Good morning.
My name is Chad, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Q4 2015 Earnings Release and operations update for Oasis Petroleum. Please note this call is being recorded. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
I will now turn the call over to Michael Liu, Oasis Petroleum's CFO, to begin the conference. Thank you, sir. You may begin. Thank you, Chad. Good morning, everyone.
This is Michael Liu. Today, we are reporting our year end 2015 financial and operational results. We're delighted to have you on our call. I'm joined today by Tommy News and Taylor Reid as well as other members of the team. Please be advised that our remarks, including the answer to your questions, include statements that we believe to be forward looking statements within the meaning of the Private Securities Litigation Reform Act.
These forward looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings release and conference call. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the Securities and Exchange Commission, including our Annual Report on Form 10 ks and our quarterly reports on Form 10 Q. We disclaim any obligation to update these forward looking statements. During this conference call, we will also make references to adjusted EBITDA, which is a non GAAP financial measure. Reconciliations of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release and on our website.
We plan to file our 10 ks today following this call. We will also reference our current investor presentation, which you can find on our website. With that, I'll turn the call over to Tommy.
Good morning, and thanks for joining our call. While 2015 proved to be more challenging on the macro front than many had anticipated, from an operational standpoint, it was arguably our best since inception. The team worked diligently throughout the year to continuously drive down costs and improve operational efficiencies. As a result, we increased annual average daily production by 11% to 50,500 BOEs per day in 2015, which is above the top end of our guidance, while spending 70% less in drilling and completion capital year over year and approximately $100,000,000 less than our original total capital budget. Additionally, we drove LOE costs down by over 20%, reduced well costs by roughly 30% and saw differentials improve by about 40%.
We were able to power down activity quickly in response to lower oil prices, reducing our rig count from 16 to 3 rigs in the course of 5 months, while incurring only $3,900,000 in rig termination penalties. To begin 2015, we anticipated needing 5 rigs to execute our capital drilling program, but through operational efficiencies, the team found a way to accomplish the same workload at a run rate of 3 rigs. We have since dropped another rig and plan to remain at 2 rigs for
the balance of
2016, both of those being in our Wild Basin area. OMS also beat expectations delivering $66,000,000 in adjusted EBITDA versus an estimate of $40,000,000 coming into the year. We've spoken throughout the year about the continued success that we've seen through our high intensity completion program. We completed 60% of our wells with high intensity jobs in 2015, and the results continue to be extremely impressive with production uplift ranging from 30% to an excess of 60%, and in some cases, 2x, as you can see in our presentation posted this morning. At the same time, our well costs have come down significantly, and Taylor will talk more about that.
With the tremendous results we've experienced, we anticipate completing 100 percent of our wells with high intensity jobs in 2016. The substantial total well cost improvements we have recognized coupled with significantly increased well performance all translate into a meaningful increase in our capital efficiency, generating much more with much less. We've also been able to remain strong and well positioned in a challenging environment, which is reflected by our continued ability to remain cash flow positive all in including midstream capital starting in the second quarter of 2015 and carrying on throughout the remainder of the year despite a significant decrease in the commodity price year over year. Given the macro environment, we're keenly focused on our balance sheet with an eye on liquidity, leverage, our hedge profile and how our operational choices impact all of these items. We ended the year with a revolver balance of $138,000,000 and with proceeds from our January equity offering, that facility is undrawn today.
We are continuously watching the oil markets and opportunistically hedging to lock in 2016 2017 prices. We have about 70% of our estimated 2016 oil production hedged at over $51 a barrel. And we've started to chip away at 2017 with 8,000 barrels a day hedged with an average floor price of approximately $47 Since the end of 2015, 100 percent of our drilling activity has been in our Wild Basin area, which will continue to be the sole focus of our drilling activity in 2016. As we've discussed in the past, Wild Basin is in the deepest part of the basin and is some of the very best rock, not just in the Company or the Williston Basin, but across all of the North American resource place. We can still drill economically attractive wells in this area at $35 WTI.
So while
the macro environment in 2015 presented us with a lot of challenges, our organization transitioned quickly and performed extremely well. We powered down our activity in an orderly manner, contracting to the core of the basin and reducing rig count from 16 to 3 and frac spreads from 6 to 2. We optimized completions from our base design to high intensity and significantly increased per well recoveries. And we materially impacted both capital and operating costs through both service cost reductions and operational efficiencies, all resulting in us exceeding internal and external expectations. But all that's behind us now, we'll continue to
Excuse me, this is the operator. May I have your name, please? Hello, we're speaking privately in the six thirty two phone number. May I please have your name?
You are now rejoining the main conference.
I'll turn the call over to Taylor.
Thanks, Bobby. I want to start by saying that 2015 was a great year for us operationally. We continue to see strong results from our high intensity completion program. And as a result, we increased our high intensity wells from 20% in 2014 to about 70% in the second half of twenty fifteen. We also made a
good transition to the core of the
basin, including 86% of our wells in the core in the second half of the year. On our previous earnings call, we mentioned 3 all sand slickwater wells in our Indian Hills area. We now have about 6 months of production data on those wells.
And just
as we saw in Montana, Red Bank and in competitor wells, they are performing in line with nearby ceramic proppant wells. As a result, we have transitioned to 100 percent sand slickwater wells going forward. This design change reduces well cost by $500,000 per well. Those cost savings continue the rapid well cost reduction we have seen over the past year. Coming into 2015, we were completing wells for over $10,600,000 and they were taking approximately 21 days to drill.
In November, we said those costs would come down to $7,400,000 with the changes evenly split between service cost reductions and efficiency gains. Today, with the combination of the switch to sand, updated rig contracts and continued improvements in efficiencies, we expect slickwater wells in our 2016 plan to cost $6,500,000 and we're currently drilling them in 15 days on average. Following these latest developments, we have also updated our type curves. Turning to Slide 11 in the
presentation we released this morning,
we are now modeling our core area type wells at 1050 MBOEs in the Bakken and 875 MBOEs in the Three Forks. These estimated recoveries reflect our latest data on high intensity results and our weighted averages of remaining inventory estimates. When you pair the core inventory data on Slide 8 with the returns depicted at the bottom of Slide 11, it shows that even at today's strip, we have over 13 years of economic inventory at our current pace of 46 wells completed per year. During our last call, we talked about living in a $50 world and keeping production flat to slightly growing. As oil prices continue to drop, we have updated our 2016 plan to reflect current oil pricing.
To start the year, we have reduced activity to 2 rigs and 1 frac crew. Our rigs will remain in Wild Mason and our frac crew will remain in Indian Hills until it transitions to Wild Basin later this year. Under this program, we expect to complete 46 gross wells and 28.6 net wells in 2016, all with high intensity completions. With the reduced well costs and pace of activity, our drilling and completion capital will drop substantially from 2015 and come in at $200,000,000 for the year. Another great outcome for the year is our proved reserve numbers.
Year end 2015 developed reserves slightly increased over year end 2014 levels. Thus, while our total reserves of 218,000,000 barrels of oil equivalent reflect a 20% reduction from 2014, the difference is driven entirely by undeveloped reserves and is a reflection of both a 47% decrease in the SEC price deck and our reduced activity levels. Proved reserves now represent 68% of our total reserves compared to 54% at the end of 2014. As we move further into 2016, we will continue to keep an eye on the oil markets and we'll be prepared to adjust activity accordingly. As we mentioned on the last call, our rig contracts matured around the beginning of the year.
As we approach new contracts, we will continue to maintain flexibility and work to lower cost to both cost reductions and operational efficiencies. In addition, our backlog of 85 wells waiting on completion at year end provides us with immediate flexibility from a price recovery and operational standpoint. In closing, I want to commend the team for an outstanding 2015 and challenge them to maintain the momentum going into 2016. With that, I'll turn the call over to Michael. Thanks, Taylor.
Coming into 2015,
we talked about being cash flow positive as measured by adjusted EBITDAX less CapEx and cash interest. And for the past three quarters, we've accomplished this coming in cash flow positive by $157,000,000 during that period. Excluding the stream capital, we are projecting to be cash flow positive at $35 per barrel in 2016. Differentials grew much tighter throughout 2015 ending in the $4 to $5 range where we expect it will stay for 2016. This was driven by a combination of factors including the HH pipeline which came online last summer, by reduced rates at certain rail facilities, and by the overall flexibility of our crude takeaway systems, all of which highlights our marketing team's ability to access the best markets at any given time.
Over the course of the year, we were also able to dramatically reduce lease operating expenses, ending the year at $7.84 per BOE, a 23% reduction versus 2014. OMS was a large contributor to this success as we exited the year with 75% of our produced water volumes connected to OMS gathering pipelines for the last 4 months of the year, which is almost double our 2014 exit rate. Other significant contributions to our operating cost reductions included managing uptime on producing wells, better efficiency on high cost wells, and lower workover activities. Throughout 2015, OMS exceeded our expectations and guidance and its 4th quarter was no exception. OMS delivered $18,000,000 of adjusted EBITDA in the 4th quarter and helped drive LOE to the lowest level in 2 years.
For the year, OMS delivered $66,000,000 of adjusted EBITDA versus our original plan of 40,000,000 dollars That is 2.4 times our 2014 levels and 1.8 times our original guidance. The infrastructure build out in Wild Basin, which is critical for our 2016 development, is on schedule and on budget. We expect OMS adjusted EBITDA to be relatively flat in 20 16 with a ramp up coming from Wild Basin towards the end of the year. We'll provide you with a strategic financing update on OMS when it's appropriate. Given the uncertainty in the market and commodity prices, we elected to undergo our spring borrowing base redetermination early and we just completed it on Tuesday.
Our borrowing base is now $1,150,000,000 as banks are now running a much lower deck than in the fall. The lower bank pricing was offset by operational cost improvements our team delivered in 2015. Today, our borrowing base is undrawn providing us with about $1,200,000,000 in liquidity. Our next redetermination is not until October. With all the hard work of our employees, we continue to position Oasis to be able to make solid returns at much lower oil prices in 2016 and beyond.
Our assets are concentrated in the heart of the Williston Basin, and our acreage is almost entirely held by production, providing us with tremendous option value. We will continue to focus on balancing CapEx and production growth, spending within cash flow and preserving our strong liquidity position. With that, I'll now turn the call over to Chad for questions. Thank you, sir. We will now begin the question and answer session.
Our first question comes today from David Deckelbaum with KeyBanc. Please go ahead.
Good morning, Tony, Taylor and Michael. Thanks for taking my questions.
Hi, Dave.
Curious, I know you guys had some successful financing recently through the equity markets and you came out with a 16 plan that basically matches cash flows on the E and P side. It seemed like there is still some variability around building out LMS. And I know you said you'd update us on external financing. But when I look at things now, you guys are 70% hedged this year at $50 a barrel and change.
Is it fair to say that the decision
to go forward with building out LMS right now is sort of set at this point absent like a significant incremental deterioration in the commodity prices and would you really need to bring in an external partner this year to accomplish what you want just given the borrowing base redetermination, the amount of liquidity you have?
Yes, Dave, good question. Look, we still think that we can bring in external financing for OMS and that's our current plans. We're continuing to move down the road on Wild Basin for now. Things can obviously change there if we needed to, so we have some optionality. But Wild Basin is a great area for us and we're going to continue to move down that path given what we see in the marketplace and what we think is our ability to finance and own this on an external basis.
Thanks, Michael. And then just any incremental color on well costs in the basin? I know there's very little activity right now. We've seen well costs steadily coming down. Are you guys expecting another round that you should be realizing this year?
And then could you quantify that at all for us?
So obviously, a huge move in well cost last year going from 10.6% to what we see is currently 6.5 on slickwater wells. And from where we stand, we still think there is room to move and it will still be a combination of efficiency. So getting more efficiency on the drilling and completion side. And then also a bit on the service side as well. But the service side is certainly not going to move as much as it did last year.
They just don't have as much room to move. But we think it's reasonable that we could get it down another 5% to 10% by the end of the year.
What's a tell do you
know what the conceptual cost is of what a well basin completion would do right now or what you have planned currently to total D and C cost?
Yes, 6.5%.
Okay. So it's in line with everything else in the portfolio then?
Right. Got it.
All right. Thanks guys. Thanks, Dave.
The next question is from Ron Mills with Johnson Rice. Please go ahead.
Good morning. Maybe another one for Taylor. When you look at your core position with the 13 years, if you look at Indian Hills versus Wild Basin versus Offshore, are there meaningful differences between those three areas or is the whole core subset in terms of EURs and costs pretty similar across those portions of it?
Overall, Ron, they're pretty similar. We represent that core type curve. I would say that well basins probably a little better than the other 2, but it also has a little bit higher gas content, but you tend to have a little higher EURs there. The cost in all three are pretty comparable. So the economics aren't wildly different, but Wild Basin's probably got an edge on the other 2.
And then when
you talk about the we moved 100% cement completions from the ceramic, Is that going to be just to make sure I understand is that can be applied across all of the core as well based on those initial three well results?
Yes, correct. It will be all across the position. So we'll use it in all of our wells in the core from this point forward.
Okay. And then Michael on OMS, the what is the timeline there? You talked about the project being on time and on schedule. Where are you on that project? Have you already started construction?
And I'm just trying to get a sense as to I guess it's more clear today than it was 3 months ago that you're really moving forward with Wild Basin. I'm just curious where you are in the construction process.
Good question, Ron. The timing is that Wild Basin will be coming online sometime in the back half of the year, called around the end of Q3, really into Q4. The project obviously is we've spent capital already there and you can see by the picture that we've had in our investor presentation that the gas plant is fairly well constructed already. We do have a number of lines that need to go in that area and so we've got more capital spend this year. Most of that work is not done until things clear up in terms of the winter weather and breakup season occurs.
So that will be kind of in the middle part of the year.
And just to clarify, the $140,000,000 is what the unit cost of that is. And so to the extent you bring in some sort of external capital or sell down a portion of it, then you would re capture whatever that portion is of the $140,000,000 Is that correct?
That's exactly right. And we've already spent some capital there. So even if you did something that brought in $140,000,000 we have kind of additional capital that was spent in Wild Basin and Learning.
Which you would recover as well.
Yes. That project is a little
bit bigger than just that 140.
Understand. Okay, great. Thank you.
Thanks, Ryan.
The next question is from Brandon Bingham with Cowen and Company. Please go ahead.
Hi, good morning.
Good morning.
Curious if you guys have had any consideration for OMS in your profitability? And if not, would you expect that to change going forward?
There's not a lot of consideration in the credit facility for LMS, a little bit on the LOE side, but not for the rest of that person. Most of it's just on the E and P reserve side.
Okay. And just switching over to differentials right now, how sticky are differentials right now at the current levels? And what is the company taking to protect against a potential widening up in the Bakken?
Yes. We think the differentials will hold pretty strong. There's a lot of good pipeline in rail access, and so there's a lot of varied areas that we can go to across the country to access the best differentials for us. Our gathering system that we're connected to allows us that flexibility. So we feel fairly confident that we can keep those differentials lower.
We have done some longer term work on the differential side, which has not been available historically to lock in some of those, but continue to work that every day. The next question is from Steven Berman with Canaccord Genuity. Please go ahead. This is Michael Katzen reporting in
for Steven Berman. Thank you for taking my question. So the first one is Q4 oil percentage came in
a little bit lower than what we
were looking for. I realize that the result of this is going to
be in the Wild Basin. What should we
expect going forward in 'sixteen and in 'seventeen?
Yes. The 4th quarter oil percentage came down mainly because we were connecting our wells at a higher rate and so we flare less gas. The impact of Wild Basin, it will be a little bit gassier, so you'll continue to see that gas percentage or the oil percentage continue to come down a little bit. So we'll continue to keep you updated on where we think that will go, but it should continue to inch down a bit as we do more and more wild basin wells.
All right.
Thank you. And then additionally, we've seen that
both Continental and Whiting are deferring the Bakken wells. And if the prices if prices are just too depressed, can you see yourself doing the same in the future?
At this point, based on what we see in pricing, we look at current strip pricing. The economics still support the program. And so we think it makes sense to move ahead. We've got a good hedge position that you've seen for this year with 70% of the volume hedged and that certainly and that's at over $51 a barrel. And so that's the biggest part of the program.
And if started our hedging program, 8,000 barrels a day in 2017. So when we put all those things together, we think it makes sense to continue to complete the wells there. We're getting great returns.
All right. That answered my question.
I appreciate it. Thank you.
Thanks. The next question is from Neal Dingmann with SunTrust.
Please go ahead. Good morning, guys. Hi, Neal. Tommy, it looks like obviously you've done the prudent thing and cutting back and continue to focus obviously in your updated area there. Just I was wondering the size of Wild Basin, what price wise or is it more on key returns?
What would it take for you to start looking and returning activity in some of the other areas outside of that?
It all boils down to oil price and the resulting returns and some traction on time window on that oil price or our ability to lock some of it in additional in through hedging, right? But it's and you've got the overlay of how much damage has been done to the service sector. And as you look to potentially ramping up at some point in the future, how easy is it or difficult to get services back. So that's going to that's probably going to be a bit of a throttle when we come out of the website of this.
Okay. And then just lastly one more just follow-up for Michael as far as obviously not in this environment, Michael at what range would you guys think about adding some more hedges?
Yes. We've got Tommy mentioned that we've got 70% of oil hedged this year at pretty good numbers. Next year, we're a little bit more lightly hedged, and so we'll continue, as we normally do, to be opportunistic around layering hedges into 2017 or the next year out. And then as we get further into the year, we may continue to layer into the back half of twenty sixteen a bit if we see prices that we like. Usually, we do that to protect cash flow as well as we're fairly opportunistic when we see some prices that we like.
Got it. Thanks, guys. Thanks.
Ladies and gentlemen, this concludes our question and answer session. I would like to turn the conference back over to Tommy Nusz for any closing remarks. Thanks.
As I said earlier, we'll continue to remain flexible and adjust to our macro environment. We have a tremendous asset base, multiple financial options and a strong team that continues to perform exceptionally well in a tough environment. With all of that, we're well positioned to bridge this current down cycle and be prepared for a rebound. Thanks for joining our call today.
Thank you, sir. The conference is now concluded. Thank you for attending. You may now disconnect.