GPOR
#Thank you, <UNK>.
Welcome, everyone, and thank you for listening in.
As announced in the press release yesterday evening, during the first quarter Gulfport reported approximately $15.1 million of adjusted net income on $164.6 million of adjusted oil and natural gas revenues and generated approximately $96.7 million of adjusted EBITDA and $83.2 million of operating cash flow.
The first quarter was another solid operational quarter for Gulfport, highlighted by strong production from our Utica shale assets and our continued focus on efficiencies that led to decreases in costs across the board.
In addition, Gulfport improved upon our already solid balance sheet, completing a successful equity offering which provides us with the flexibility and optionality should we continue to see improvement in the forward curve.
Total net production for the first quarter averaged approximately 692 million cubic feet of gas equivalent per day, ahead of our previously-issued guidance of 670 million to 685 million cubic feet per day.
As we discussed in February, during the first quarter Rice completed ahead of schedule the lateral that now connects two of our existing dry gas gathering systems, which allowed us to end our previously announced voluntary curtailment.
In addition, while we did not have a completion crew running during the first quarter, we entered 2016 with an inventory of 15 gross drilled and completed dry gas wells from our 2015 program, which were all turned to sales and flowing by March 31.
Following the first quarter, Gulfport brought back a completion crew in the Utica and began exiting our planned 2016 completion activities in the play.
We currently forecast production during the second quarter to average approximately 664 million to 692 million cubic feet per day and reiterate our full-year production guidance of 695 million to 730 million cubic feet per day.
During the first quarter, before the effective hedges and including transportation costs, Gulfport's realized natural gas price settled at approximately $0.70 per Mcf, below the average Nymex natural gas last day settlement prices for the quarter.
As you can see from our production results, we brought online significant volumes during the first quarter within a matter of weeks and, when coupled with an unusually warm winter, we came in slightly above the high end of our previously-provided differential guidance.
We currently forecast a similar natural gas differential during the second quarter.
However, we reiterate our full-year basis differential guidance of $0.61 to $0.66 per Mcf off Nymex monthly settled prices.
We believe we will experience stronger differentials in the latter part of the year and continue to be very focused on and committed to obtaining strong realizations.
In addition, before the effect of hedges, our first-quarter oil and NGL realized prices came in as expected and we reiterate our expectation to realize approximately $7 to $8 off WTI for oil and $0.19 and $0.22 per gallon for NGLs during 2016.
On the hedging front, we realized a significant gain of $65.4 million in the first quarter of 2016.
In an effort to further protect the balance sheet and provide certainty to our realizations and cash flows during 2016, specifically over the summer months and the shoulder season, we recently layered on additional hedges for the year and currently have approximately 82% of our expected 2016 natural gas production swapped at $3.20 per MCF.
For 2017 we have a large base level of hedges to secure a healthy rate of return for a portion of our anticipated activities and currently have approximately 355 million cubic feet per day swapped at $3.08 per MCF.
Turning to costs, we remain focused on improving efficiencies in the field and continue to see economies of scale as our dry gas volumes grow.
With regard to well costs, our efficiency gains and further cost reductions from our service providers have resulted in savings of approximately $300,000 per well on future well costs, relative to our estimates provided in November 2015.
And we continue to pursue additional reductions.
In addition, as you can see in our financial results released yesterday evening, all operating expenses continue to trend lower as well.
During the first quarter, our per-unit operating expense, which includes LOE, production tax, midstream, gathering and processing, and G&A, totaled $1.08 per Mcfe, which is down 9% over the fourth quarter of 2015 and 28% over the first quarter of 2015.
First-quarter lease operating expense totaled approximately $0.26 per Mcfe, which is down 13% sequentially and 41% year over year.
First-quarter midstream processing and marketing expense totaled approximately $0.60 per Mcfe, down 7% sequentially and 10% year over year, and first-quarter G&A expense totaled approximately $0.17 per Mcfe, down 6% sequentially and 40% year over year.
As we stated on the fourth-quarter call, we expect all per-unit expenses will decrease further as we progress through the year, due to our focus on cost initiatives in the field and the addition of incremental dry gas volumes, ultimately improving overall margins.
We have provided a detailed breakout of our updated well costs and operating expenses by phase window on slide 23 of the presentation posted to our website yesterday evening.
And assuming today's strip pricing, we estimate wellhead returns in excess of 40% throughout our dry gas phase window of the play.
Moving to the balance sheet, Gulfport remains committed to keeping the balance sheet strong and preserving financial strength and flexibility for the Company.
During the first quarter, Gulfport successfully completed an equity offering, raising net proceeds of approximately $412 million.
Proceeds from this offering provide us with significant flexibility as we prepare for 2017 and contemplate the appropriate levels of operational activity.
As we look toward a potential rebound in natural gas pricing, this additional liquidity allows Gulfport to adapt quickly should we choose to begin adding back activity within the basin and ensures we do so while adhering to our core philosophy of capital discipline and conservative credit metrics.
Conversely, this serves as an insurance policy in a lower-for-longer pricing scenario.
As of March 31, Gulfport had approximately $454 million of cash on the balance sheet and an undrawn revolver resulting in over $925 million of liquidity.
Before we move to Q&A, let me touch on the current state of the natural gas environment and the key leading indicators we are closely monitoring as we think about our 2017 activities.
Number one, as we discussed in February, the North American shale natural gas rig count had decreased in excess of 60% over the past year with less than 50 rigs running in all of Appalachia at that time.
Today this number has decreased even further, with the most recent Baker Hughes data showing less than 40 rigs running in the Northeast, which is down from over 130 rigs at the peak of the cycle.
We continue to believe that dramatically lower rig activity must at some point correlate to meaningfully lower supply growth.
Current EIA data continues to indicate that production in the Northeast have plateaued at around 19 Bcf per day.
And while the Northeast production supply growth is slowing, we are seeing evidence of material declines in production from associated gas; conventional gas in the higher cost shale basins such as Haynesville, Fayetteville, and Barnett.
Net-net North American gas supply appears to be demonstrating early evidence of a rollover.
Number two, meanwhile, the demand side of the equation as we enter 2017 is encouraging.
The increased demand from power generation, coal-to-gas switching, start up of the LNG exports, and increased exports to Mexico are materializing today, increasing the overall demand pool for North America natural gas.
This data suggests that the supply and demand rebalance is no longer just wishful thinking.
The natural gas markets are becoming more efficient as time passes and numerous key indicators are all pointing towards an improvement in pricing during 2017.
As the macro environment continues to improve, we are preparing today to implement the appropriate operational and financial strategy that will allow us to increase activity levels promptly, when warranted, to ensure that Gulfport will be an active participant in an upward swing of the commodity cycle.
In summary, our high-quality assets, low cost structure, strong balance sheet, and current liquidity have uniquely positioned Gulfport to not only endure the challenges during a depressed commodity price environment, but also be poised to capture the value associated with improved pricing and accelerated activity should natural gas prices strengthen.
This concludes your prepared remarks.
Thank you again for joining us for our call today and we look forward to answering your questions.
That's a good question, <UNK>.
Since November we've seen about a $300,000 reduction in our leading-edge AFEs.
And just to remind you, since the peak of the cycle, including the most recent savings, we brought down well costs by 34% to 40%.
These cost savings that we've seen over time are both from efficiencies and also from continuing RFP processes.
In fact, we just finished another round and I will let <UNK> jump in here and <UNK> and talk about that as well.
They have been working on it over the past several months.
I do think there's some additional savings, both through service cost reductions, but also mainly probably at this point through efficiencies.
But I will let the guys jump in and comment as well.
<UNK>, this is <UNK> <UNK>.
Just like <UNK> said, we are seeing less days on location and that really, quite frankly, is the definition of efficiency for us.
Less pad days equates to less costs, or quite a bit of savings.
Over the last year, as an example, we had a goal set for fracks at six stages per day and at the end of the year we came in just under that, around 5.9.
But if you do the math on that, roughly where we are today at eight stages per day that knocks down, if you do the math, on an average well you can go from about 36 days on pad to 22.
That equates to a significant savings.
So those are the kind of efficiencies we are seeing on all phases of our completion line.
Not overkill this, <UNK>, but one comment I do want to make is, while we continue to work with service providers and drive efficiencies down, we are certainly not making any decisions that would sacrifice well quality.
So we are going to make sure we keep delivering industry-leading wells.
We will cut costs where we can.
We do postmortems of every well that we drill to see where we can be more efficient, but we will never sacrifice well quality in doing it.
Yes, so we're going to run ---+ it looks like we're going to have two completion crews running.
We've got one now.
They can handle actually most of the activity that we need.
We may bring in a second one at some point in time, but with the efficiencies that <UNK> mentioned from our completion side, I think that completion crew can handle everything we need to do this year.
I will let <UNK> jump in here, too.
I'd say, on our side, we are certainly planning ahead on the long lead-time items if and when there's an opportunity to ramp up, getting ahead on permitting, unitizations, pad construction.
But on the service side, I will let <UNK> comment on that.
You know, that's an excellent question.
I think ---+ our thoughts on M&A activity really haven't changed.
I think we're in a little different position than some folks because we have a large inventory of undeveloped locations.
We've been pretty vocal about saying we don't necessarily think we need more undeveloped acreage.
Obviously, we would like to have an opportunity to get some production reserves and cash flow.
I just haven't seen the right kind of opportunities for us in the core area.
So I think we are pretty heads down, focused on developing our acreage.
And the equity raise, while certainly could help us pick up acreage here and there, it was really a defensive posture for a lower-and-longer scenario and also an offensive strategy to enable us to think about activity levels in 2017 in a different way.
I think certainly you have to begin now thinking about 2017 and what your thoughts are and levels of activity.
As you can see from the well economics in our slide deck, we make really attractive returns at $3 gas, over 40%.
And I'm sure from your own model, you can see the between $3 and $3.50 we could certainly support a higher level of activity.
Again, as I mentioned just a little bit ago, we're trying to get ahead on the long lead-time items that don't cost a lot of money: creating a bullpen of pads, making sure we are ahead on midstream development, permitting.
I would say we are planning ahead for an increase of activity.
As to when we make those decisions, I think a lot of things have to happen so we're watching ---+ certainly watching supplies.
We're watching gas price to make sure that this is not just a temporary phenomenon.
Watching inventories, watching winter forecasts.
A lot of things are indicators for us as to what our thoughts should be about ramping up.
And so <UNK> may have a few comments, too, on this.
Thanks, <UNK>.
<UNK>, it's <UNK>.
I think, as <UNK> mentioned, we're encouraged with the fundamentals that we are seeing for 2017, but I think it's worth highlighting a couple more things on top of what <UNK> talked about.
The first is that, as we talked about in February, we expect to have pretty strong exit-to-exit growth this year at a rate of 15% year over year.
And then, secondly, you talked about hedges for 2016.
We actually have a pretty good hedge book in place already for 2017, so we will look to be opportunistic to layer on there.
But we already feel pretty good about where we are, not just from an operations point of view, but from a financial liquidity and hedging point of view as well for 2017.
First of all, <UNK>, we've been pretty open about saying that we would like to monetize those non-core assets and we'd hoped actually that 2015 was the year that we could do that.
However, quite frankly, southern Louisiana continues to operate pretty efficiently for us.
We have allocated a maintenance budget to them this year, and with a small amount of dollars they are able to throw off their own cash flow and certainly keep the production flat.
So I think my response to that is at some point we will consider monetizing those non-core assets, but our attitude is they are not a physical or financial distraction to Utica.
So as long as they continue to support themselves, we're ---+ we're not in the position, I guess, that we need to give them away.
Obviously, it's hard to sell that kind of an oily asset right now, although there's been some improvement in oil prices.
But, at some point, we may have the right environment.
But again, we don't need it for a liquidity event.
We have got plenty of liquidity and so we have the luxury of being patient, waiting till the markets recover.
Are you talking about wet gas or are you talking about condensate.
We are going to hang out ---+ we're hanging on to our wet-gas acreage.
We like our wet-gas acreage and we do think that ---+ hope and think that prices will recover to a point where we start developing over there again.
Now, we have strategically ---+ certainly we are letting our oil acreage expire, which is not very much.
We never lease much over there.
And our condensate acreage, generally, we're not renewing those leases, although we do have an area that we like that we're going to hang on to.
But we are still trading acreage with other operators back and forth, so there are other ways to augment your acreage package other than just letting acreage expire.
But certainly we are not going to let wet-gas acreage go and certainly not dry-gas acreage.
Well, you know certainly that most of our inventory is in the dry gas window.
I think right now our wet gas locations that we have left to develop are only 12%.
We have ---+ we do have some wet gas pads and we probably will complete a few of those later this year.
But in a time when capital is precious, obviously you are going to stick to your most economic windows.
Right now, all of our activity is in the dry gas window and that's where it will remain for now.
We are certainly still at this point at 1,000 feet, but, look, we're encouraged by the movement in gas prices.
We will find the right time to go back to 750-foot spacing, because we do feel like that's the right way to develop this play.
But, for now, we're still focusing on 1,000-foot spacing.
Thank you, Latanya.
We appreciate your time and interest today.
Should you have any questions, please do not hesitate to reach out to our investor relations team.
This concludes our call.
