Vanguard Natural Resources' CEO Discusses Q2 2013 Results - Earnings Call Transcript

Aug. 1.13 | About: Vanguard Natural (VNR)

Vanguard Natural Resources, LLC (NYSE:VNR)

Q2 2013 Earnings Conference Call

August 1, 2013 11:00 AM ET

Executives

Lisa Godfrey - Investor Relations

Scott Smith - President and Chief Executive Officer

Richard Robert - EVP and Chief Financial Officer

Britt Pence - EVP, Operations

Analysts

Michael Peterson - MLV & Company

John Ragozzino - RBC Capital Markets

Abhishek Sihna - Bank of America Merrill Lynch

Kevin Smith - Raymond James

Praneeth Satish - Wells Fargo

Daniel Guffey - Stifel Nicolaus

Amy Stepnowski - Hartford

Operator

Good day ladies and gentlemen, and thank you for standing by. Welcome to the Vanguard Natural Resources Second Quarter 2013 Earnings Call.

During today’s presentation, all parties will be in a listen-only mode. Following the presentation the conference will be opened for questions. (Operator Instructions) This conference is being recorded today, August 1, 2013.

I would now like to turn the conference over to Lisa Godfrey, Director of Investor Relations. Please go ahead, ma’am.

Lisa Godfrey

Good morning, everyone and welcome to the Vanguard Natural Resources, LLC's second quarter 2013 earnings conference call. We appreciate you joining us today. On the call this morning are Scott Smith, President and Chief Executive Officer; Richard Robert, our Executive Vice-President and Chief Financial Officer, and Britt Pence, our Executive Vice President of Operations.

If you would like to listen to a replay of today’s call it will be available through September 1, 2013 and may be accessed by dialing 303-590-3030 and using the pass code 4631199#. 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 online for approximately 30 days.

For more information, or if you would like to be on our email distribution list to receive future news releases, please contact me at 832-327-2234 or via email at lgodfrey@vnrllc.com. This information was also provided in Wednesday’s earnings release.

Please note the information reported on this call speaks only as of today, August 1, 2013. And therefore you are 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 10-Q that will be filed later today and will also be available on our website under the Investor Relations tab, and on EDGAR.

Also on the Investor Relations tab of our website, under Presentations, you can find the Q2 2013 earnings results supplemental presentation.

Now I would like to turn the call over to Scott Smith, President and Chief Executive Officer of Vanguard Natural Resources.

Scott Smith

Thanks, Lisa and welcome everyone this morning and thanks for joining us on the second quarter conference call. I'll start off with a brief summary of our operational results for the quarter, then we’ll review our capital spending year-to-date and our plans for the balance of the year.

Lastly, I’ll quickly discuss our acquisition outlook, and Richard will proceed with the financial discussion and then we’ll open the line up for Q&A. First I'll review our production results for the quarter.

Average daily production for the second quarter of this year was 36,477 BOE per day, up 10% over our first quarter production of ‘13, and almost three times a 12,338 BOE per day produced in the second quarter of 2012. The significant increase in production from 2012 is a direct result of the acquisitions closed last year and the Range Permian acquisition, which closed at the end of last quarter.

Additionally, as mentioned on our last conference call, we had a significant amount of capital spending that was accelerated into the first quarter and we saw some of the benefits of the spending program during this quarter. Production for the quarter was approximately 66% natural gas, 24% oil, and 10% NGLs.

That being said, even with our significant increase in natural gas production, our revenues are still more weighted to liquid with 60% coming from oil, 9% from NGLs and the balance from natural gas.

Turning to our capital spending, we continued to be active during the second quarter. As I mentioned on our last call, we put together a capital budget of approximately $55 million for the year.

Our capital budget is focused on deploying capital on high rate of return projects that are aimed at offsetting the cash flow impact of the natural declines in our oil and gas production.

I want to reiterate that we focus our capital spending on maintaining cash flow and not production. As we all know, a barrel of oil is not equal to 6 mcf of gas on a value basis. And as an MLP, our business is paying out a majority of our cash flow to unitholders, so our focus is on cash flow, not production.

Over the course of the year our production mix will change and so we are increasing our overall production to our capital project but our gas production is declining.

During the first quarter of the year we spent just under $15 million which was ahead of our originally anticipated amount of $10 million.

Although we spent approximately $5 million more than we’d originally forecast majority of that variance was expected to be in the second quarter or was due to additional non-op AFEs that came in. As expected we saw a reduction from the $19 million of drilling capital that we had originally forecasted being spent in our guidance for the second quarter by approximately $5 million.

All in all we spent approximately $30 million through June which is right in line with what we had projected for the first half of the year. The breakdown of the capital spending during the quarter is as follows.

Consistent with our capital budget almost half the capital spent during the quarter was in connection with our Arkoma Woodford and Fayetteville assets. During the quarter we completed five operated Woodford wells with an average seven day IP rate approximately 3200 Mcf per day and 380 barrels of NGLs per day. Our working and net revenue interest in these wells is 41% and 32% respectively.

Additionally, Vanguard participated in completion of four other Woodford wells with an average working interest of 13% which were operated by BP. These wells are in the dry gas window and had an average seven day IP of 8700 Mcf per day which is an excellent result.

In regards to the Fayetteville activity, we have participated in the recompletion of eight non-operated wells where we had an average working interest of just over 5%. During the second quarter, we also kicked off our Permian recompletion frac program which was upside we’d identified as part of the Range acquisition that closed in the first quarter.

Thus far for this year - during the quarter we have completed two fracs, one asset job in the Eunice field and another frac that was pumped this week. The initial results have been very good and we look forward to continuing this program in the future. We have budgeted work to recomplete and frac at least 12 more wells before year end at an average cost of approximately $240,000 per well.

Similar to last year we have continued our Elk basin frac program, where we've achieved great success. This year we frac’ed 8 wells, with 7 currently on production, our average uplift from these frac jobs has been about 40 barrels per day and the average cost has been right at $300,000.

Looking at the second half of the year, we're anticipating an increase to our capital, to our full year capital budgets of between $5 million and $10 million or $60 million to $65 million for the whole year. The increase is primarily driven by the activity associated with the range Permian acquisition as well as initiating a 2 rig drilling program in the Woodford Shale that we hope to begin in August.

Let me quickly go into some more details on what we have planned. Based on the operational results for our initial Woodford program in recent non-operating completions, we plan to continue our JV with Jones Energy which covers 10 township ranges and include most of our high BTU Woodford acreage.

This covers over 360 sections where we have 13,000 net acres. The Vanguard and Jones Woodford teams have identified and ranked the 10 most attractive sections and as mentioned previously we're planning a two rig continues drilling program starting this month.

The expected average IP per well is 3.6 million a day and 290 barrels of NGLs. The average gross cost per well is expected to be between $3.8 million to $5 million which is dependent on the number of frac stages and the length of the laterals that we’ll be drilling.

Our average working interest will be approximately 25%, we expect the rate of return of roughly 35% based on current strip pricing. However, I do want to point out that we don't have any production forecast to come on in line this year, so approximately $11.3 million will be spent although we will not be seeing any production.

In the Fayetteville, South Western and BHP appear to be increasing their development program due to the higher gas price environment and better than expected results in their recent wells. So we continue to see additional AFEs come in. I can't say enough that during our evaluation of the Antero transaction we gave no value to the Fayetteville [inaudible] so there has been a great [inaudible] activity not only pick up but come in with the results that we have seen today.

Lastly, as you would expect across our portfolio we received AFEs from our non-operated partners for additional project in the second half of the year in areas where the first half spending netted excellent results. This additional CapEx is expected to be about $3.5 million. While we have a significant amount of additions to our CapEx programs, we do plan to cut most of the remaining 2013 Bakken CapEx plan that we had originally planned due to the high investment dollars and the low projected rate of return for near-term development.

This resulted in a decrease of approximately $9 million from our capital program. All-in-all, we are very pleased with the results we are seeing from our capital program in the first half of the year and are excited to increase our budget by the $5 million to $10 million to focus on replicating the results in the third and fourth quarters.

Please note that although we do expect to ultimately grow our cash flow as a result of these increased expenditures, it is currently not our intention to classify any of our capital as growth capital. While this may negatively impact our reported distributable cash flow and distribution coverage for 2013 we feel it’s important to keep our reporting simple, albeit conservative. However, if in future years we chose to spend a material amount of capital on growth, we may be forced to change our reporting philosophy.

With respect to acquisitions, we've been very busy during the quarter evaluating numerous transactions of various sizes and remain disciplined in our bidding approach to ensure the assets we successfully acquire will be accretive to our unitholders. [Inaudible] a very competitive market for MLP type asset I think we're well positioned to be very competitive for the asset packages we know are coming to market.

With almost $900 million of liquidity available to us, we can move swiftly in this acquisition market. As you know, several of our peers have announced large acquisitions in the second quarter or engaged in previously announced transactions so we think at least for the next few months, we're in the enviable position of having a significant amount of liquidity and expect less competition for quality asset acquisitions.

With that, I turn the call over to Richard for the financial review.

Richard Robert

Thank you, Scott. Good morning everyone. Please excuse my voice, I am recovering from a cold but I’ll try and get through this so that you can understand me. As Scott mentioned, during the second quarter of 2013, we were active in the equity markets and more importantly added a new financing tool for our future growth.

First, we closed a $7.3 million common unit offering for net proceeds of approximately $200 million. This was an opportunistic equity rate to take advantage of the strength in our unit price. Additionally, we're very excited to have added a new financing tool to our portfolio, perpetual preferred equity. In June, we closed our offering of Series A cumulative perpetual preferred equity of 2.5 million units with a 7.875% coupon for net proceeds of approximately $61 million. These preferred units are redeemable by the company after 10 years from the date of issuance. This is one of the first publicly offered preferred unit offerings by an MLP, but I don’t believe we will be alone in issuing the security for very long.

Based on my discussion with some typical preferred buyers, they would welcome the opportunity to include MLP preferred units in their portfolio and from a company perspective I think it makes a lot of sense. The preferred yield is more than a 100 basis points lower than our common unit yield and has a fixed distribution and thus is a much less expensive alternative to issuing common equity. As I regularly mentioned, long-term financing of our growth strategy is the major challenge we face and adding preferred equity opens up more avenues for our future need.

Let me first turn to our financial results, we reported adjusted EBITDA of just over $80 million for the second quarter, an increase of 81%, when compared to the $44 million reported in the second quarter of 2012, and an increase of 11% from the $72 million in the first quarter of 2013.

As I mentioned on our last conference call, we were forecasting some [lift] [ph] in the oil differentials in the second quarter especially in the Big Horn and Permian Basins. I am pleased to report that in the second quarter we saw significant improvements in both of those areas.

Oil differentials came in at about $3 in the Permian and just under $14 in the Big Horn. On a companywide basis, our published guidance anticipated a negative differential of around $8 for the second quarter and the actual result was better at just under $7.

I wish I could say the same thing happen to our natural gas liquids or NGLs for short but that is just not case. NGL pricing continues to decline. Our NGL basket realization has decreased from 44% of WTI in the first quarter of 2013 to 36% of WTI in the second quarter equating to almost $2.5 million in lost revenues or put it in a different way, was the difference between 1.1 times distribution coverage this quarter versus the 1.05 times coverage we did report.

Both NGL and natural gas realizations are challenges that face our entire industry but there is a silver lining to this situation. The continued decline in NGL realizations creates opportunities to buy natural gas assets which include an NGL stream at more attractive valuations from a long-term perspective.

Not only are we able to acquire these assets with little to no value being placed on undeveloped locations because it is not economic to drill at current prices but we are giving ourselves an opportunity to participate in the pricing recovery over the long-term. There are a number of demand catalysts that should allow natural gas and NGL prices to recover in the three to five year range which we hope will allow us to replace natural gas hedges at higher prices and NGL pricing improvements will have an immediate impact on revenue as that revenue stream is largely unhedged.

Now turning to lease operating expenses and selling, general and administrative cost, I won’t rehash all the numbers in the release but I will point out that our LOE and SG&A through the first half of the year are running at expected or better than expected levels as compared to our 2013 guidance.

In terms of our distributable cash flow, the second quarter of 2013 totaled approximately $48 million or $0.65 per common unit generating a coverage ratio of 1.05 times based on our current distribution of $0.205 per month or $0.615 per quarter.

As, Scott mentioned, we spent less than anticipated in the second quarter due to an acceleration of our projects in the first quarter. For the first half of the year, we are in line with our forecast for capital spending. For the second quarter, we reported adjusted net income of approximately $19 million or $0.27 per common unit. Our GAAP reported net income was approximately $81 million or a $1.14 per common unit.

Next, let me move on to our hedging portfolio, as I regularly note, we continuously evaluate our hedge book and opportunistically add to our current positions. We were quite active in the second quarter adding to our hedge positions primarily as a result of taking advantage of the strength we saw in oil pricing. During the quarter, we began opportunistically adding hedges in 2014 and 2015 in the form of three-way collars and swaps where we sold $70 puts to enhance swap price. Of note we added three-way collars for 500 barrels per day at a weighted average floor price of [$90] [ph] and a ceiling of $96.70 in 2014 and 2015.

Additionally, we entered in swaps for 1,000 barrels a day at a weighted average price of $90 by selling $70 puts in 2015. In terms of percent of production hedged, 2013 expected oil production is a 100% hedged, 2014 is 95% hedged and 2015 is 57% hedged all at a weighted average price of $92.81 per barrel. As is our strategy, we continue to opportunistically layer our own hedges in 2015 to improve our hedge portfolio.

On the natural gas side 2013 expected gas production is 92% hedged, 2014 is 85% hedged and 2015 is 94% hedged, 2016 is 96% hedged and the first half of 2017 is approximately 47% hedged, all at weighted average prices of about $4.60 which we are hopeful that by 2017 we can rehedge future natural gas production at comparable levels thus avoiding a cash flow cliff.

Over the last month we and our peers have received a lot of attention in regards to our hedging strategy. As is indicated by the different instruments we use in our own portfolio specifically on the oil side, hedging can be done in many different ways. No strategy is necessarily better or worse than the other, just different. At Vanguard, we structure our hedging programs to be mostly costless and thus less capital intensive than some of our peers. We do not buy puts, but rather we sell oil puts to finance the costs of our oil hedging strategy, sometimes in the form of a three-way collar or using the sold put premium to enhance the price of a fixed price swap as I just discussed.

We feel that it is a more cost effective way to improve our hedged portfolio, but it does expose us to some cash flow risk should oil prices decline below $75 for any extended period of time. Clearly we don't feel that it is a realistic scenario and is worth taking that risk. Our approach on the natural gas side is quite different and quite simple. We only have fixed price swaps at the moment.

More details regarding our current hedge portfolio and percent hedge as well as the recent hedges entered into for the Range Permian acquisition can be found in the supplemental Q2 2013 information package posted on our website.

Let’s turn to our credit facility and liquidity for a quick update. In connection with the closing of the Range Permian acquisition on April 1 and our semi-annual borrowing base re-determination process, our borrowing base increased to 1.3 billion in April, but we elected to keep commitment at 1.2 billion since we did not currently need the additional liquidity. This lowers the fees we have to pay upfront as well as on the unused commitments. However, our credit agreement is set up such that if we were to need the extra capacity, we can ask for the commitment to increase to the higher borrowing base amount without the need to go through a long credit process. Additionally, we extended the credit facility an additional year and half so now it matures in April of 2018.

As previously mentioned, we cumulatively raised approximately $261 million in the second quarter via common and a preferred unit offer. All proceeds were used to repay debt under our revolving credit facility. As of July 31, Vanguard had $420 million in outstanding borrowings under the revolver, which provides us with almost $900 million in current liquidity after taking into consideration the $1.3 billion borrowing base and $50 million in cash.

Now, I'll turn quickly to give you a little update on our outlook for 2013. As Scott mentioned, we have increased the capital budget to between $60 million and $65 million, which encompasses capital associated with the Range Permian acquisition, a two rig Woodford drilling program and the other non-operated capital. Because of these changes as well as the multiple capital raises we have completed in the second quarter, our guidance for the year has also changed. Assuming the increase in our capital spending, but updated for actual results for the first half of the year, current strip prices, the range Permian acquisition and our recently announced distribution increase of $0.25, we anticipate our EBITDA to be in the range of $320 million to $325 million and our distribution coverage to be approximately 1.05 times for the full year 2013, absent any new acquisitions.

I will reiterate that this includes the full burden of the capital we raised in the second quarter. In light of the recent turmoil the upstream MLP space has encountered, we feel very fortunate to have raised money that we did, when we did. As Scott mentioned, many of our peers have recently announced large acquisitions and now being one of the few public upstream MLPs with a significant amount of liquidity puts us in an advantaged position in the acquisition market at least in the near term. We are confident that we will have an active second half of the year on the acquisition front, which should improve our distribution coverage for this year and going forward.

This concludes my comments. We would be happy to answer any questions that you may have.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from the line of Michael Peterson with MLV & Company.

Michael Peterson - MLV & Company

Just a couple of questions if I would, if I can rather. First, there’s certainly been a lot of discourse regarding maintenance capital. Richard I think it would be helpful for everyone if you could frame the benefit either in terms of CapEx savings or perhaps a lower decline rate from the escalated working interest component of the Barrett acquisition?

Richard Robert

Sure, Michael, that is an important aspect of that transaction. We do get the benefit of an increased working interest every year, we started at 18% on the -- interest on the Piceance Basin specifically. We start at 18% then we go to 21% next year and 24% and finally 26% in 2016 and the purpose of that was to recognize that there was a higher decline on those assets and drilling in that area didn’t make any sense, so we have to have some other mechanism to maintain our cash flow and that is what we came up with. When you combine that with an increasing price deck that we are able to hedge into, our anticipation is spending no capital there and having very consistent cash flow every year. So that was a good transaction for us, it was a creative way to make a higher decline property so attractive.

Michael Peterson - MLV & Company

With regard to the Permian assets, you talked a little bit about some of the encouraging recompletion results that you’ve received thus far, also some expectation on our part I think of a little bit of operating and overhead efficiency, have you started to see any of that or are we still little bit early to have solid results?

Scott Smith

With respect to the project that we have already done, we saw about 20 barrel per day lift, I mean new wells we’re making like a barrel a day and now after the recompletions or the treatments these two wells are now making about 20 barrels a day on a net basis. So quite a nice increase and the cost came in much low, little bit lower than what we had expected. So we're very pleased with that. We have a very large inventory of these projects, numerous years’ worth. So we are very excited about that.

With respect to efficiency, we kept the Range field people which is typical in every acquisition that we do and so you keep the continuity of operations. So from a supervision standpoint, we already had - our Permian Basin team was able to put this under their umbrella very quickly and it's been really a pretty very seamless transition and we've also been fortunate to add a new engineer with Permian Basin experience, who is dedicated just to enhancing these assets.

Richard Robert

And just to put it in a different perspective, 20 barrels doesn’t sound like a lot and it's not a lot, it's not - each individually doesn't move the needle that much, but when you consider about a three month payout, it is a very good utilization of our capital.

Operator

And our next question comes from the line of John Ragozzino with RBC Capital Markets.

John Ragozzino - RBC Capital Markets

Richard, can you comment on the levels of institutional demand that you saw for the preferred equity offering and then if you don't mind just give me a quick reminder on how the rating agencies actually treat those types of transactions?

Richard Robert

Okay. Let me answer your first one, your last question first so I don't forget it. Rating agencies consider it - they give you 50/50 debt equity allocation on preferred units. But obviously from our perspective, we consider it equity and it's perpetual equity and we consider that we have no obligation to repay, so from our perspective it’s permanent equity capital irrespective of how the rating agencies look at it.

As far as the institutional interest, we weren't trying to raise a lot of money, frankly, we already had a lot of liquidity as we’ve talked about in detail on this call. It was really, I just wanted to have another trading security out there. So doing a $60 million raise didn't attract a lot of institutional interest. It was principally retail oriented, but I'm hopeful that as this security gains more acceptance, as we see some other MLPs issue this type of securities, I think we will see, and obviously we issue a larger amount and there's more liquidity, I do believe based on my discussion with some of those institutions that they would be very interested in buying the security.

John Ragozzino - RBC Capital Markets

With respect to the recent fourth amendment to the credit facility I believe you may have touched upon this last time we caught up but can you just give us a reminder on what you mean when you say that there was some increased flexibility with respect to the hedging constraints on the facility.

Scott Smith

Well it principally relates to the amount of hedging we can do on anticipated production which allows us to be - to more actively hedge our drilling programs, if you have a capital program you're anticipating production to come from that capital program you want to go ahead and hedge that into the future, we were limited in the past by a percentage, a fairly low percentage that was attributable to PUD. So now that they've raised that percentage we can do it better, we can do a better job of ensuring that our drilling programs will receive -- or will generate the returns that we think they will.

John Ragozzino - RBC Capital Markets

Does it also apply to any anticipated production between the time of signing a PSA and closing an acquisition?

Scott Smith

No.

John Ragozzino - RBC Capital Markets

And then with respect to the Permian acquisition, can you give us a little more detail as far as what the net acreage position was, what specific counties that was across and then if there is any limitation across the depths in terms of rights?

Scott Smith

Those properties, the New Mexico properties are in the Eunice area, which is in Eddy County – no, it’s Lea County, Lea County with the right next to each other and then the other area, the Powell Ranch field which is in Glasscock County. The every lease is different, I wish I can tell you it's across the board but yes we do have depth restrictions on some of it, but not all of it. And as far as a big acreage position, it's not very large. It's probably a couple thousand acres total. Again, it's all HBP and again the big upside for us that we had identified in the deal is really just going in to these old well bores, a lot of them were drilled in the 50s, and 60s and 70s and just going in and adding zones that are productive within the field but had never been perforated in these wells.

And obviously I feel quite good about our early success because we're going in, again, wells that are very old in established fields and spending very little money for great results.

John Ragozzino - RBC Capital Markets

Okay, and then just one more for me. You touched a little bit on this earlier with respect to the hedging strategy and gave some helpful detail regarding the actual mechanics of it. Can you do the same with the actual calculation of your maintenance capital expenditures and perhaps just lay that out so people can make their own judgment as to whether or not they think it's a valid mechanism or not?

Richard Robert

Well, as Scott mentioned, our intention as it relates to our maintenance capital is to replace the cash flow that we see as a result of declines in our existing [BP] [ph] properties. And so when we establish our capital budget each year, our engineers look at the profile, the decline profile on our existing assets, they assign a value to that production decline and then they go to the undeveloped acreage inventory and start prosecuting those - that drilling and when they offset that cash flow decline they stop. I mean that’s about as simple as it gets, however, it's not simple because you have changes in pricing, you have new acquisitions with different undeveloped acreage that you may want to replace, you have results that you've got to take into consideration, you don't keep drilling wells that aren't productive, I mean you make changes throughout the year and so it's not a static sort of evaluation.

John Ragozzino - RBC Capital Markets

Alright, that's it from me, thanks a lot guys and I hope you feel better, Richard.

Richard Robert

So do I.

Operator

And our next question comes from the line of Abhi Sihna with Bank of America. Please go ahead.

Abhishek Sihna - Bank of America Merrill Lynch

Hi, good morning guys. Just a couple of questions, first is with regards to your acquisition strategy and outlook, could you provide some color on the numbers and versus what you had last year. I know you have a lot of liquidity available and you have only quarter of million dollars of acquisition done this year, so is there any number that we should gauge by in the range or something that you can provide?

Scott Smith

I think last year we did just over $800 million and we are at around $300 million this year and I think what we stated earlier, that's been consistent that we'd be disappointed if we didn’t do what – Abhishek, what we did last year, so obliviously we've got some heavy lifting to get done if we need to put away another $0.5 billion this year.

But on the positive side there is lot of opportunities in the market, sellers know that we have the financial wherewithal to transact and they know we're a good buyer, we're easy to work with. So again we're seeing lots of opportunities and are optimistic with what we have in the future, for the next six months.

Richard Robert

Yeah, and I would just add to that, the quality of our deal flow I really do believe is improving. People are - we're not having to participate in large widely marketed auctions. We are getting a little bit more direct seller contact where they’ll put a small group together to evaluate a package that they want to sell, so I think our potential hit rate is going to improve.

Abhishek Sihna - Bank of America Merrill Lynch

Sure, and just as a follow up, I mean the CapEx of $55 million that you provided is and correct me if I’m wrong, I believe it’s all maintenance CapEx. So if that is correct why, I mean what's your strategy behind putting some of that cash towards the growth CapEx, I mean you have good percentage of PUDs available and you have good liquidity available?

Scott Smith

Well our intention right now is just to maintain our cash flow. We look at our PUD inventory as our insurance policy, should the capital markets dry out and we are not able to raise any liquidity, we look at that inventory as our insurance policy that we can continue generating cash flow necessary to pay our distribution for the long-term.

Now, things could change, we certainly have high hopes for our Woodford drilling program and it's certainly possible, and we talked about that, we talked about it with our Board. There is a possibility down the road that we will institute a growth capital wedge but for now we haven't. And I say if we decide to go down that path, it's going to be a meaningful growth capital where it's not just a very small single-digit kind of growth capital.

Richard Robert

The dollars that we just added now, I don't think were meaningful enough to highlight that it’s growth capital.

Operator

And our next question comes from the line of Kevin Smith with Raymond James. Please go ahead.

Kevin Smith - Raymond James

Scott or Britt would you mind walking me through the timing of when these five wells came on - Woodford wells came online, I think you had two in April last we talked and I assume the other three came on pretty subsequently after that?

Scott Smith

Sure, I'll let Britt take. Britt you'll handle that.

Britt Pence

Sure. We frac’ed all five basically at the same time we drilled them; we drilled back-to-back and then after we finished the drilling, we came in and we frac all five. So they all came on approximately within the same period of time.

Scott Smith

Which was?

Britt Pence

Which was the April-May period. So of course you have some flow back you know as they clean up but it was a second quarter increase.

Kevin Smith - Raymond James

Okay, got you, and then can you walk me through what your next drilling program is looking like so you got - in the Woodford specifically, you got two rigs coming on you said in October, I assume those are going to be three to four well pads as well. And then are we expecting to see all of them then come online in January-February timeframe?

Britt Pence

Yeah, you pretty much, we are looking at – we’re hoping to have the first rig come in late, at the end of the month, could be September, early September, we’ve two rigs running before the end of September hopefully we will get seven maybe eight wells in drilled this year and we are looking at about four to five wells for inspection before we go back and complete them all at once. So January-February timeframe would be when the production comes on from it, and that's what Scott was saying earlier we are going to spending quite a bit of capital in the Woodford this year but we are not going to see the benefit until next year. So that's something we need to factor in.

Kevin Smith - Raymond James

Got you. But when you do see a production, you are going to see a pretty good ramp if those wells are basically the same ones because you are talking about eight to 10 wells or gross wells coming online?

Britt Pence

That's right, that's correct and then we will have depending on each sections, we will have little different working interest but we are at 30% to 40% working interest probably.

Scott Smith

I think we said around 25. Yeah, everyone is different, some are higher, some are lower and then again we are doing this with Jones and it covers quite a few sections.

Britt Pence

Yeah, and then we are going to have - and the wells on a gross basis come in approximately $3 million a day and so we will see a nice increase once we start the frac programs early next year.

Richard Robert

Although we're contemplating some larger laterals on these new wells, so the production potentially could be better than what we’ve seen in the past and the cost might be a little bit higher as well.

Kevin Smith - Raymond James

Got you. Would – do you mind sharing the AFEs or what you expect AFEs for these to be?

Scott Smith

Well, I think I said that in my part of that call, it’s $3.8 million to $5 million on a gross basis. $5 million would be the longer laterals with more frac stages. We’re talking about the new – the wells that we're going to prosecute. The five wells that did come in were in the 3.8 type cost range.

Kevin Smith - Raymond James

Got you. And then just a house - kind of cleaning item. LOE per unit decreased a good bit this quarter. Did you have any few like lower workovers in 2Q or should we think of this as kind of a sustainable run rate?

Scott Smith

Yeah, I mean, one of the things that we’ve benefited from in these acquisitions is some synergies in terms of operating personnel. On the Barrett transaction, we took that headcount from about 45 down to 26 and on Range, we took it from 11 to 7 and we're doing some things in the field too that are lowering some of our cost for converting some of our diesel engines to gas.

Britt Pence

Put in some salt water disposal reduced cost there as well.

Scott Smith

Hopefully, that’s totally we're going to be staying in this area that we're at now, it's not a one-time deal.

Richard Robert

Yes, I think it's a fairly good run rate especially when you consider we had some fairly significant P&A liabilities this quarter as well. So all-in-all, I think it should be a pretty good run rate.

Operator

And our next question comes from the line of Praneeth Satish with Wells Fargo. Please go ahead.

Praneeth Satish - Wells Fargo

Just a couple of quick questions. I guess, first, could you just comment on the depth of the preferred equity market and if you had to what do you think is a maximum amount that you could raise in this market in one offering?

Richard Robert

Well, Praneeth I mean, before we issued our preferred, there was no depth in that market because it hadn’t been done before, and that was the biggest challenge was finding underwriters who are willing to try and place the new product. And frankly, the day we came, the day we went out with this offering, it turned out to be a pretty bad day in the market. So at $60 million it was again largely retail oriented, I think it’s going to take time for this product to get acceptance, and I don’t believe there should be a problem getting acceptance, when you look at the REIT industry which is obviously similar to ours, in terms of entities that generate a lot of cash flow and pay out to their investors the REIT issue this preferred all the time, I mean that is the staple of their capital structure.

So I think it’s going to gain some acceptance over time and I am hopeful the next time we come out, we will do a $150 million. Now we at least we have a comp - and I am happy to report that it’s traded quite well. It closed yesterday at $25.80, $25 par, so it’s trading above par and that would suggest that there are people that like that product.

Scott Smith

I think Richard mentioned before we understand there is more MLPs coming…,

Richard Robert

Looking at it?

Scott Smith

I didn’t say that but well if there are; in the event it does happen, obviously, the more traction that we get in the market and there is more issues, more likelihood it’s going to be more accepted and deal size can go up.

Richard Robert

Yeah, my understanding Praneeth is that there are other MLPs that are contemplating issuing preferred; whether it comes to pass I don’t know but I know they are contemplating it.

Praneeth Satish - Wells Fargo

Got it, and just a point of clarification, you mentioned that the rating agencies treat the preferred as 50% debt equity; how do the lenders look at this with respect to covenants?

Richard Robert

Our expectation is that it’s a 100% equity.

Praneeth Satish - Wells Fargo

Okay, and just one last one, just housekeeping, what is your current decline rate right now?

Richard Robert

It is in the 13%, 14% range.

Operator

And our next question comes from the line of Dan Guffey with Stifel. Please go ahead.

Daniel Guffey - Stifel Nicolaus

You mentioned that you are scaling back really stopping investment in the Bakken, just curious are you looking at that as a divestiture candidate?

Scott Smith

It’s not on the market, it’s really, it is decent cash flow again it’s, lot of what we have is not really Bakken what we have in the Williston is more conventional assets, but we did pick up some Bakken, there were some activity where we farmed out some acreage and participated in a few wells. Again, I think our decision to scale back is really the well cost have continued to stay high and the results although they look pretty good on paper, just don't generate what I would – we consider a sufficient return for the risk that we're taking. So therefore we just made the decision it's better to work with the operators who want to drill wells, we will exchange our interest and retain an [over rights] [ph] so we still have some economic benefits, but let them go ahead and take the drilling risk.

And many of these are public companies, again just the way they look at their business, it's all about growth, I'm not, they may not be as concerned about the rate of returns as we are. So, it just doesn't really make sense for us to be participating in that type of well cost for the mediocre returns that we’ve seen.

Richard Robert

Yeah. And I would suggest if this acreage had been contiguous and we could sell it as a package that would be something we would have considered, but it wasn't contiguous. And so we are forced to find out who the best operators are in the different areas and kind of work with a lot of different people up there. So to answer your question, yes, it would have been a divestiture candidate had it been contiguous but it's not. But if you know somebody who wants to buy it then…

Daniel Guffey - Stifel Nicolaus

Okay. Thanks guys. And then in the past you’ve talked about before the Permian acquisition kind of focusing on gas acquisitions and in your prepared remarks you talked about NGL prices being depressed and having a long term opportunity there. Are those the type of acquisitions you guys are focusing on in the second half of ‘13, gas and NGL rich and is that where you're seeing a lot of the activity in the market?

Scott Smith

Definitely the latter that is we're definitely seeing more of that type opportunity in the market. You see the publicly announced deals people have announced [exits] [ph] out of the gas and NGL rich plays in the Anadarko basin and at the Texas Panhandle. We continue to see that in other areas as well. I mean there are still Permian deals but a lot of them have a lot of undeveloped opportunities in drilling and to be honest you know we are typically not very competitive in that type of process against private equity that this again has a huge - where you can deploy a lot of capital and that's the 100% or more of the cash flow to develop the assets. We were not going to be competitive in that type of process. So again we are seeing a lot of gas and NGL rich type opportunities so and I imagine we are going to continue to see that through the balance of the year.

Daniel Guffey - Stifel Nicolaus

And then just one last one for me, the $320 million to $325 million of second half EBITDA that you guys are projecting, can you provide the differentials you guys are assuming for each commodity?

Richard Robert

Well, let me be clear that $320 million to $325 million is full year 2013. I wish it was the last half of the year. We will get a $1 billion transaction done and then maybe, but the differentials, I can tell you our commodity prices are obviously the strip, but the differentials are – we’re anticipating about $8, a little over $8 on the oil and are anticipating NGL realization of about 40%, natural gas realizations of about 58% be specific.

Operator

(Operator Instructions). Our next question comes from the line of Amy Stepnowski with The Hartford.

Amy Stepnowski - Hartford

Just following up on the last question regarding differentials and the information you provided earlier where oil differentials you are able to improve upon and I guess the $8 is that the estimate for the full year for the differentials and if you could just give us any insight into what you are able to do to achieve that and if you think there is room for further improvement going forward?

Richard Robert

As you may recall, the oil differential on a company-wide basis was almost $14 in the first quarter and this quarter, it was a little under $7. So we're anticipating little over $8 in our forecast for the rest of the year only to be a little conservative; the big one which is a lot of that differential for us is actually continuing to improve. So we're hopeful that our oil differentials are more conservative than they need to be, but they change quite dramatically, quite quickly.

So I don’t want to get ahead of myself and get too confident about that. And it's not a function of what we've done. We certainly are looking at alternatives in areas that we can't hedge that differential - in the Williston and Bakken, or the Williston and Big Horn in particular, I mean we are looking at potentially putting in fixed price physical contracts which will help stabilize that volatility. In the Permian, we did put in hedges after that first quarter blow out, so we do have some certainty on that Permian.

And I mentioned the Permian differential is $3 or so this quarter, I expect that to continue to come in as well, because of the hedges that we put in place. I think the average hedge is somewhere in the $1 range, so those were kind of things that we are doing to try and mitigate that risk, but it’s not specifically, we haven’t done anything per se, we can’t take any credit.

Amy Stepnowski - Hartford

Okay. I was just following up from, I thought at the end of last year quarter you had talked about that there was aside from these Permian hedges something in particular that you might be looking at some contracts etcetera that to try and bring it in, but this is just obviously we’re seeing differential across coming in, it’s narrowing?

Scott Smith

We did put those Permian hedges in place and that’s certainly helped. So we were proactive, we could be proactive, but we are still looking for alternatives that include rail and fixed price physical contracts in the Big Horn where we have a good relationship with Marathon and they are the 800 pound gorilla in that area and they are also frustrated as well with the volatility, so we may run under a [inaudible] as well, we are jointly looking for alternatives.

Operator

And I am showing no further questions at this time. Please continue with any closing remarks.

Scott Smith

I appreciate everyone joining us on the call. Again, I don’t think we can reiterate enough. We have a lot of liquidity. We are looking for opportunities and are excited about the second half of the year and putting this money to work on behalf of our unitholders. So again, thanks for joining us and we will visit again in November.

Operator

Ladies and gentlemen, that does conclude the Vanguard Natural Resources second quarter 2013 earnings call. Thank you for your participation. You may now disconnect.

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