Goodrich Petroleum Corporation
Q3 2017 Earnings Call Transcript

Published: 11 Nov 2017

[Operator:]

Good morning and welcome to the Goodrich Petroleum Corporation Third Quarter 2017 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation there’ll be an opportunity to ask questions. [Operator Instructions] Please also note that today’s event is being recorded. I would now like to turn the conference over to Mr. Gil Goodrich, Chairman and CEO. Please go ahead.

[Gil Goodrich:]

Thank you very much, and good morning to everyone. Thank you for joining us this morning as we are very pleased to have an opportunity to present and share with you our third quarter results. We prepared a slide presentation in conjunction with this call this morning and we would invite you to follow along with the slide deck as we go through our prepared remarks. You can access the slide presentation on our website entitled Management Presentation and Haynesville Shale Overview 3Q17 Earnings Call. Our standard disclaimer, forward-looking statements and risk factors are highlighted for you on Slide 2 of the presentation. Before reviewing the quarterly presentation, I would like to share a few highlights with you of the quarter. We believe the third quarter results further illustrate the quality of the new Haynesville Shale play, which has also been highlighted by other operators drilling longer, lateral and high-profit Haynesville wells, as well as our strategy of achieving excellent growth while maintaining a solid balance sheet with low debt metrics. Through the first nine months of the year, we believe we have achieved top-tier capital efficiency defined as production, additions, dollar of capital expenditure. Our capital expenditures for the first three quarters has largely been funded by our growing cash flow as we entered the year with $38 million of cash and exited the third quarter with approximately $32 million of cash with no incremental borrowings. In addition, we believe the third quarter results illustrate the future potential of our Haynesville focus strategy, which is production volume growth, declining per unit operating expenses and significant cash margin expansion. If you’ll now turn to Slide 3. You’ll see our company overview, which highlights our 20-plus year inventory of drilling locations in the core of the Haynesville Shale in Northwest Louisiana, as well as our current listing on the NYSE American under the symbol GDP. As most of you are aware, we have seen tremendous results in the Haynesville for multiple operators as the play has transitioned to longer laterals of 7,500 to 10,000 feet and increased profit loadings from 2,500 pounds to 5,000 pounds per foot of lateral. This transformation has once again made the Haynesville Shale one of, if not, the top natural gas play in the United States, particularly when factoring in the geographic location, pipeline and infrastructure capacity and deliverability of gas to the Gulf Coast industrial complex and LNG export facilities. As a result, effectively 100% of our capital expenditures are earmarked for the Haynesville development and we have recently revised our full-year capital expenditure estimate back up to a range of $40 million to $50 million to accommodate four additional gross nonoperated wells with modest working interest, which we expect to spud in the fourth quarter of this year and be completed in early 2018. Our plans for the fourth quarter also call for three operated Haynesville wells to be completed prior to year-end. We have slightly revised the timing of those completions to allow us to complete them back-to-back and we reaffirm our estimated exit rate of 55 to 60 million cubic feet of gas per day, albeit the exact date of the first production from the two well pad could slip into the first week of January. Moving to Slide 4. During the third quarter, we incurred capital expenditures of $5.4 million and $25.8 million through the first nine months. Production grew by 11% sequentially over the second quarter to approximately 40 million cubic feet of gas equivalent per day and is projected to further accelerate as we enter 2018 with the addition of the three operated completions prior to year-end. As I mentioned a moment ago, with growing production volumes in both absolute and per unit operating cost improvement, we are seeing meaningful margin expansion with third quarter pro forma adjusted EBITDA up significantly over the second quarter at $8.8 million and net income of approximately 700,000. The balance sheet remains in very good shape with approximately 32 million of cash at the end of the quarter and just 30 million of net debt. Slide 5 provides a quick look at recent developments and current operating activity. We have drilled and cased our Franks 1H well, which is a 10,000 foot lateral and we are currently waiting on completion which we expect to begin in a few weeks. We are currently drilling a two well pad, the Wurtsbaugh 2H and 3H wells, which are both planned to starting -- excuse me, a 7,500 foot laterals and we’ll be zipper frac immediately following the completion of the Franks well. In addition, we will be moving a rig next week to another two well pad to drill two planned 10,000 foot laterals on our Cason-Dickson unit in the Thorn Lake area. Both of these wells are expected to be flat in the first quarter of next year. We are continuing to look for opportunities to bolt-on, expand or enhance the value of our acreage position in Northwest Louisiana. And as we previously announced, we recently completed a second acreage swap, which allowed us to consolidate acreage and several cost units, increased the number of operated wells to be drilled in our inventory and added over 25 Bcf of proved undeveloped reserves pro forma to year-end 2016. On Slide 6, we illustrate the production growth we’ve experienced over the last couple of quarters, as well as the expected rate as we enter 2018 with the addition of the three wells to be completed by year-end, as well as you can see the huge impact from the Haynesville Shale volume growth. If you turn to Slide 7, you will see our current commodity price hedging summary where we have significantly increased our natural gas hedge position in 2018 with swaps just over $3 per Mcf and initiated a hedge position for 2019. We also recently added some NYMEX crude oil swaps through 2019 in excess of $51 per barrel. In addition, essentially all of our physical crude oil production is currently being sold at approximately $2 off of LLS, which is currently trading at approximately $63 per barrel. I’ll now turn the call to Rob Turnham for a more detailed review of the quarter and our current activity.

[Rob Turnham:]

Thanks, Gil. Our revenues for the quarter of $13.2 million were generated from an average realized price of $3.54 per Mcf equivalent comprised of $2.96 per Mcf from $47.85 per barrel of oil. When including our hedges, our average realized price was $3.59 comprised of $3.01 per Mcf and $47.85 per barrel, and 74% of our revenue was attributed to natural gas production. Our per unit operating expenses continue to march lower, primarily driven by incremental production from low lifting cost Haynesville wells. LOE was $2.2 million for the quarter or $0.60 per Mcf equivalent versus $3 million or $0.89 per Mcf equivalent in the prior quarter. LOE for the quarter included $0.2 million or $0.05 per Mcfe for workovers. LOE excluding workovers was $2 million or $0.55 per Mcf equivalent versus $2.2 million or $0.67 per Mcfe in the prior quarter. Per unit LOE is expected to continue to fall as new Haynesville wells are added, as these wells carry very low lease operating expense per unit of production. Production and other taxes included refunds for both severance and ad valorem taxes, which resulted in a small credit in the quarter versus $0.4 million of expense or $0.13 per Mcfe in the prior quarter. Haynesville wells drilled in North Louisiana have severance tax abatement until the earlier of payout or two years and therefore the company’s production and other taxes per unit of production is expected to remain low in the near term as new Haynesville wells were added. Transportation and processing expense was $1.6 million in the quarter or $0.44 per Mcf equivalent versus $1.9 million or $0.57 per Mcfe in the prior quarter. We expect per unit transportation and processing expense to also continue to fall as we had operated Haynesville production, which carries a lower rate. DD&A expense was $3.5 million in the quarter or $0.96 per Mcfe versus $3.1 million or $0.93 per Mcfe in the prior quarter. G&A was $3.7 million in the quarter, which includes $1 million of stock-based compensation and the accrual $0.7 million for potential performance bonuses and $0.1 million in noncash amortization of office rent. G&A payable in cash for the quarter was $1.9 million or $0.51 per Mcf equivalent. G&A for the prior quarter was $3.8 million, of which $2 million or $0.59 per Mcfe was cash G&A. The company expects cash G&A per unit of production to continue to decrease with significant growth in production volumes while keeping overall cash G&A in line. Operating income defined as revenues minus operating expenses totaled $2.2 million in the quarter versus $0.4 million in the prior quarter. Interest expense totaled $2.5 million in the quarter, which includes cash interest of $0.4 million incurred in the company’s first lien term loan and noncash interest of $2.1 million incurred in the company’s second lien notes, which includes $1.4 million paid in-kind interest and $0. 7 million amortization of debt discount. Interest income and other was a credit of $1.3 million in the quarter, primarily related to the receipt of cash that had been held in escrow related to an asset sale, which occurred in a prior period. Moving back to our slide deck. Slide eight shows our properties where we retain approximately 50,000 gross, 26,000 net acres in the Haynesville. 102,000 gross, 71,000 net acres in the TMS and 32,000 gross, 14,000 net acres in the Eagle Ford. Slide 9 breaks out our acreage position for the Haynesville where the vast majority of our capital plans this year will be spent in the North Louisiana core positions. In North Louisiana, where we have drilled and completed 89 wells to date, we have an average working interest of approximately 40% with approximately 250 gross, 100 net locations in inventory. Approximately half of the locations are capable of 10,000 foot laterals, with the remaining half split between 4,600 and 7,500 foot laterals. We have gridded our acreage with the plan to maximize long laterals and expect to be in a position to swap acreage or drilled joint wells with offset operators to further increase our long lateral inventory. We’ve announced a couple of swaps during the second and third quarters that have added long lateral in operating locations as well as approximately 47 Bcf of pro forma proved reserves based on our year-end ‘16 reserve report. We are hopeful of continuing with these swaps and bolt-on acquisitions, which can be beneficial for both parties. We estimate approximately 1.2 Tcf of reserve exposure at 2.5 Bcf per 1,000 feet of lateral in North Louisiana of loan, of which we operate approximately 50%. In addition, although we are currently focused on Angelina River Trend acreage, an offset operator has been making exceptional wells directly offsetting our acreage, which validates our analysis, but the quality of the Haynesville is as good at Angelina River as it is on our core North Louisiana acreage. We’ve updated Slide 10 that show certain recent activity in our 2-well pad at Thorn Lake in Red River Parish, Cason-Dickson wells which Gil mentioned earlier, where we have an estimated 79% working interest, 51% net revenue interest and two 10,000 foot wells planned to be spud later this month and completed in the first quarter of 2018. We have developed type curves for each of the 4,600, 7,500 and 10,000 foot laterals as shown on Slides 11 through 13. Our type curves are based off of 2.5 Bcf per 1,000 feet of lateral and our results are exceeding our high case type curve. We continue to believe that the main drivers of superior well results, proppant concentration, lateral length, stage and cluster spacing, fluid design, pump rates and pressure maintenance programs designed to minimize drawdown. We and other operators in the play believe pressure maintenance with conservative choke sizes can flatten the curves and minimize drawdown and we expect to see very good long-term recoveries on this strategy. No 2 wells better exemplify the effects of reduced chokes than the 2 Angelina River Trend or ART wells offsetting our acreage as shown on Slide 12. For those 2 wells, the operator was extremely conservative on the choke sizes, which allow the fractures to heal and remain open and flatten the curves. Although cash flow from this strategy is impacted, we continue to monitor performance in order to determine optimal flowback procedures. Our economics, as shown on Slide 14 through 16, show very competitive internal rates of return at $3 gas for all 3 lateral lengths at our type curves, ranging from 53% for short laterals to 76% for our longer laterals. These economics are run in our 2.5 Bcf per 1,000 foot curve and [blended average gathering fee and bases] of $0.60 off of NYMEX. As seen in our third quarter financials, our operated activity carries better FX than $0.60 and our production is outperforming our curves, which generates higher rates of return than shown on our slides. Our capital efficiency in full cycle returns in the Haynesville are second to none as compared to other basins and you will continue to see meaningful growth in volumes, a continuing expansion of our cash margin and significant growth in EBITDA in 2018. We believe we can deliver these results for our shareholders from a drilling plan that lives within our means with very low outspend, provides increasing liquidity from a growing borrowing days and allows the company to maintain very low debt metrics, as exhibited in the third quarter where we were less than one times net debt to annualized third quarter EBITDA. With that, I’ll turn it back to the operator for Q&A.

[Operator:]

Thank you. We’ll now begin the question-and-answer session. [Operator Instructions] Our first question comes from Neal Dingmann of SunTrust. Please go ahead.

[Neal Dingmann:]

Gil and Rob, you’ve been real successful on the acreage swaps and trades, I’m just wondering, when you look at the position including the JV with Chesapeake, is there opportunities for more of this in the near term?

[Rob Turnham:]

Yes, Neal. Certainly hope so. It makes a lot of sense for both parties to, in essence, get out of each other’s hair and expand the working interest in wells that you already operate or certainly block off areas where you can add to your long laterals, and for us carry a lower gathering cost from our operated activity. So we’re hopeful. We have a very good dialog with Chesapeake. We continue to discuss our best to develop the acreage and so nothing definitive as we see here right now, but we’re hopeful.

[Neal Dingmann:]

And then on same from, for up for you, Gil, just the last question I had, in mindful, you don’t have full ‘18 guidance out yet. You changed the plan obviously for the more economical doing the completion sort of back-to-back and you potentially see that as being the plan next year. I’m just trying to get a sense of cadence in general, is it going to be more one well pads or just when you see the overall plan next year, how do you think that will play out?

[Gil Goodrich:]

We plan actually to drill as many to two-well pads as possible, I don’t have the exact preliminary planning in front of us, but I think a majority of the wells we would drill next year, Neal, would be two-well pads. There’s just too much cost savings with the efficiency of getting a lot of pad and drilling two wells back to back, you cut and mobs in and out down and swapping out from a water-based mud system to an oil-based one time that saves a couple of days and some incremental costs, and then of course, you get significant efficiencies from coming and fracking two wells in a zipper style. So we’re going to drill as many two-well pads as we can. There will be a few places where we’ll probably end up with some single one-offs, but for the most part, you can look for us to be drilling two-well pads next year.

[Operator:]

Our next question comes from Mike Kelly of Seaport Global. Please go ahead.

[Mike Kelly:]

Shifting with 2018, I’m not asking for guidance here, but would be hopeful if you can give us a glimpse in just what approach -- the general approach will be in 2018, maybe just give us a look at kind of high level strategy and so objectives that you might have set as you push next year?

[Gil Goodrich:]

This is Gil. Look, we’re delighted with the progress we’ve made so far in 2017. We will be meeting with our board in December to review and set the preliminary plans for next year. But given the exit rate and production rates we enter next year in addition to the margin expansion that both Rob and I’ve mentioned and the enhanced hedge position, our expectation is that we will be able to increase capital expenditures for 2018 over 2017, continue the rate of growth that you’ve seen so far and be able to do all of that with limited to no incremental borrowings under our revolver as we get into 2018. So we’ll set that in December, we’ll put out a press release that kind of outlines our 2018 plans. But you can expect us to be a little bit more aggressive next year than we were this year.

[Mike Kelly:]

And if I’m looking at Slide 12, those two offset Angelina River Trend wells do look fairly phenomenal. So can you give us maybe a little bit more color on that, what you saw there, little more profit it looks like, but anything else from the approach of that operator? And then just the logical follow up there is that, have you thinking about maybe test in your acreage down there in ‘18?

[Rob Turnham:]

This is Rob. Thanks for that question. Yes, the results are pretty phenomenal. We were concerned a little bit early on because the choke sizes were very small, but obviously that operator had a plan to minimize crushing or closures of the fractures, let them heal and then gradually open the choke. You can’t argue with the curve, you do forfeit some cash flow in your first 4 months or so that based on how we’re flowing our wells back, our rates are certainly higher than that in the early time. And so we need a little more time to see how that curve shapes out over time just to be able to kind of more accurately portray what the cash flow might look like as well as the EUR. For us, it’s all about returns and generating higher PV-10, high cash flows and you want to obviously be conservative, but what drives the growth of our business, what drives us going forward is generating higher and higher cash flows. So we just need a little bit more time to monitor those results. As to activity in 2018, all of our acreage in the Angelina River Trend is held by production with basically becoming the donut hole in the middle of offset activities and all of our plans in 2018 are still going to be centered around North Louisiana. It’s more shallow there. Therefore, we think it’s a couple of million dollars less expensive to drill and complete wells in North Louisiana. So we’re actually mapping that out as Gil said for our December board meeting, but you can see more of the same with a little more capital intensity.

[Operator:]

Our next question comes from Jeff Grampp of Northland Capital Markets. Please go ahead.

[Jeff Grampp:]

You mentioned next year moving to more two well pad on a more recurring basis, kind of wondering how we should maybe think about cycle times changing as a result of that I think in your type curves, you guys have kind of a 60 days, spud to sales, and just trying to get a better handle on how that evolves with the pad drilling?

[Gil Goodrich:]

This is Gil. We’ve made no change yet in that. I think the real question is securing the frac crews and completions in order to maximize efficiency as we just done here with these last few wells could cause things to move around a little bit. But we’ve not made any wholesale change to the overall plan and we are expecting and hoping, frankly, that we’re going to see a little bit more flexibility and capacity for securing those days out in front of ourselves that should keep that pretty much on schedule.

[Rob Turnham:]

And so and this is Rob. I might just add, Jeff, that obviously you’re drilling two wells instead of 1, so in essence, kind of 60 days of drill time for both wells, you got to do it a little bit quicker than that because as Gil described earlier, you’re walking the rig and able to enjoy a lot of efficiencies there. So if you look at 60 days, you’re really looking at 90 to 100-day spud to completion for two wells instead of 60 days spud to sales over the line.

[Jeff Grampp:]

And then just on these upcoming batch of wells here, and you guys as well as other operators have kind of tweet between it seems like four to five kind of seems to be the honey spot there. Just kind of wondering if you guys are leaning one way or the other, it seems like the shorter lateral 5,000 pound well you guys had the real strong performers, so just wondering if you guys are kind of narrowing in on either end of that spectrum?

[Gil Goodrich:]

Yes, that’s a great question, Jeff. This is Gil. We are monitoring that very closely. You probably just saw Chesapeake announced a series of wells in their 3Q earnings that were all 2,600, 2,700 pounds per foot, which is obviously considerably lower than what we’ve seen in the past. The wells that Rob was talking about a second ago at Angelina River are again about 2,700 pounds per foot. So we’re trying to figure out thus perhaps tightening up the spacing a little bit, but backing off the profit end up saving you a little bit of money in delivering the same type results. I think it’s still an open question. That being said, we are planning on 4,000 pounds plus on these upcoming wells that we’re going to frac between now and the end of the year.

[Operator:]

Our next question comes from Kevin MacCurdy of Heikkinen Energy Advisors.

[Kevin MacCurdy:]

Just a couple of modeling questions. Slide 17 shows four wells completed -- to be completed in 1Q ‘18. Are those operated or non-op wells and what’s the working interest on those?

[Rob Turnham:]

I may have to get back to you, Kevin, offline, but it’s actually -- it’s probably going to be six wells instead of four. We’ve had four non-operated well proposals come in the door over the last 30 days, all of which obviously caused our CapEx budget to go back up by the midpoint of about $5 million. All four of those wells are scheduled to be completed in the first quarter. So basically, call it a half of the net well -- four gross the half of the net well. But we’re also scheduled to frac the two Cason-Dickson wells in the first quarter and that’s, as I said, are about 79% working interest, 51% net revenue interest. So I think we should have probably updated this Slide 17 to state six additional long lateral wells completed in first quarter.

[Kevin MacCurdy:]

And I know it’s early for ‘18, but do you guys have a general idea of what the non-op program will look like or at least how you think it will all unfold?

[Rob Turnham:]

We obviously are talking to Chesapeake regularly. We are expecting as many as 6 nonoperated gross wells, again our interest will be less than 50% in those wells, and those I think our scheduled kind of mid-year --middle of second quarter 1, call it June 1, and we don’t know about other offset operators. For example, 2 of the wells that we just received well proposals are from Covey Park on our kind of southeastern side of our Bethany Longstreet acreage. So we’re trying to get a handle with all of the offset operators as to what their plans are. But the vast majority of our activity, if we continue to run 1 rig, is going to be operated, and so I think if you look at the metrics going forward, that’s why we’re confident that you’re still going to see improvement on our per unit costs across the board, just because of a majority of the activity being operated.

[Kevin MacCurdy:]

So it sounds like we could see some front-end weighted growth for next year, is that right?

[Rob Turnham:]

I think that’s right. In fact, we had a call earlier today by pushing the peak exit rate to right at the end of the year or perhaps slightly in the January that causes those 3 wells to produce more in the first quarter than they would have had they come online 2 to 3 weeks earlier. So clearly you’re just kind of shelving some of that production into the first quarter and then we clearly have 4 additional wells that weren’t in our original thought or budget that are nonoperated that are going to be completed in the first quarter that perhaps needs to be baked into your [end-year modeling].

[Operator:]

[Operator Instructions] Our next question comes from David Beard of Coker & Palmer.

[David Beard:]

Nice progress on the cost. My questions are related to the cadence of drilling and they have been answered. So, I appreciate it.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Gil Goodrich for any closing remarks.

[Gil Goodrich:]

Thank you very much. We appreciate everyone’s attendance and participation this morning, and now we look forward to reviewing the fourth quarter and year results with you early in 2018. Thank you.

[Operator:]

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.