Q1 2021 Goodrich Petroleum Corp Earnings Call
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Good morning, the Goodrich petroleum call will start momentarily I repeat the call we'll start momentarily. Thank you for your patience.
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Good day and welcome to the Goodrich Petroleum first quarter 2000 on 'twenty One earnings conference call. All participants will be in a listen only mode should you need assistance. Please signal conference specialist by pressing the star key followed by zero. After today's presentation there'll be an opportunity to ask question to ask a question you May press.
Star then one on your Touchtone phone and to withdraw your question. Please press Star then two please note. This event is being recorded I would now like to turn the conference over to Gil Goodrich Chairman and CEO. Please go ahead Sir.
Thank you and good morning, everyone. Thank you for participating in our first quarter 2021 earnings call I'll start by introducing the other cash with team members here with me, Rob turn on our President.
And Christian Mcwaters, Senior Vice President and Chief Financial Officer.
While the first quarter was somewhat impacted by the February storm in Texas and Louisiana.
And some curtailment of non op volumes, we nevertheless delivered solid first quarter EBITDA of $23 million.
In addition, numerous new well additions late in the first quarter and subsequent to the end of the quarter, how about is very well positioned to deliver strong results into Q.
Included in the recent new wells added to production is our Goodrich operated Latin three and 34, H, one and approximate 10000 foot lateral located in Caddo in Desoto parish, Louisiana.
A lot in well located northeast of our Bethany Longstreet field, and what we call the wallets Lake area.
Latin one H is our first well on this area and in which we have a 76% working interest and is flowing at a sustained rate of 35 million cubic feet of gas a day on a 30 to 64 cents joke and 7700 pounds of flowing pressure.
This is certainly one of if not the best well we've ever drilled and we're currently making plans for further development in this area in early 2022.
We've again prepared a slide deck and we invite you to follow the slide deck. During our prepared remarks, you can access the slide presentation on the Goodrich petroleum website entitled <unk> 2021 earnings presentation.
I will now turn to the presentation for those of you who would like to follow along and our standard disclaimer forward looking statements and risk factors are highlighted for you on slide two.
On slide three we again provide specific data regarding our environmental social and governance statistics. Our objective is zero gas flaring and we essentially achieved that goal in 2020.
We believe we have a very high quality and significantly diverse workforce of which we are very proud of.
And with 75% of our board being independent we believe we provide excellent governance and oversight for our shareholders.
We plan to continue to share this information with you as well as do you update and refine as conditions and best practices evolve overtime.
On slide four you will see an overview of the company.
With the 4000 net acres, we added last year in the core of the Haynesville through bolt on and drill to earn transactions. We have increased our core acreage position to approximately 26000 net acres and increased our core inventory to over 12 years at our current pace of development.
Our SEC proved reserves are reflective of the SEC's five year rule in our capital forecast, we believe the total natural gas resource potential, including pre reserve proved reserves in our core area is in excess of 1.8 Tcf.
While first quarter production averaged 125 million cubic feet of gas equivalents per day as I mentioned recent well additions had significantly increased production and we are providing a production guidance range for the second quarter of between 150, and 160 million cubic feet of gas.
Its equivalents per day.
And almost 25% sequential increase at the midpoint over the first quarter.
The core of the Haynesville continues to offer low development and lifting costs top tier cash margins and return on invested capital as well as the ability for us to both grow and deliver free cash flow at current commodity prices.
As I mentioned.
The shut ins from.
The storm as well as curtailments of non ACA not non op activity have caused us to slightly adjust our current forecast for full year guide of about 260 million cubic feet of gas per day equivalent at the midpoint, which will result in approximately 20% production growth year over year.
Versus 2020.
And at current Capex and natural gas prices should generate free cash flow in excess of $15 million.
Moving to slide five we show our year end 2020, SEC proved reserves of 543 Bcf equivalent.
Which of the present value, which has a present value using a range of $2 50 to $3 per Mcf, a $338 million to $485 million discounted at 10%.
With a current total enterprise value of approximately $260 million you can see that we are trading at a substantial discount to our current total proved reserve value.
On slide six we have updated our cap table as of the end of the first quarter.
As of the end of the quarter, we had approximately $87 million outstanding on our senior credit facility and an additional $30 million of senior excuse me a second lien Pik notes for a total debt of $117 million.
At the end of the quarter net debt to EBITDA on a trailing 12 month basis was 176 times, but dropped to just 1.44 times when annualized on the first quarter EBITDA.
We continue to forecast year in 2020 net debt to EBITDA of approximately 1.0.
On slide seven we provide a chart of our historical production growth, which includes the forecast at the midpoint of 2021 production guidance of 160 million cubic feet of gas equivalents per day, a level of production that we could achieve in the second quarter. If results are at the high end.
Our <unk> guidance.
Moving to slide eight you will see our current commodity hedge position.
We currently have hedges in place covering 100 million cubic feet of gas per day for the balance of 2021.
Of this 70 million cubic feet per day, or approximately 44% of forecasted production at the midpoint is covered by swaps with a blended average price of $2 54 per Mcf and 30 million cubic feet of gas per day or 19% covered by Costless.
With a floor of $2 50, and a ceiling of $3.50 per Mcf.
The remaining 37% of projected production at the midpoint of our guidance remains unhedged.
We continue to watch the markets closely and expect to add to both the amount and tenure of our hedge position at the appropriate time.
Finally, we again provide details of our current 2021 guidance on slide nine where we continue to expect to drill 17 gross and nine five net haynesville wells by year end.
We estimate the blended average lateral length for 2021 will be approximately 7500 feet.
And this year's development will be predominantly operated activity.
For modeling purposes, we provided the expected cadence of completion activity along with our projected production and capital expenditures. In addition, we provide a range of expected cash cash cost per unit of production.
If you add up the midpoint of beach expected range you will see we are projecting total cash operating expenses of approximately 84 cents per M. Cfe as Rob where Australia in just a minute. This compares very favorably to our natural gas focused peers.
With an increasing production profile, a strong hedge position a constructive natural gas outlook and very high quality assets. We believe we are very well positioned to deliver on our plans and guidance for 2021 and with that I'll turn it over to Rob. Thanks Gil.
Revenues adjusted for cash settled derivatives totaled $31 2 million comprised of $31 $9 million of oil and natural gas revenues and.
$700000 of cash settled derivatives average realized price, including cash settled derivatives $2.77 per mcf for the quarter.
Our per unit cash operating expense, which is defined as operating expenses, excluding DD&A and noncash G&A was <unk> 99 per Mcf fee and cash interest expense was eight cents per mcf for a total of $1.07 per Mcf equivalent.
Cash margin, including interest expense was $1 17 per mcf fee or 61%.
Our realized price including settled derivatives.
As you will see in our slide deck and discuss later in my prepared remarks. Once we are able to analyze the first quarter financials for our peers. We expect this cash margin to be at or near the top of our natural gas peer group like we were in the fourth quarter.
As volumes grow throughout the year, we anticipate total cash unit costs, including interest to continue to decline as Gil said with the midpoint of guidance less on a dollar per mcf per day, including interest.
When combined with much higher gas prices robust cash margin expansion will drive significant EBITDA growth and free cash flow for the year.
As we stated previously our capital expenditure budget is a little front end loaded and varies by quarter due to completion timing with the first quarter higher than the average for the remainder of the quarters in the year.
Capital expenditures for the quarter totaling $29 3 million of which nearly all with drilling completion and facility cost associated with Haynesville wells.
During the quarter, we conducted drilling and completion operations on 14 gross six five net wells and added nine gross three three net wells to production.
For the year, we are maintaining our capital expenditure budget of $75 million to $85 million.
Interest expense totaled $1 9 million in the quarter, which included cash interest of $900000 incurred on the company's revolver and non cash interest of $1 million, primarily incurred on the company's convertible notes.
Turning back to our slide deck all of our activities remain in the core of the Haynesville beginning on slides 10 and 11.
We currently have 26000 net acres in the core of the play and continue to seek and review bolt on opportunities to expand our footprint through acquisitions and drill to earn farm outs and we believe you could see additional expansion of our footprint with this strategy.
Our acreage is currently approximately 75% undeveloped and 80% operated.
On slide 12, we show our inventory in North, Louisiana, which totals approximately 186 Tcf of reserve exposure, including 559 Bcf a day in proved reserves at year end at $2 50 gas price.
We have now quantified, we've not quantified or inventory at Angelina River or the Tms since all of our activities planned for North Louisiana currently.
Our PV 10 for year end proved reserves at $2 50 to $3 flat pricing of $338 million to $485 million is significantly over our current enterprise value as Gil stated earlier.
The activity map on slide 13 shows how consistent the play is in our area when drilling and completing wells in similar fashion.
For acreage is fully derisked and ring fenced with very good wells.
We're in development mode drilling predictable wells in proven areas and connecting wells into existing pipes with excess capacity.
The Latin well, which gill referenced before.
Had an IP 30.
24 of 35 million cubic feet per day, and as Gil said is located northeast of our Bethany Longstreet area on acreage, we acquired through a drill to earn farm out.
We continue to outperform our type curves on on slide 14, we track our short laterals versus 298 industry wells drilled nearby in the core.
Industry pumped on average of 2600 pounds per foot and as you can see our 10 wells are significantly outperforming the industry wells and our type curves.
10 wells shown in Green were stimulated with approximately 4000 pounds per foot of profit with tighter cluster and interval spacing and as we have said before regression analysis shows a very good correlation between proppant loading and cluster and interval spacing to EUR.
We expect our more recent wells to continue to pull up the composite curve over time from this optimization.
Slide 15 has a cumulative production curve shows over time, how we are outperforming our type curves.
Moving to slide 16, which reflects our 7500 foot curve, where we now show a composite of 207 industry wells with average proppant loading of approximately 2500 pounds per foot.
For the most part fits our two five Bcf per 1000 foot type curve initially, but then it falls off as the older wells that are under stimulated fall below the curve.
Like the short laterals on our more recent operated 7500 foot wells are materially outperforming our type curves.
Slide 17 again just shows how we are outperforming our type curves again on a cumulative basis.
Moving to slide 18, we track our 910000 foot laterals against the 187 industry wells drilled and completed in our areas as you will see we're for the most part tracking our type curve and industry, mainly because we have only recently completed wells with the newer completion designs.
We are optimistic with very early flow back time from our three recent wells, including the plant and Latin wells that we have the potential to outperform the 10000 foot curve over time like we have on the shorter lateral links.
And again slide 19, just tracks cumulative production relative to our type curves.
As we have stated before we believe our well performance speaks for itself and is driven by a number of factors one quality of our acreage in the core of the play to an optimum completion design, where proppant concentration fluid levels cluster and interval spacing and pump rates provide a material difference in results.
Net three flowback technique that minimizes daily drawdown flattens. The decline curves provides high recoveries of gas in place and most importantly maximizes returns.
We have seen very little service cost inflation to date and our economics as shown on slides 20 to 22 are as good as we have seen them in the basin.
The outperformance of our curves on the 4600 7500 foot laterals and service cost deflation across all wealth is created.
A unique situation where at a minimum of $2 50 gas price, we can generate approximately 100% or greater.
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As a reminder, the Haynesville economics are driven by high volume attractive net backs relative to Henry hub as compared to other gas basins low lifting costs and severance tax abatement until the earlier of two years or payout of the well.
Moving to slides 23, and 24, our cash cost per unit, including interest expense of $1.07. As is ranked second among our gas peers when compared to their fourth quarter results and our cash margin of $1 70, or 61% of our realized price will likely continue.
And you to rank at or near the top but we update for first quarter results from our peer group.
Our return on invested capital shown on slide 25 remains extremely attractive at 38%, which has us the number one ranked company out of our gas peers and if you will flip to slide 26, you will see we rank second on this return metric in the much larger larger 34 company peer group, which include.
<unk> the predominant oil companies utilizing fourth quarter results.
For 2021, when you bake and expected lower per unit cash costs in the forward gas curve, we anticipate our cash margin and return on invested capital to move even higher.
In summary.
Our team is executing well our balance sheet is in good shape with low debt metrics.
We are generating superior returns both in the field and at the corporate level and we continue to add to our inventory debt with very accretive bolt on acquisitions.
With this favorable backdrop.
One we look forward to sharing with you our results throughout the year.
And without I'll turn it over to the operator for Q&A.
Thank you we will now begin the question and answer session to ask a question you May Press Star then one on your Touchtone phone.
If youre using a speakerphone please pick up your handset before pressing on the key withdraw.
Withdraw your question. Please press Star then two and at this time, we'll pause momentarily to Nomura roster.
Okay.
And the first question will come from better trend on it with <unk> Securities. Please go ahead.
Good morning, guys.
I'm just not on that Latin well is it the little yellow dot middle of it.
Slide 13.
Area, that's where the well was the net and then how many locations do you think.
We're looking at the map so we'll try to.
Yeah.
But it is it is that area you see it's straddling the Caddo and Desoto parish line.
Kind of northeast Bethany Longstreet on the way towards Swan Lake.
So it's a 280 acre unit this was the.
There was 140 600 foot lateral we would have one more remaining 4600 foot lateral.
And this is the first 10000 foot lateral in that 1200 80 acre unit. So were expecting to have four additional 10000 foot laterals and one additional 4600 foot lateral.
That's perfect and then.
As far as the comments you had on your capital program about maybe we can add a little bit more free cash flow was that a function of removing some activity or maybe adding activity or price goes up or was it more maybe internally you're thinking.
Cost savings.
Bob.
Yes. This is Rob again so.
I don't I don't think you'll see us add activity, we're comfortable with the $80 million of midpoint Capex guidance range.
It's moving around slightly if you really drill down and you'll see we're expecting to complete nine five net wells. This year instead of $9. Four is just a change in working interest on on a well or two.
And yet we're not changing obviously the capex range. So I think the big question is just on.
Operating costs are and where gas prices go.
You take if you look at the strip.
On which is $3, we're obviously going to be at the high range of debt free cash flow.
The guidance range.
We're doing our best to control, our operating costs and we're not seeing any service cost inflation. So we still feel comfortable with the range.
Free cash flow that we've guided to.
Even though production is coming in.
Bit less than.
And that's worth talking a little bit about also the wells several of the wells that were brought online in the first quarter were non operated.
There was a pipeline.
Curtailment of volumes that we think over time it gets resolved.
Since those volumes were cut almost in half of where they came on line. So even though we had a smaller working interest in those wells that still affected first quarter production and frankly.
All we can do is forecast at the reduced rate through second quarter throughout the rest of this year, which is predominantly driving some of the reduction in our midpoint of production guidance.
And I guess this is Gil I might just add one.
Quick caveat to that and that isn't particularly on the second half of this year, our ability to forecast non op.
Plans that we can't currently foresee is a little bit challenged so to the extent from non op activity came in and we think made sense that could obviously have an impact on the full year capex.
Absolutely that makes sense and then really the last one is more of a big picture.
With the.
Now this.
Morning is there any interest.
You guys are kind of the go public situations a lot smaller.
On private is trying to.
Alright.
Yes. This is Rob again.
Entertaining.
All of the above we're looking to continue to bolt on.
Acquisitions, we like the drill to earn because it.
No upfront cash and you capture the opportunity by shuffling Youre drilling rigs. So that's important we're looking at bigger packages.
We're open to any other ideas that make sense that are accretive for our shareholders. So.
That's.
Yeah.
It's all about new shareholders and figuring out how best to create more value.
Sure.
Yes.
Thanks Bert.
Yeah.
The next question will come from Phillips Johnston with capital one. Please go ahead.
Hey, guys. Thanks.
The Haynesville rig counts picked up from a pretty good great group.
It's been.
In about five or so.
Rob I know you did set price and you haven't seen any cost inflation, but at what point do you think we might start to see some in and if we do see some maturity.
Yes.
Which areas do you think you would expect to see channel first.
Sure sure that's a great question and in fact, as we as we said on the last call.
We're baking in a little bit of cost inflation.
In particular second quarter through the end of the year. We just think it's inevitable you can't.
Generate 100% rate of return or greater.
For for an extended period of time without seeing some.
Service cost inflation I think the biggest driver of your completed well cost is the frac right now we have excess.
Pressure pumping capacity in the basin.
If oil prices continue to rise and we see a good bit of Frac fleets moving back into the Permian from where we are now.
Then that could obviously impact.
<unk> cost to some degree.
But right now we're just not seeing it but we do think it's fruit and if we're in a $3 from some people are calling for even $3 50 gas in the back half of this year.
Then.
We're expecting.
A little bit of cost inflation.
It's just you know, it's just all a supply demand on the equipment in particular.
But our $80 million midpoint does have.
The range of 75 to 85 does have some internal service cost escalation built into it in case, we see that.
Okay.
Net net.
If we look at your production guidance from the second half.
Aside from the second quarter and full year.
Pleasure.
Average around 180 or so in the second half of the year.
I'm not sure if I missed this but should we assume that the growth in the second half of the year will be fairly even maybe 171 to 175 or so on the third quarter net sort of exiting maybe.
<unk> hundred 85, 190 ish or is the cadence a bit more lumpy than that.
Yes, Phil it's Rob again I'll take those.
Can't argue with those numbers, we haven't specifically given guidance in the in the quarters, but sequentially.
That does make sense and we are comfortable.
With the with the yearly average so if you look at the cadence second quarter, Capex, clearly going to be down significantly third quarter back up.
And that would cause your exit rate in the fourth quarter to be to be higher than we've seen to date. So.
Can't argue with the with those numbers, but we will as we get closer certainly on the second quarter call. We'll announce we will give guidance on third quarter, and maybe a little more direction on fourth quarter, but those numbers seem to be in the ballpark.
Okay sounds good thank you. Thanks.
Thanks Phillips.
Again, if you have a question. Please press Star then one.
This.
Our question and answer session I would like to turn the conference back over to Gil Goodrich for any closing remarks. Please go ahead Sir.
Sure. Good morning, Thank you everyone really crucial here.
This morning, and we certainly look forward to presenting our second quarter results to you in August Thank you.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
Yeah.
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