Welcome to the second quarter 2010 earnings conference call on August 2, 2010. (Operator Instructions) I would now like to hand the conference over to Ms. Lisa Godfrey, Investor Relations.
Good morning, everyone, and welcome to the Vanguard Natural Resources, LLC second quarter 2010 earnings conference call. We appreciate you joining us today. Before I introduce Scott Smith, our President and Chief Executive Officer, I have some information to provide you.
If you would like to listen to a replay of today's call, it will be available through September 2, 2010, and may be accessed by calling 303-590-3030 and using the pass code 4339640. A webcast archive will also be available on the Investor Relations page of the company's website at www.vnrllc.com and will be accessible for approximately 30 days. For more information or if you would like to be on our e-mail distribution list to receive future news releases, please contact me at 832-327-2234 or via e-mail at firstname.lastname@example.org. This information was also provided in this morning's earnings release.
Please note the information reported on this call speaks as of today, August 2, 2010, and therefore you're advised that time-sensitive information may no longer be accurate as of the time of any replay.
Before we get started, please note that some of the comments today could be considered forward-looking statements and are based on certain assumptions and expectations of management. For a detailed list of all the risk factors associated with our business, please refer to our 2009 10-K that is available on our website under the Investor Relations tab or on EDGAR.
Now, I would like to turn the call over to Scott Smith, President and Chief Executive Officer of Vanguard Natural Resources, LLC.
Thank you, Lisa, and welcome everyone and thanks for joining us this morning to review our results for the second quarter. As usual, I'm joined today by Richard Robert, our Executive Vice President and Chief Financial Officer; and Britt Pence, our Senior Vice President of Operations.
I'd like to point out one thing. As I'm actually calling in from California and while Richard and Britt and Lisa are there in the office, things may be a little more disjoint than our typical conference call when we get to the Q&A section. So please forgive us for that.
I'll start off with a brief summary of our production during the quarter, then review our development drilling activities and will conclude my portion of the call with some observations about the A&D markets and where we see opportunities for Vanguard for the rest of the year. Richard will then take over the call for a financial review, and then we'll open the line for Q&A.
With respect to this quarter, our results came in about where we expected, as we had another full quarter's contribution from the Ward County acquisition that we completed in December of last year and with the initial contribution from the Mississippi transaction that we closed on May 20.
With respect to our production, during the second quarter, our average daily production rose 55% to 24.7 million cubic feet equivalent per day, up from the 17.6 million cubic feet equivalent per day we produced in the second quarter of 2009 and rose 5.2% over the first quarter 2010 volumes.
Looking at our production on an individual product basis, our year-over-year natural gas production rose 21% to 1.27 Bcf. Oil production rose 98% to 155,000 barrels, and NGL production increased 241% to 50,000 barrels.
On a sequential basis, oil production was 17% higher than produced volumes in the 2010 first quarter. Natural gas production was 5% above last quarter's volumes, and NGL production was 12% lower than first quarter 2010 volumes. This reduction was attributable to the Enterprise plant in South Texas being shut down for much of the June period. But we're glad to report that plant is now back up and running.
During the second quarter, inclusive of our hedges, we realized a net price of $10.09 per Mcf of natural gas, $75.87 per barrel of crude oil and $0.96 per gallon of NGL. These realized prices were essentially flat to last quarter for natural gas and crude; however, we did see a 20% drop in our realized NGL pricing from the prices we had seen last quarter.
With respect to our LOE, we came in, in our second quarter LOE with $1.86 per Mcfe, which compares to $1.74 per Mcfe in the first quarter of 2010. During the quarter, we had several nominal non-recurring events that led to this increase. And now that these are behind us, we believe our LOE per Mcf will be back to the lower levels we had seen previously.
As we discussed in our last call, this quarter would be the highest capital spending period for the year; however, we are pleased that as far as spending $6.1 million in capital in development drilling activities, we managed to post a positive coverage ratio of right at 1 times. Our largest capital expenditures were in the drilling of a 100% well in the Ward County properties and the drilling of a 50% working interest well in the Parker Creek field in Mississippi.
Although the completion of the Ward County well has been delayed due to the lack of frac crew, I'm pleased to report this well is in process of being frac, and we should have the well on production from all the perfs in the next few weeks. As this well is producing 100 to 200 barrels per day from a single set of perfs pre-frac, we're anticipating a very good production rate once the well has been completed fully.
This well came in at our AFE estimate of around $5 million and based upon the results we've seen to date should generate a very nice return. I'd like to point out we have five PV locations left to drill on our Ward County leasehold, and our plan is to drill at least one well a year for the next several years.
The initial Mississippi development well was completed for about 20% less from the projected AFE and is currently producing at a rate of around 50 barrels per day from the Hosston Formation. This rate is below what we had hoped for initially and the operators are currently evaluating several additional completion techniques in the effort to obtain a higher rate.
And in addition to the pay we encountered in the Hosston, there are substantial behind pipe pay in the Sligo and Rodessa zones that will be completed at a later date. Post this well being drilled, we still have an inventory of 15 infill PUD wells that we plan to develop along with the other operators in the next four years.
Within South Texas, we didn't drill any wells this quarter, but we did complete one well, the (Gate 14 H). We are currently evaluating the drilling of two to three development wells in the Sun TSH Field during the balance of the year.
Production from this field has high associated NGL component. So the economics of drilling are in the 60% internal rate or internal range even at today's depressed gas pricing. There is also a secondary horizon in the field, the Escondido, but this encounter can be cold mingled with the Olmos and further enhances the economics of drilling.
As the offshore wells to our proposed locations all have Escondido present, we feel it's highly likely we'll encounter this zone at our proposed locations as well. These proposed wells will be the first of 42 PUD locations we plan on drilling in the Sun TSH Field over the course of the next several years.
With respect to A&D, post the closing of our Mississippi transaction in late May, we've been actively screening and evaluating acquisition opportunities ranging as large from a million to several hundred million dollars in size. There continues to be many MLP suitable assets coming to market from both private and public companies. For the private, the key driver appears to be they're looking to cash out ahead of the impending changes in the tax laws, whereas the public companies, both large and small are rationalizing their material assets to reduce debt; a right response for higher return projects.
Over the past two months, we have made several offers of assets that would have been good additions to our portfolio, but we are not able to reach an agreement with the seller as to the value. We hope that as the year progress, some of these asset packages maybe offered again as the sellers realize the benefits of our proposal. We have been successful recently in adding two small bolt-ons in the Permian Basin near our existing operations; these acquisitions added roughly 75 barrels per day at a total cost of just over $3 million.
We'll continue to review these types of opportunities, while at the same time, allocating the majority of our efforts towards acquisitions of significant size that have the potential to drive distribution growth going forward.
Thanks again for joining us this morning and I'll now turn the call over to Richard for the financial review.
Thanks, Scott, and good morning.
We're generally pleased with our second quarter results. After the second quarter of 2010, we generated adjusted EBITDA of approximately $19.1 million up 44% over the amount earned in 2009 and up 3% over the amount earned in the first quarter of 2010. The increases are primarily attributable to the impact of the accretive acquisitions consummated in August and December of last year and May of this year.
We reported net income for the quarter of $3.9 million or $0.19 per basic unit compared to a reported net loss of $6.8 million or a loss of $0.54 per basic unit in the first quarter of 2009. However, as is normal, both quarter included special items which we excluded to arrive at adjusted net income so that quarter can be accurately compared.
The recent quarter included a $5.7 million non-cash loss on the acquisition of natural gas and oil properties. $524,000 of unrealized net losses in our commodity and interest rate derivate contracts and a $22,000 non-cash compensation charge for the unrealized fair value of phantom units granted to management.
2009 second quarter results include a $13.1 million in unrealized net losses and our commodity and interest rate derivate contracts and $1 million non-cash compensation charge for the unrealized fair value of phantom units granted to management. Excluding the net impact of the specific non-cash items mentioned above, adjusted net income was $10.1 million in the second quarter of 2010 or $0.50 per basic unit as compared to adjusted net income of $7.3 million or $0.58 per basic unit in the second quarter of 2009. Decline in our adjusted net income per unit can be attributed to a higher unit count based on our decision to use equity to fund the majority of the purchase price in our August and December 2009 acquisitions.
In addition, our depreciation, depletion and amortization on Mcfe basis increased from $1.65 in the second quarter of 2009 to $2.29 in the current quarter. Importantly, depreciation, depletion and amortization is a non-cash number and the increase does not impact our distributable cash-flow, which is why we have been able to increase our distribution per unit despite our adjusted net income per unit decline for the quarter.
Speaking of distributable cash-flow, we generated about one times coverage based on our increased distribution rate of $0.55 for the second quarter. This coverage rate was significantly less than the approximate 1.5 times coverage generated in the first quarter this year, but was expected. As I mentioned in the first quarter earnings call, we anticipated spending approximately $6.3 million in the second quarter on drilling and re-completions. And as it turns out, we actually spend $6.1 million which represents a little more than 40% of our 2010 budget.
Anticipating the increased cash-flow relating to this drilling starting in the third quarter and the full quarters contributions of the May acquisition, we continue to be comfortable with the revised 2010 guidance provided in May, which suggests our coverage should be in the 1.25 times to 1.3 times range for 2010.
Continuing on as Scott mentioned, we had some non-recurring lease operating expenses flow through in the second quarter, which cause LOE to increase to $1.86 per Mcfe this quarter as compared to $1.73 in the same period 2009 and $1.74 last quarter.
That being said, I would like to put things in perspective. Dollar amount of these non-recurring expenses is now large, about $350,000. However, on an Mcfe basis, that's $350 as a significant impact. Excluding those non-recurring items, the LOE for Mcfe would have been in the $1.70 range. We do anticipate LOE per Mcfe cost to be lower for the remainder of the year.
Our selling, general and administrative expenses were $1.1 million for the quarter, which represent a $1.8 million decline from the amount reported from the second quarter of 2009. $1.6 million of the $1.8 million decline is related to the difference in the amount of non-cash compensation expense recorded in each of these quarters. The non-cash compensation declined in 2010, principally related to the decline in the value of the phantom units granted to management pursuant to new employment agreements negotiated at the beginning of 2010.
In addition, in 2009, management finished divesting in the majority of the units they were granted upon their initial employment. And therefore, the amount charged for the non-cash unit compensation declined from $876,000 in the second quarter of 2009 to $212,000 in 2010. When we focus on the cash SG&A expenses we are pleased to note that despite our significant growth in the past year, our cash expenses have remained relatively consistent with those incurred in 2009.
I would like to shift the discussion to our leverage and liquidity. Our boring base was recently increased to $240 million after consideration of the acquisition in May. We currently have approximately $68 million available under the facility. I'd like to take a moment to discuss two key covenant limitation on commodity price hedging, which were amended in the recent re-determination.
Under the terms of the amended credit facility, Vanguard may enter into commodity price hedges with respect to the acquired production upon signing a purchase-sale agreement. We'll no longer have to wait until the acquisition is closed to enter into commodity price hedges. We can now lock in the expected cash-flow from the acquisition and not have to bear the risk when commodity prices fall between signing the purchase-sale agreement and closing the acquisition.
In addition, the amended credit agreement allows Vanguard to hedge up to 85% of their projected oil and gas production for total proved reserves. Previously our hedging was limited to 95% of the projected oil and gas production from proved developed producing reserves. As a result, in addition to hedging our cash-flow and existing producing wells, we can now hedge certain quantities of oil and natural gas that we anticipate producing from our drilling activities.
In essence, we can now fix the commodity price that we will earn from anticipated production from our drilling activities which should provide for a more predictable cash-flow in the future. In terms of our growth prospects, Scott already summarized our feelings that the acquisition market should be well supplied for the next several quarter. We feel confident that given access to capital at a reasonable cost, we will be able to successfully grow this company via acquisitions.
We appreciate our investors continued support and look forward to a great second half of 2010. This concludes my comments and we'd be happy to answer any question you may have.
(Operator Instructions) The first question comes from Joel Havard of Hilliard Lyons, please go ahead with your question.
Joel Havard - Hilliard Lyons
I caught commentary in the release about the drilling and plan for the second half, could you elaborate on that a little bit specifically as to the timing, is this going to be a busier Q3 than Q4. And thinking beyond that is it too early to think about or really to outline maybe the four major fields and how that schedule may look going into 2011?
Britt, why don't you take that question, you have a better handle on that.
Well, first of all as Scott mentioned we're completing well on Ward County, and we're kind of scheduled to frac at this week. There will be some costs there. This is a seven-stage frac. So we're looking at probably close to $1 million on that for this quarter. But the good news is we'll start to get the benefit from that well shortly within the (inaudible) frac and will start flowing it back.
We also have some wells that we would like to drill in the frontier stage, and we're looking at a frontier stage area, three vertical gaps wells in ahead of us, and that we have 50% working interest there. Those wells are probably gross about $800,000 each. And we'll have $400,000 from each of those.
We're going to hedge some less expensive wells out in Appalachia. So we plan about six vertical oil wells. Those wells gross cost are about $250,000, we have 40%, so we have a $100,000 from each of those totaling $600,000 for the Appalachia. And then we have one well that we believe will get drilled in Parker Creek this year, before the end of the year. And those are $3 million wells and we have roughly 50%, a little bit over 50% working interest. So it'll be $1.5 million to us there.
Joel Havard - Hilliard Lyons
Appalachia is out this year. Again, is it too early to be thinking about how some of these efforts will start to move going into the 2011?
Well are you talking about the impact to our production, Joel?
Joel Havard - Hilliard Lyons
Well, we'll get to that. The idea that Appalachia goes kind of side ways, another half dozen or so next year. Scott I think you think you made some comments about the pod's that are lined up right now. Does that mean Permian and South Texas, and Mississippi could each step up from the 2010 pace.
I think we could, but I think that the current plans are to be pre-measured in our development approach. And the idea is to reinvest enough capital on an annual basis to do our, the goal, trying to keep the production relatively flat, not pile on the drilling too much and burn up all of our distributable cash flow.
And I think it's also a function of not so much keeping our production flat, but keeping our cash flow flat. And that means drilling no gas wells and more oil wells. And that's what we'll do. And that may lower our Mcfe, but it will keep our cash flow consistent.
Joel Havard - Hilliard Lyons
I'm glad you all brought that one and now that you're very balanced on the production side, liquids versus gas. Scott your comments, that there is some activity bubbling, you haven't pulled the trigger on anything big yet, but do you guys have a, I think I've asked this question in the past, do you have a proclivity to keep moving increasing the oil content or is this really just to keep as Btu that you can find right now.
What I love is the cheapest Btu is the highest margin Btu's.
Joel Havard - Hilliard Lyons
I'm sorry I meant in regards to your future focus here?
I think Joes, and I think we should be pretty clear is that we're pretty opportunistic. If we see a quality natural gas field that we can acquire even in today's prices, we're going to look very strongly at those. We're not looking at oil deals to the expense of looking at gas fields. We're looking at all transactions and there's good opportunities in both types of the property sets.
And now it should prove to be a great time to be an acquirer of natural gas properties. We have made some pretty aggressive offers on some things, but again we're as I mentioned before were unsuccessful. So we don't have a stated goal of trying to do one or the other. It's really just a matter of the opportunities that we're looking for and type of transactions that we can get completed, and make the company better and help us achieve our goals.
The next question comes from Ethan Bellamy from Wunderlich Securities.
Ethan Bellamy - Wunderlich Securities
Britt, could you gives us an update on what the weighted average natural decline rate is for the asset portfolio as it stands now. And then Richard maybe comment on what is the level of maintenance CapEx to not just to keep rate steady, but keep reserves steady as well?
Well, our decline right now is 15%, that's for our PDP. And of course, with the additional drilling we'll try to maintain that as best we can, may not be perfectly flat but it will be close. Keep in mind that 15% includes some wells that are still in the hyperbolic portion of their production decline. So you got some at 5%, you've got some at 35%.
As far the CapEx, as that's required to maintain our cash flow. It's just what we've been focused on and not we forecast going forward, that's how we kind of look at our drilling. What do we need to do is to keep our cash flow consistent and still generate a good return on the wells that we're drilling. Now we're anticipating that somewhere in the $15 million range.
Ethan Bellamy - Wunderlich Securities
With respect to the financial reform legislation, and I know we've had some conversations in the past, just want to get your updated thoughts and maybe some intel and with regards to what your bank group has been telling you about, what if any impact we're going to have on future liquidity and the cost of commodity derivatives.
Well, I haven't had any specific conversations with my banks regarding that it at this point, so we certainly haven't been told what the ultimate impact will be, but it appears on a positive side that we won't have to post collateral ourselves, which obviously will help preserve our liquidity for allowing us to grow. But that's a very good thing.
Although, there is some talk about the banks themselves having to post collateral. So if they have to do that, they'll obviously pass on that cost us which likely will mean that we'll not be able to hedge. They may take a few sets off the tray to help pay for the cost of that collateral. I don't think it's going to have a significant impact, but you will see us obviously not be able hedge at the market if that's the case.
Ethan Bellamy - Wunderlich Securities
But so far not impact as you look out to maybe 2012 over some of the long dated derivatives?
Nothing's has been brought to our attention at this point.
The next question comes from (Richard Dearnley) from Longport Partners.
Given your hedges, when you net it all out, what do you think your hedging as a percentage of expected production looks like in '11 and '12?
I think on the natural gas side, we are hedged somewhere in the 80% level for '11. And at '12 we're not hedged at all in gas. On the oil side, we're probably in the 55% range or so in both '11 and '12, and then we're actually hedged in oil through '14 at about that 50% to 60% range.
And then, pro forma the acquisitions, do you have a guess as to what the production per day would be in '11 at this point?
In '11, I think we'll probably producing closer to 30 million a day on an Mcfe basis. But again, more of that is going to be oil, and so from a cash flow perspective, each one of those Mcfe is going to generate more cash flow.
The next question comes from (Eli Kantor) from Jefferies & Company.
At the beginning of the call, you had mentioned that the Ward County horizontal cost $5 million, essentially in line with the AFE. And I was just wondering if the $1 million that you're going to spend this quarter to complete the well is included in that $5 million cost?
Yes, it is.
(Operator Instructions) And the next question comes from Michael Blum from Wells Fargo.
Michael Blum - Wells Fargo
Just a couple of questions ago, just on the hedging, can you just give us your latest thoughts in terms of what are your plans to sort of lair and hedges and fill out the book, because I guess the hedging kind of trails off after next year or so.
As I mentioned, in 2012 we don't have any natural gas hedges out there. I've talked about it in the past that with the acquisitions we've dome and the hedges we have in place, we are comfortable and we will have half of that distribution coverage even if we put no new hedges in place at today's strip pricing, assuming that we have today's strip pricing.
So we've done a little bit of an option; we have a little bit of time to wait to see if things improve. We're also looking at, if we do a natural gas acquisition, we can layer in some hedges on our existing production at the same time as we do that acquisition.
Although, again hopefully it'll be a large enough acquisition that maybe we would keep our existing production unhedged, because as you know we can only do 85% of total approved. So if we do a large enough acquisition, those volumes could ultimately remain unhedged, just to stay within that company limitation.
And I think with respect to oil, what we did with this last Mississippi transaction, we put in a level of hedging that would support the acquisition and support our current borrowing base. And it just felt like there was room to the upside on oil, and as obviously is evidenced by today's market, at least for today it looks awfully good. And we're going to be looking for other opportunities; if we see some spikes to take advantage of it.
(Operator Instructions) There appears to be no other further audio questions at this time. Please continue.
Okay, again, thank you everyone for joining us today for the call. Again, it was a good quarter for the company. As Richard said, we're looking forward to a very exciting and hopefully a very good second half of the year. And we look forward to our next conference call in October. So thank you very much.
Ladies and gentlemen, this concludes the second quarter 2010 earnings presentation. Thanks for participating. You may now disconnect.
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