprint organically, including leasing and/or extending approximately 1,000 net acres. This increases our core acreage position to approximately 57,000 net acres with approximately 93% of that held by production. Finally, last week, we announced an exciting strategic acquisition of Devon’s Lavaca County Eagle Ford assets, which is an important step in our long-term growth strategy. And on Slide 3, we look at that acquisition in more detail. As you can see from the map, it is an excellent fit with our core operations in the Eagle Ford and materially increases our production footprint and drilling inventory. We target closing the transaction on September 30 with an effective date of March 1. Adjusting for estimated net cash flows from the effective date to the closing date, we are effectively buying the assets for $190 million. This acquisition is extremely compelling, as we are bolting on approximately 19,600 net acres that are contiguous to our core operating footprint. As such, our operating team knows this area extremely well. We plan to utilize our extensive technical capabilities to optimize production and reduce operating and administrative costs. We are buying net production of approximately 3,000 barrels of oil equivalent per day that is over 60% oil, increasing our net production by approximately 30%. More importantly, the acquisition provides us the opportunity for drilling a significant number of extended reach laterals with attractive PV-10 breakeven pricing of less than $30 per barrel. We plan on funding the acquisition with $150 million of newly committed debt financing, as well as draw on our recently expanded credit facility. This low cost of capital, along with the additional production, makes this transaction highly accretive for Penn Virginia on all key metrics, including earnings, cash flow and net asset value. It’s also important to note that after adjusting the net purchase price for the value of net production, overriding royalty interest in the included midstream assets, we are paying less than $3,000 per net acre. We’ve also identified approximately $40 million of operational synergies, including installing centralized gas lift, reducing salt water disposal costs by expanding our water gathering system and/or contract renegotiation, as well as other optimization opportunities that we plan to initiate over the coming year Slide 4 really illustrates how well Devon’s Lavaca County Eagle Ford assets fit with Penn Virginia’s core acreage. Also, since this acreage is 90% held by production and located around our existing wells, the drilling locations have been significantly derisked. The Devon assets come with 42 drilling units, 16 of which, or 35% of the total, are currently operated by Penn Virginia. We have identified 91 gross locations in the Lower Eagle Ford formation, 43 of these locations will be extended reach laterals, including 26 locations that could be 10,000 foot or greater, subsequent to forming the appropriate production sharing agreements. Majority of these extended reach laterals will require forming production sharing agreements, and we’ve modeled that process will go on into 2018. We’ve already formed 5 PSAs in this area on our existing acreage, with another 2 in process. And as such, our land department has solid experience in successfully securing PSAs in the vicinity. In the meantime, while those PSAs are being formed, we’ve identified some longer-than-average laterals to drill and complete. And while they may not be 10,000 foot, they could be 8,000 foot or longer. To the extent we can form the PSAs faster than we have modeled, we could, at the end of the day, have more than 43 extended reach laterals available for drilling before the end of 2018. Another feature of these properties being acquired is their high working interest, an average of over 90%, which also helps drive the PSA formation process. In addition to attractive drilling inventory, we are also buying proved developed producing reserves of approximately 6.3 million barrels of oil equivalent. We currently estimate a total resource potential of greater than 60 million barrels of oil equivalent, which provides us with significant upside. As I mentioned earlier, there are midstream assets included in the transaction and this includes an in-field gathering and compression system with no volume commitments or acreage dedications comprised of over 23 miles of pipelines with multiple delivery points. I mentioned the positive results we had seen from the Lager 3H well and there’s actually 3 important takeaways from the success of the Lager 3H. Not only was this our first slickwater completion in the deeper, higher pressured down-dip portion of our acreage that we call Area 2, it also demonstrates the effectiveness of drilling a longer lateral. And as a result of the Devon acquisition, we will increase our working interest in the Lager well from approximately 41% to 96%. So leveraging off the success of the Lager 3H, the Devon acquisition not only provides an immediate 30% increase in our total production, it also gives us an inventory of opportunities to drill longer laterals in higher pressured oil-producing Eagle Ford, completed with high-intensity slickwater fracs at a higher working interest. And we think there is room to improve upon our Lager 3H results. EOG has also completed several high-performing slickwater wells all around our existing acreage position in Area 2, as well as in the vicinity of the acquired Devon acreage. And none of the wells on the Devon-operated acreage that we’ve acquired – that we are acquiring have yet utilized slickwater completion. So we believe there is significant upside to these assets, not only for extended reach laterals, but also for applying slickwater completion design. After closing, we expect to continue to operate 2 drilling rigs. In addition to the Lower Eagle Ford potential, we see significant upside potential from the Upper Eagle Ford and the Austin Chalk formations. Indeed several of the producing wells we are purchasing from Devon are, in fact, completed in the Upper Eagle Ford. Having said that, we intend to focus our initial efforts on developing the Lower Eagle Ford. Now let’s turn to Slide 5 to talk about our preliminary 2018 development plans. We know everyone wants more details on how we plan to develop the Devon assets. However, as I mentioned earlier, we need to do some additional land work to put the PSAs together so that we have the ability to drill some of the 40-plus extended reach laterals. As such, today, I will talk generally about our plans for 2018 rather than focus on specific locations. In Area 1, we plan to keep one rig active for the entire year. We expect to drill between 22 and 25 gross wells where we will have a working interest of approximately 45% to 55%. We also plan to keep one rig active in Area 2 for the entire year, drilling approximately 15 wells in Devon North, Devon South and legacy Penn Virginia acreage. Our current thinking is that the rig will initially be focused on locations in Devon North and legacy Penn Virginia acreage, and then move to the Devon South acreage. Some of these wells are anticipated to be drilled at lateral lengths of greater than 8,000 feet. I’ll now turn it over to Steve to give you some color on the finance side.

[Steve Hartman:]

Okay. Thanks, John. I’ll start with an overview of our second quarter financials on Slide 6. This is a third quarter in a row where we generally met or beat our guidance numbers, and we’re excited about our progress. Total production revenues for the quarter were $36.3 million or $39.24 per BOE, with 89% of the product revenues derived from oil sales. This was a 4% increase over the first quarter, primarily driven by 8% higher production, partially offset by lower commodity prices. In the prior quarter, our product revenues on a per unit basis were $40.63 per BOE. Total direct operating expenses were $12.9 million for the quarter or $13.96 per BOE, which is a 1% increase over the prior quarter in total, but a 6% decrease on a per BOE basis. The per BOE basis declined, being primarily driven by higher production and lower G&A, partially offset by higher LOE. The increase in LOE is mostly timing related and primarily the result of a long-term maintenance project on some older tank batteries and heater treaters getting completed faster than we had anticipated. We expect to see LOE drop when that project is completed later this year. Operating income was $11.4 million, which is a slight decrease over the previous quarter, primarily as a result of higher DD&A. We reported $21.3 million in net income for the quarter or $1.42 per diluted share, compared to $28.1 million or $1.87 per diluted share in the prior quarter. The primary driver for the lower net income, besides slightly lower operating income, is a $7 million lower recognized gain on derivatives for the quarter compared to the prior quarter. And this mostly reflects noncash changes in the fair value of our hedge portfolio between quarters. Finally, Adjusted EBITDAX, which is a non-GAAP measure reconciled in the appendix of our presentation, increased 15% to $23.1 million, up from $20.1 million in the prior quarter, primarily due to increased production volumes, lower direct operating expenses on a per BOE basis and lower cash settlement payments on derivatives, partially offset by lower commodity prices. Adjusted EBITDAX which includes cash settlements from derivatives, we paid $500,000 in cash settlements for derivatives during the quarter compared to $2 million in cash derivative payments in the prior quarter. On the next slide, Slide 7, we highlight our liquidity position. At the end of the quarter, we had $37 million drawn on our $200 million credit facility, $800,000 outstanding in issued letters of credit and $10.1 million in cash, giving us liquidity of approximately $172 million. As of this last Friday, August 4, we had $47 million drawn on the credit facility and $6 million in cash, giving us approximately $158 million in liquidity. Turning to the acquisition financing that John mentioned, we expect to finance the recently announced acquisition from Devon with $150 million of new committed debt financing, with the balance of the transaction, estimated at around $40 million, being financed with the credit facility. And we are in the process of syndicating this new debt right now so we can’t go into any of the specifics at this time, but we will update on the terms and other details of the financing as soon as we can. And looking over on the right of the slide, you can see our estimate for liquidity pro forma for the acquisition is approximately $132 million. This is shown as of the end of the second quarter, but it hasn’t changed much as of today. The $10 million we borrowed on the credit facility since quarter-end was for a transaction-related deposit, so that would be included in the $40 million estimate to be financed on the credit facility. I also want to highlight the liquidity estimate does not include a change in our borrowing base. We are in discussions now with our bank group to further amend and increase our borrowing base beyond the current $200 million commitment level to take into account the acquired PDP reserves and our drilling activity since our spring redetermination, which would include the Lager 3H and the Zebra wells. We expect a meaningful increase to the borrowing base, which would improve our liquidity beyond the level shown on the slide, but it’s too early to speculate how much more we would expect the pro forma borrowing base to be. I also want to note, we are solidly focused on ensuring we maintain a healthy balance sheet and ample liquidity. We are targeting a leverage ratio of net debt to adjusted EBITDAX of 1.5x or below, and we believe that that’s achievable by the end of 2018. On the next slide, Slide 8, we update our full year 2017 guidance as well as our production expectations for 2018. Guidance for both years has been increased to reflect the closing of the Devon deal on September 30. We currently expect third quarter 2017 production, which does not include any contribution from the acquisition, to be down slightly from the second quarter due to a 1-month delay in bringing on the 8-well super pad. As such, we are now expecting third quarter production to be 9,200 to 9,600 BOE per day. For the 2017 full year, we are projecting production of 10,600 to 11,200 BOE per day and a fourth quarter exit rate of 14,600 to 15,200 BOE per day. This reflects a 57% to 63% increase as compared to our fourth quarter 2016 exit rate, which was approximately 9,300 BOE per day. Looking to 2018, we’re expecting a full year production rate of 20,000 to 22,000 BOE per day and a fourth quarter 2018 exit rate of 21,000 to 23,000 BOE per day. This equates to about a 45% to 50% growth rate as compared to the 2017 projected fourth quarter exit rate. Moving down the slide, we are not changing our realized price differentials guidance. For direct operating expenses, we are lowering guidance for cash G&A to $12 million to $14 million for 2017, down from previous guidance levels of $13 million to $16 million. Using the midpoint of 2017 production guidance, we would expect cash G&A to be around $3.25 to $3.50 per BOE. We’re not giving formal 2018 expense guidance at this point, but with the extra volumes coming online from the acquisition and the added scale, we would expect G&A to be below $3 per BOE for the coming year. For LOE, we kept guidance unchanged at $5 to $5.50 per BOE. And looking into 2018, we would expect LOE to be sub-$5 per BOE given the scale. For gathering, processing and transportation expense, we kept that rate unchanged as well and expect it to continue at roughly the same level in 2018. We lowered guidance for ad valorem and production taxes to a range of 5.75% to 6.25% of product revenues. So altogether, we expect our cash direct operating expenses on a per unit basis, excluding ad valorem and production taxes, which depend on product pricing, to be around $11 to $12 per BOE in 2017 and likely sub-$11 per BOE in 2018. For capital, we are expecting a $20 million increase from previous guidance in 2017, with a new guidance range of $140 million to $160 million, with 90% directed to drilling and completion operations in Eagle Ford. The increase is mostly related to a higher working, interest in the fourth quarter related the acquisition. For 2018, with a 2-rig program, we would expect capital to be $220 million to $240 million, again, with about 90% directed towards drilling and completions. And one thing I’d like to highlight on guidance, we are seeing slightly higher drilling and completion cost, especially on the completion side. We are raising the average cost of an Area 1 6,000-foot lateral with Gen 3 well design to $5 million to $5.2 million. That’s up from the $4.8 million to $5 million cost in our previous guidance. This is the design of our current type curve is based on. Gen 4 design, which would have 6 more stages and higher proppant, levels, would be around $5.3 million to $5.7 million or around $300,000 to $500,000 more per well for the same lateral length. And this is the well design we have been testing for the last several pads and are still evaluating. The well costs we provided last week for Area 2 development on the newly acquired acreage already considered the higher completion cost. On the next slide, Slide 9, we highlight our hedge position. We recently added hedges on the 1,000 barrels per day of oil production for 2018 at a swap price of $50.34 per barrel. So as a result, we currently have 4,408 barrels of oil per day hedged for 2017 at $48.62, 4,476 barrels of oil per day hedged for 2018 at $49.37 and 2,916 barrels of oil per day hedged for 2019 at $49.90. We do not have any natural gas or NGL volumes hedged at this time, and we do expect to add hedges after we closed the acquisition. And Jonathan, with that, I think we can go to Q&A.

[Operator:]

[Operator Instructions] Our first question comes from the line of Jeff Grampp from Northland Capital. Your question please.

[Jeff Grampp:]

First on the upside, and particularly Zebra wells which look pretty impressive in Area 1, just generally with the Gen 4 wells, I’m curious how much data you guys think you need to come out with a Gen 4 type of Area 1 type curve? Is it more, I guess, history with the existing wells? Is it rolling out more tests across the acreage? Or just generally, how you guys are thinking about potentially revising type curves from a timing standpoint?

[John Brooks:]

Well, we’ll be really careful about changing any type curves. I think the Gen 4 that you mentioned that we’ve attempted has had – well, we had some real good results on it. So we’ve really got to measure the additional cost we see with the production response. And I think what we’re seeing is it’s different across the field in some areas. Zebra, actually, we were targeting 3,000 pounds per foot. So we went even further than our Gen 4 design, and that seem to work really well. It has a lot to do with the pressure response of the rock where we’re at. With those added volumes of proppant goes a lot more volume of water. And the higher pressured rock seems to handle the additional water volumes sometimes better than the lower pressured rock. So we haven’t changed our type curve in a while, and we’ll probably be very careful about doing that going forward. In the meantime, I think we’ve got a lot of good repeatable results that converge on a fairly tight distribution around the type curve. And probably, any other additional type curve information that we see coming will probably be focused on Area 2.

[Jeff Grampp:]

Okay. Okay. That’s helpful. And I guess transitioning to Area 2, with the Schacherl, these 2 wells that you guys are going to spud here next quarter, should we expect, I guess, a similar completion recipe to the Lager? And can you just remind us what the planned lateral lengths are on the Schacherl wells?

[John Brooks:]

I don’t really have the actual lateral length of those wells in front of me, but I think they’re probably going to be real close to our average of 6,000 foot. The idea would be to go and treat those wells with something similar to the Lager, which we were targeting at 2,500 pounds per foot.

[Jeff Grampp:]

Okay. Great. And the last one for me, maybe for Steve, on the LOE side, I know you guys are kind of tracking above the guidance range for first half and just kind of, I guess, expectations for second half given that volumes are going to be down sequentially in 3Q, and I guess I’d imagine that the Devon barrels are maybe a little bit higher costs coming on in 4Q. So just, I guess, can you maybe help us understand how the LOE trajectory we should expect in the back half?

[Steve Hartman:]

Sure. We actually do – we think that we’re going to land within the guidance zone of the $5 to $5.50. So yes, we were a little higher this quarter than we would have expected, but like I alluded to in the comments, we’re just way ahead of schedule on some planned maintenance for the year, so we have that mostly done. So it was timing related. I would expect that that’s going to finish very soon, maybe in the third quarter. And even though we’re having some slightly lower volumes in the third quarter, we expect LOE to be coming down as well. And then, of course, when the volumes come on with Devon in the fourth quarter, we expect the scale will outweigh any kind of cost. And so we feel very confident we’re going to land within that $5 to $5.50 range for the full year, so it’s coming down.

[Jeff Grampp:]

Okay, perfect. Very helpful.

[Operator:]

Thank you. Our next question comes from the line of Richard Tullis from Capital One Securities. Your question please.

[Richard Tullis:]

Good morning and congrats on a nice quarter there. John, looking at the Upper Eagle Ford and the Austin Chalk, I know you have the acquisition to work through now, but how do you see testing those zones perhaps using the current completion method as we go – move into 2018?

[John Brooks:]

Well, we’re currently testing 2 Upper Eagle Ford completions on our super pad. Those are 2 4-well pads that are adjacent and each one of those has an Upper Eagle Ford completion in them and they are offset by a Lower Eagle Ford completion. And in both instances, for both pads, they’ll be traced and we’ll be able to evaluate any contribution or crosstalk between the 2 formations. That’s in an area where we’ve had some success in the past in the Upper Eagle Ford, so we’re excited to see what these will do with a slickwater completion. In terms of the Austin Chalk, that’s probably third on the list of things that we’re going to focus on. Obviously, being the Lower Eagle Ford and the Upper Eagle Ford and then the Chalk, but the Upper Eagle Ford we do intend to test in the near future as well as probably into 2018 as well. And it will probably be in a co-development phase where we’ll stack and stagger it next to another one.

[Richard Tullis:]

Okay. That’s helpful, John. And I realize the 2-rig program provides significant growth in 2018. What levers are you looking at to possibly add a third rig as we go forward?

[John Brooks:]

Well, I think, number one, commodity prices will have an impact on that and the focus is try to remain within our cash flow to the extent that we can and exercise some capital discipline and maintain the balance sheet objectives that Steve delineated in a higher-priced environment. The third rig starts to really look attractive, but we still want to maintain our turn on – our focus on returns.

[Richard Tullis:]

Okay, that’s helpful for me John. Thank you.

[Operator:]

Thank you. [Operator Instructions] And this does conclude the question-and-answer session of today’s program. I’d like to hand the program back to John Brooks for any further remarks.

[John Brooks:]

Thanks, Jonathan. In conclusion, we had another solid quarter in the strategic, accretive bolt-on acquisition of Devon’s Lavaca County Eagle Ford assets, it increases our production by 30% and provides an inventory of undeveloped locations with high working interest, the potential for extended reach laterals, and an area where we can further extend our successful slickwater completions. The acquisition of the Devon acreage allows us to continue enhancing the economics of our drilling inventory significantly extending our runway of resource development and offering many years of organic production growth, which we believe will allow us to generate peer-leading returns for our shareholders. Again, thank you for taking the time to join us this morning.

[Operator:]

Thank you, ladies and gentlemen, for your participation in today’s conference. This does conclude the program. You may now disconnect. Good day.