EV Energy Partners, L.P. (NASDAQ:EVEP)
Q4 2016 Earnings Conference Call
March 1, 2017 9:00 AM ET
John Walker – Executive Chairman
Mike Mercer – President and CEO
Nick Bobrowski – Vice President and CFO
Brian Brungardt – Stifel
Welcome to the EV Energy Partners Fourth Quarter and the Full Year 2016 Earnings Conference Call on Wednesday, March 1, 2017. Throughout today’s presentation, all participants will be in a listen-only mode. After the presentation, there will be an opportunity for analysts to ask questions.
This morning, EV Energy Partners issued a press release announcing fourth quarter and full-year 2016 results. That release along with additional financial and operational information and reconciliations for non-GAAP financial measures is available on EVEP's website at www.evenergypartners.com.
Please refer to the forward-looking statements in the earnings press release, which state that statements made during this call that refer to management expectations and/or future predictions are forward-looking statements intended to be covered by the Safe Harbor provision of the Securities Act, as there are many factors, which could cause results to differ from management’s expectations.
I will now hand the conference over to John Walker, Executive Chairman; Mike Mercer, President and CEO and Nick Bobrowski, Vice President and CFO. Please go ahead.
Thank you Jennifer and good morning everyone. This is John Walker, thanks for joining us today, I’d like to quickly recap 2016 and get you up to speed on all the recent activity. Then I will turn the call over to Nick for a financial review and Mike to discuss our year-end reserves and drilling plans for 2017. Overall operating results for 2016 were in-line with our expectations.
Production for the year was within 2% of the mid-point of our guidance, that we put out last February, primarily impacted by some divestitures that we had throughout the year. Additionally we were able to continue making progress over reducing our operating expenses, which were 9% below the mid-point of the guidance for the year.
Since we last spoke in mid-November we have been hard at work taking, steps to improve our asset portfolio. In December, we sold natural gas properties in the Barnett Shale for $52.1 million.
This sale represented approximately one sixth of our Barnett reserves more than 20,000 town lot leases and approximately 13 million cubic feet per day of lower margin dry gas production. Because these properties have a low tax basis, we are likely to put the proceeds into a like-kind exchange account, so that our unit holders would not realize the capital gain associated with this sale.
In January, we used these proceeds and $6.6 million of borrowings under our credit facility to purchase a 5.8% interest in producing properties in acreage in Karnes County Texas for $58.7 million, from an unrelated third party.
As you probably know Karnes County is the largest oil producing county in Texas. And the core of the core area in one of the premier basins in North America. And that's the area where we have improving results for both the Eagle Ford and Austin Chalk.
And EnerVest institutional partnership owns 87% of the properties that has been operating in since last summer, with intrinsic initial results. Our first pool well pad averaged oil production at over 9,000 barrels of oil per day for 30 days.
Since November, EnerVest overall has brought the gross production on this acreage from 11,000 barrels of oil per day to 28,000 barrels of oil per day. The wells pay out in less than a year at today's prices.
A recent strip pricing are an estimated 6.0 (sic) million barrels of oil equivalent a of proved reserves and then the issue of 1.3 million barrels of oil equivalent of probables and that's net to the EVEP. Current production is a little over 1,200 barrels of oil per day just for EVEP but we plan to increase that by approximately 40% by the end of the year.
The properties have over 200 drilling locations that are scalable, repeatable and very economic at current prices. Current production in reserves for this property are lower than that of the Barnett Shale asset we’ve sold in December. It is 80% oil and liquids and it's a significantly higher margins. Therefore we expect significantly higher cash flow on a relative basis.
Mike will discuss the details of our planned capital spending for the year later in the call but the Eagle Ford acquisition represents roughly a third of the $30 to $45 million that we plan to spend in 2017. This is an area that is very attractive that we want to add more to EVEP’s portfolio over time.
Finally our operations team began evaluating our existing portfolio to earmark those assets or specific wells we consider non-core to our operations portfolio. The ultimate goal was to divest these non-core properties and transform our existing asset base in an effort to improve margins and reduce operating and administrative cost.
To sum up we had a quarter and a year that were overall inline with our expectations. We completed the tax efficient exchange of properties trading low margin dry gas property in the Barnett Shale for a high margin oily property in the best part of the Eagle Ford, which vastly improves our drilling inventory. As we continue to trim our portfolio of marginal wells, which helps to reduce our cost and our liabilities.
Now, I am going to turn it over to Nick to discuss our financial results.
Thank you John, I'm going to review our results for the fourth quarter and the full-year of 2016 and discuss 2017 guidance. For the fourth quarter production, was 11 Bcf of natural gas, 278,000 barrels of crude oil and 547,000 barrels of NGL’s, or 173.9 Mmcfe/day. This represents a 17% decrease from the fourth quarter of 2015 and an 11% decrease from the third quarter of 2016. The decreases were primarily due to reduced drilling activity and the divestitures completed on December 1.
For the fourth quarter we had a net loss of $165.7 million, or negative $3.31 per basic and diluted weighted average limited partner unit outstanding. Several items to note that were included in the net loss are; $127.9 million of impairment charges primarily related to the write-down of certain oil and natural gas properties due to the effects of commodity prices on expected future net cash flows and the disposition of oil and natural gas properties. $27.5 million of non-cash losses on commodity derivatives and interest rate derivatives and $1.8 million of non-cash compensation related costs contained in G&A expense.
For the fourth quarter, Adjusted EBITDAX was $28.5 million, which is a 46% decrease from the fourth quarter of 2015 and a 10% increase over the third quarter of 2016. Distributable Cash Flow for the fourth quarter was $7.9 million, a 70% decrease from the fourth quarter of 2015 and a 24% increase over the third quarter of 2016. The decreases in Adjusted EBITDAX and Distributable Cash Flow from the fourth quarter of 2015, which are described in the press release under non-GAAP measures, were distributable to lower realized hedge gains and lower production, partially offset by higher realized oil, natural gas and natural gas liquids prices.
The increases in Adjusted EBITDAX and Distributable Cash Flow for the third quarter of 2016 were primarily due to higher realized oil, natural gas and natural gas liquids prices and lower operating expenses, partially offset by lower production.
For the full year 2016, production was 70.6 Bcfe, or 192.9 Mmcfe per day, which is a 10% increase over 2015 production. The increase over 2015 production was primarily due to the addition of producing properties acquired on October 1, 2015.
We reported a net loss of $242.9 million, or negative $4.85 per basic and diluted weighted average limited partner unit outstanding. Included in net loss were the following items:
$131.3 million of impairment charges primarily related to the write-down of certain oil and natural gas properties due to the effects of commodity prices on expected future net cash flows and the disposition of oil and natural gas properties. $93.8 million of non-cash losses on commodity derivatives and interest rate derivatives.
A $47.7 million gain on the early extinguishment of debt related to our Senior Notes repurchases which were at a significant discount to par. $6.6 million of non-cash costs contained in G&A expenses. A $3.2 million gain on the settlement of contract, associated with one of our Utica JV Partners and $700,000 of dry hole and exploration costs.
For the full-year 2016 Adjusted EBITDAX and Distributable Cash Flow were $101.3 million and $18.7 million, which is a decrease of 50% and 81%, respectively, versus 2015. This is primarily due to lower realized hedge gains and lower realized oil and natural gas prices, partially offset by the addition of producing properties acquired in October 2015, lower operating expenses and higher realized natural gas liquids prices.
Guidance for the full year of 2017 is included in our press release, we expect production to average between 167 Mmcfe per day to 185 Mmcfe per day. With the December sale of our Barnett dry gas assets we expect to see an improvement in our natural gas differentials relative to NYMEX ranging between negative $0.37 and negative $0.25 per Mcf compared to negative $0.44 realized in 2016.
Our crude differentials to NYMEX are expected to be negative $5.40 to negative $3.90 per barrel. Natural gas liquids forward prices have improved relative to WTI. And we are guiding to realizations between 34% and 38% of WTI. As John mentioned we continue to make progress on our operating expense reductions.
Our LOE guidance, is $98 million to $108 million. Production taxes are expected to be between 4.2% and 5.2% of our oil and natural gas revenues. And our cash G&A is expected to range between $22 million and $26 million.
Since our last call, we added 50 million a day of natural gas hedges in the first quarter 2018, which is about 43% of our natural gas production. We are already fully hedged on our natural gas production for the remainder of 2017. We also added 1,400 barrels a day of ethane hedges and 700 barrels a day of propane for the entire year of 2017, which represents just under 50% of our expected production for those components. The details of all our hedge positions are provided in the press release.
We expect to have unitholders K-1s for the tax year 2016 available for download on our website by March 6, with paper copies arriving in the mail a few days later.
Finally, as of December 31, we had $265 million drawn on our credit facility. Following the acquisition in January, that amount is now $275 million. Our current borrowing base is $450 million, which leaves us with over $175 million of liquidity between cash on hand and borrowing base capacity.
Now I will turn it over to Mike Mercer for a view of our reserves and our plans for capital spending in 2017.
Thank you, Nick, and thanks for joining us today. Today I will spend a few minutes discussing year-end reserves and our CapEx plans for 2017. Our year-end estimated net proved reserves were 851 Bcfe. Approximately 68% were natural gas, 23% were natural gas liquids, and 9% were crude oil. In addition, 90% of our reserves, were categorized as proved developed. Year-end 2016 estimated net proved reserves decreased by 22% or 246 Bcfe from year-end 2015 reserves.
The largest cause of this decrease was due to lower SEC pricing for 2016 relative to that of 2015. As you know, the SEC specifies that reserves are determined based on crude oil and natural gas prices using the average price on the first of each month for that year. The prices used in determining estimated net proved reserves at year-end 2016 were $42.75 per barrel of oil and $2.48 per Mmbtu of natural gas which were 15% and 4% lower respectively than those used in 2015.
Additionally divestitures throughout the year, including the sale of our Barnett dry gas properties in December and volumes produced and sold during the year, also contributed to the decrease in our reserves year-over-year. Our recently announced acquisitions of the Karnes County properties, which was completed in January, was not included in our year-end reserves. We estimate total SEC proved reserves of this acquisition were 35 Bcfe.
Now for comparative purposes when comparing SEC reserves, if you utilize NYMEX forward closing prices for oil and natural gas as of year-end 2016, rather than SEC pricing, our strip-based proved reserves would be 1.28 Bcfe with a PV 10 of $790 million. In addition, at these prices, our recent Karnes County acquisition would be 38 Bcfe of strip-based proved reserves with a PV 10 of $87 million.
As John mentioned, we plan to spend between $30 million and $45 million this year, primarily on the Barnett Shale, the Eagle Ford, and the Austin Chalk. There is currently one rig running on the Karnes County acreage where we own a 5.8% working interest.
However, a second Karnes County rig is planned during the second quarter. We also currently plan to have a rig in each of the Barnett Shale and Austin Chalk areas beginning around midyear. In the Barnett Shale, we plan to spend around $15 million on low-risk infill and step-out wells. In our traditional Austin Chalk assets, we plan to spend approximately $9 million.
Like the Barnett, we are very familiar with this area having owned and drilled on this acreage for the past 10 years. On our newest acquisition in Karnes County, the planned drilling program targets the Eagle Ford and Austin Chalk formation and consist of 34 wells, where we have a working interest of approximately 5.8% as I had mentioned earlier.
EVEP's share of drilling and completion costs is currently estimated to be approximately $11 million. The economics of this area are very attractive at current, Because this is an oil-rich area of play, we expect our oil production to increase accordingly as these wells are drilled, completed, and turned in line. We also expect that with this level of drilling, we will be able to keep production relatively flat to current levels. I will now turn it back over to the operator to open the line for questions.
[Operator Instructions] Our first question is from Brian Brungardt with Stifel. Please go ahead.
Hi good morning guys.
Good morning Brian.
I guess kind of with the moving pieces there on 4Q 2016, could you just provide what the run rate was there exiting the quarter?
Brian, do you mean with the – including the acquisition that we just made in January.
A word about it. I think the midpoint of our guidance is about $175 million, $176 million, and that's kind of where we are right now. So most of our CapEx is going to be, we have drilling going on right now in Eagle Ford, Austin Chalk, and at Karnes County property, but most of the Barnett and the Chalk capital will be spent around midyear, and we should see those wells coming on in August or September. So there might be a slight dip-off in the middle and then a little ramp-up at the end.
Got you. And then just a follow-up question and I will jump back in queue. Realize there are a number of variables at play, but it looks like just kind back of the napkin, maybe deleverage coming in, as it stands today comes into play in 2018 and just curious the confidence of being able to obtain additional covenant amendments given the extent of the downturn.
Yes, well, Brian, we are getting ready to start our, semi annual borrowing base review, and we will be over the next month or so be working with our banks on that and looking at alternatives there, as well as looking at other delivering opportunities through out the year.
Got you. I appreciate it. Thanks, guys.
At this time there are no further questions, I will turn the call back over the John Walker for closing comments.
Thank you Jennifer and thank all of you for joining us this morning. We do believe that EVEP is doing quite well. Obviously we came in very close to the guidance that we issued to you a year ago. Very pleased with our team in terms of its continuation of the lowering of our operating costs and our G&A costs, and I did say in the call that we are reviewing our whole portfolio to upgrade it. I think the best example is when you can move from sort of a difficult asset in the Barnett, our only asset with 10 watts in it, to the best producing county in Texas.
And so we continue to try to upgrade our portfolio, and that is something that you should expect to see from us throughout the course of the year. So we look forward to a really good 2017 and look forward to visiting with you in the future. Thank you.
This does conclude today's conference. We thank you for your participation.
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