Vanguard Natural Resources' CEO Discusses Q3 2012 Results - Earnings Call Transcript

Nov. 1.12 | About: Vanguard Natural (VNR)

Vanguard Natural Resources, LLC (NASDAQ:VNR)

Q3 2012 Earnings Call

November 1, 2012 11:00 AM ET

Executives

Lisa Godfrey – Director, IR

Scott Smith – President and CEO

Rich Robert – EVP, CFO and Secretary

Analysts

John Ragozzino – RBC

Ethan Bellamy – Baird

Ipsit Mohanty – Bank of America Merrill Lynch

Michael Peterson – MLV

Praneeth Satish – Wells Fargo

Jeff Robertson – Barclays

Adam Leight – RBC Capital Markets

Operator

Good morning, ladies and gentlemen, thank you for standing by. Welcome to Vanguard Natural Resources Q3 2012 Earnings Conference Call. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session and instructions will be provided at that time. (Operator Instructions) I would like to remind everyone that this conference call is being recorded today, Thursday November 1, 2012 at 10:00 AM Central Time.

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

Lisa Godfrey

Good morning everyone, and welcome to the Vanguard Natural Resources LLC third quarter 2012 earnings conference call. We appreciate you joining us today. On the call this morning are Scott Smith, our President and Chief Executive Officer, Richard Robert, our Executive Vice-President and Chief Financial Officer and Britt Pence, our senior Vice President of Operations.

If you would like to listen to a replay of today’s call, it will be available through December 1, 2012, and may be accessed by calling 303-590-3030 and using the pass code 45719045. 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 this morning’s earnings release. Please note, the information reported on this call speaks only as of today, November 1, 2012, 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 this week, and available on our website under the Investor Relations tab, as well as on EDGAR. Also on the Investor Relations tab, on our website, under Presentation, you can find the Q3 earnings results supplemental presentation.

In addition as a reminder the next record date for our monthly cash distribution is today November 1, with the November 14 payable date. Unit holders of record will receive $0.20 for each unit held or $2.40 on an annualized basis. In addition, I’d like to point out, we have our direct Unit Purchase Plan and a Direct Program through our transfer agent American Stock Transfer. To enrollment plan, you can visit www.amstock.com and under the shareholders tab, go to invest online and direct purchases and link to the Vanguard Natural Resources to purchase directly online.

Now, I would like to turn the call over to Scott Smith, President and CEO of Vanguard Natural Resources LLC.

Scott Smith

Thanks, Lisa. And welcome everyone, and thanks for joining us on our third quarter of 2012 conference call. This morning, I’ll start with what I believe to be the most important topic at hand. Our execution as the purchase of the sale agreement with the Bill Barrett Corporation for $335 million acquisition of primarily natural gas, and natural gas liquids properties in Wyoming, Colorado.

With this purchase, we will have increased our operating footprint in two of the largest producing basins in Wyoming and also added a high quality non-operated position along side of lean development company in the Piceance basin in Colorado.

Highlights of this transaction are we acquired approximately 300 Bcfe of total reserves using strip pricing, which consist of 240 Bcf of proved developed reserves and 60 Bcf of proved undeveloped reserves.

On a product basis, the assets are 78% natural gas, 15% natural gas liquids, and 7% oil and con say. One of the challenges we face from negotiating this transaction was structure the acquisition in such a matter – manner as to the gauge the near-term decline of the production in order to maintain the cash flow, which is obviously a key part of our business plan.

We’re in the various team to solve this issue by structuring the acquisition of Piceance assets, which include a gradually increasing working interest overtime. Initially our working interest is that at 18%, but the interest gradually increases through 2015 until it is capped at 26% as of January 1, 2016.

By implementing the structure along with our hedging strategy, we anticipate having relatively flat cash flows each year through 2016, after any significant capital expenditures. This is important, because we haven’t modeled any PUD development drilling on the acquired properties until 2016.

The current net production attributable to the assets is approximately 65 million cubic feet equivalent per day, which translates to an ROP ratio of 13 years on a proved basis. We project an average decline of approximately 12% from current levels to the end of 2013 and then about approximately 8% annually thereafter. These decline rates do not reflect the impact of any PUD development, but are inclusive of the increased working interest structure that we’ve designed in Piceance basin. On an operating metric basis these assets are low averaged LOE per Mcf of just over $1 and production taxes are approximately 8.5%.

As is our strategy, we intend to significantly hedge this acquisition through 2016 for a combination of swaps, basis swaps and basis swaps for the natural gas production and swaps and three-way collars for the oil production.

In addition, we intend to hedge approximately two thirds of the anticipated NGL volumes in 2013 through a basket swap, which hedges the individual component that make up the NGLs. We expect that this transaction will add an incremental $50 million to $55 million per year of EBITDA for the next four years. That being said, we are expecting no EBITDA impact in the fourth quarter as our policy, which is unlike some of our peers, it’s to not include any pre-closing EBITDA in our EBITDA calculation. So, we will be able to realize the full benefits of the transaction in 2013.

Pro forma for the acquisition, our total proved reserves will increase by approximately 36% with the product mix being 61% natural gas, 24% oil and 50% NGLs and over 70% of the total reserve base will be in the proved developed category. Although, the barrier transaction doesn’t contemplate any significant capital expenditures until 2016, there is a substantial low risk drilling component that can be executed if the gas markets improved faster than current futures market indicates.

When combined with the recently acquired Arkoma assets, we’ve enhanced our portfolio of high-quality liquids rich gas opportunities that can be developed should the capital markets or acquisitions deal flow slowdown or gas price rebound unexpectedly. As we have stated on our last few earnings calls and as evidenced by the deals we’ve done over the last six months, we believe in the current pricing environment it’s a great time to buy quality natural gas assets.

If you look at where gas prices have gone since we closed the Arkoma acquisition, prices have increased from $2 level that we saw in May to over $3.50 in November and the corresponding script prices have increased as well. Simply put we believe our timing in making gas focused acquisitions will prove to be a great strategic decision that will deliver long-term benefits to our unit holders as prices gradually improve. Now let me turn to our third quarter results and when I am finished Richard will then provide a financial review and will open the line up for Q&A.

First off, average daily production for the third quarter was 24,367 BOE per day, up 82% over the 13,371 BOE per day produced in the third quarter of 2011 and up 97% over the second quarter production rate of 12,338 BOE per day. On a product basis, average daily production was just over 7,400 barrels of oil per day, just over 2,000 barrels of NGLs per day, and just under 90 million cubic feet of gas per day. As you might expect, our production increased significantly over the second quarter largely due to the Arkoma Basin acquisition that closed at the end of the second quarter. Incrementally, it added 50 barrels of oil a day, 611 barrels of NGLs per day and 69 million cubic feet of gas per day to our third quarter production.

I am pleased to report that both the Whitford and Fayetteville production are producing on track despite the reduced capital spending in wells operated by third-party operators. On our last earnings call, I outlined the capital spending we did over the second quarter and then the results we expected to achieve. We spent approximately $15 million on a variety of projects ranging from the out-base and refrac program in the Red River vertical wells in Montana to participate and non-operated Bakken well. Unfortunately, these investments can generate the results we are hoping for in terms of production volumes and associated revenues.

Our out-base sand frac program has performed above the expectations; however, our activities in the Red River play and the Williston Basin were not as successful due to less than expected well performance and to a lesser degree production delay to getting the wells online for the third quarter. Although the results in the third quarter were below expectations, results for our overall 2012 capital program have been very good and today we’ve generated rate of return in excess of 50%. Recognize that oil and gas development isn’t easy and even the best prospects don’t always provide the expected results. All that being said that’s the very reason why our drilling is not a major component of our overall strategy. As evidenced by our history in today’s announcement, we grow reserves, production and cash flow through acquisitions, not the drill bit.

Now I’ll talk a little bit about our capital spending in the third quarter, during the third quarter we spent approximately $16.9 million of total capital expenditures. And for the first nine months, we have spent $40.3 million or approximately 87% of our revised capital budget.

During the third quarter, we spent $3.4 million in the Parker Creek Field in Mississippi, $2.4 million was spent in the Williston Basin on Red River, horizontal reentries and vertical wells I have mentioned previously and $1.8 million was spent on our recently acquired Oklahoma properties, $4.9 million was spent on our non-operated Bakken interest with the balance in the Permian Basin, the Elk Basin re-frac program and other maintenance related projects.

Similar to last quarter, over half the capital production, the capital investment was spent in September of the last month of quarter which added zero production and associated revenues to the quarter’s results. Looking forward to the rest of the year, we expect to spend approximately $8 million in the fourth quarter, about 30% of that will be on the Oklahoma assets where we will begin a planned five well program to develop proved and developed reserves (inaudible) area Pittsburg County, Oklahoma. Vanguard will be the operator of the program with the 51% working interest and in the initial wells planned to spud in early December and will be followed by the second well which is spud before year end. The remaining wells will be drilled in the first quarter of 2013. There will not be any incremental production from these wells in the fourth quarter as we will be completing all five of the wells concurrently most likely early in the second quarter of 2013.

Outside of the Arkoma, we planned to spend approximately $5.7 million, projects we have underway include reentering and converting a plug and abandoned well and a saltwater disposal well which will help lower our water hauling cost and then in the word counting area and has the potential to receive additional benefits from having other operators pay to use that well as well as us.

We will also continue to execute the Elk Basin refrac program and we will spend approximately $900,000 participating in another non-operated Bakken well with an average working interest of approximately 23%. The remaining capital dollar will be spent primarily on other maintenance projects across other areas of operations.

Lastly as I am sure many of you’ve hopefully experienced we’ve now paid two monthly distributions since our announcement back in August to move from paying quarter to monthly. We continue to feel that this is a significant step in further aligning Vanguard with the interest of our unit holders and are frequently reaffirmed with that decision from the investor feedback we receive. MLPs are designed to be an income vehicle and what better way to pay our unit holders than on a monthly basis.

That wraps up my portion of the call and I will turn it over to Rich.

Rich Robert

Thanks, Scott, good morning everyone. Third quarter was a very active one for Vanguard, not only we have been integrating the back office functions for the nearly acquired Arkoma income assets, but we also took over operations beginning on September 1. Also in September and October, we took additional steps to show up our balance sheet by completing a $6.9 million unit offering in September for net proceeds of over $180 million and a $200 million add-on to our existing senior notes due in 2020.

As I will get more into in a little while, exchanging debt under our credit facility for equity and high yield debt comes at a price in the form of increased distribution with higher interest expense. However, we fully intend to put that capital to work in short order and this morning we announced that we were in a position to do just that. Today’s acquisition market, it’s important for sellers – it’s important to sellers than buyers have a liquidity in place to quickly execute acquisitions and we feel that the higher cost to capital and hence negative impact in the fourth quarter’s well worth being in the position to execute all larger transactions.

With that I want to discuss four topics this morning. Financial results for the third quarter, updated hedge profile, and finally our credit facility and liquidity update. We reported adjusted EBITDA attributable to Vanguard unit holders of $66.3 million for the third quarter of 2012, an increase of 79%, when compared to the $37 million reported in third quarter of 2011 and 49% from the $44.5 million in the second quarter of 2012.

As you would expect, the Arkoma acquisition’s negatively increased our EBITDA quarter-over-quarter. We also saw a significant growth quarter-over-quarter even though we faced near same headwinds that we saw in the second quarter. However, one of the many benefits of doing an acquisition in a new basin and with a different product mix is that it increases not only geographic diversity, but also commodity diversity. As we get larger issues based in one area have less of an impact in Company’s overall results.

Now, I’d like to move on to a more detailed explanation of our EBITDA in the third quarter. During the second quarter earnings call, I discussed the negative impact of widening oil differentials at the Big Horn Williston and Permian basins. We did expect differentials to improve over second quarter and they did.

However, it took a little longer to me anticipate it. Line (inaudible) oil differentials continue to be quiet wide, but September showed tremendous improvement and on a very positive note October has again improved over September, and Rockies old differentials are now well below historical norms. I find infrastructure improvements and new – to multiple markets are having a positive impact on differentials in the Rockies area as they are relieving bottlenecks and finding new markets from the oil in Rocky.

Moving on to NGL. NGL price realizations continue to worsen in third quarter. We start 38% decrease in the average NGL realization from the third quarter 2011 and a 14% decrease compared to the second quarter of 2012. As a percentage of Nymex oil price, NGL realizations declined from 48% in the second quarter to 41% in the third quarter. Historically, we elected to not hedge our NGL price exposure due to cost and liquidity constraints and because NGL represents a less than 10% of our overall production.

Fortunately, a portion of our NGL production is in the Big Horn Basin, where more than 80% of the barrels produced are natural gasoline and butane, which are the higher priced components of the NGL stream as the regions that our realizations as a percentage of NYMEX were historically higher than most producers.

However, the Arkoma Basin acquisition added more NGL barrels and the benefit of the Big Horn Basin heavy NGLs screen has been reduced. Our guidance was based on realization, we were seeing in second quarter, so although was a conservative from an historical perspective, unfortunately it wasn’t conservative enough for the third.

Another item that negatively impacted our results this quarter was an abnormal amount of oil inventory at end of the third quarter. We only recognized production and revenue when oil is stored, not when it is sitting in tanks. We’ve to cross our different areas and when we added together – when we add them together, there was approximately 54,000 barrels of oil in the mix. If we were able to sell just half of that, we would have realized an increment of $2 million to $2.5 million of additional revenue for third quarter.

Our operational personnel are now aware of the financial impact of oil barrels remaining inventory and we expect reduced inventory numbers in the future. There are some positives that I want to point out. First and foremost, because of the recent Arkoma acquisition and pending Barrett acquisition, we will have substantial increase in our size and scale which helps to diversify our cash flows. Issues such as differentials lining in one area or a specific capital project setback in another is less impactful to the overall company performance.

In addition, as mentioned, the pending acquisition is largely PEP after next two years acquires little to no capital to keep cash flow flat. Secondly, it is because of that size that we’re able to realize more operational efficiencies. LOE on a BOE basis has decreased 25% to 870 per BOE third quarter of 2012 from the $11.56 seen in third quarter of 2011.

The Arkoma acquisition being primarily natural gas we’ll have lower operating costs, such that when combined with our legacy assets improve Vanguard’s operating and leverage metrics pretty significantly.

Additionally, G&A not only decreased on a BOE basis, but it decreased natural dollar spent approximately 15% back to $5.5 million in the third quarter of 2012 compared to 2011.

So, even though we closed the transaction and roughly doubled our production and reserves, we were able to efficiently absorb the assets with very little trouble. It does not mean that we did not hire key people to help with these assets, but rather it shows we made a necessary investment to the Vanguard’s different structure in 2011 to grow this company successfully into the future.

In terms of our distributable cash flow, the third quarter of 2012 totaled $36.6 million, or $0.67 per unit generating a coverage ratio of approximately 1.12 times based on our current discretion of $0.20 per month or $0.60 per quarter. We also incurred the large amount of capital expenditures in our company’s history at $16.9 million which should support future growth, revenue growth into the quarters ahead. As Scott mentioned, the capital expense for the fourth quarter is expected to be much less, somewhere in the $8 million.

As we expect, time and again, we believe our distribution coverage should be measured on an annual basis and upward quarter because it’s nature of our varied capital spending throughout the year. Unlike many of our peers, we do not breakout CapEx into growth and maintenance. We take a more conservative approach which makes our distribution cover lower and if we chose to breakout growth and maintenance.

I’d like to take a moment to discuss our non-cash items that does not impact our EBITDA or DCF but is worthy of mentioning because it does impact our GAAP EPS and there is an item that I continue to expect to see as long as we are acquiring significant gas assets. I’m referring to impairments on oil and natural gas properties. This quarter we booked $18 million impairment. Is this something I believe investors should be worried about? Emphatically no. Here is one. Each quarter we have to compare the SEC future net present value of revenues from crude reserves against the book value of our oil and gas properties on our balance sheet, this is call a ceiling test.

To calculate the value of the future revenues the SEC requires the entire reserve life equal to the historical 12 month average oil and natural gas price so this quarter it was the historical prices from October 2011 through September 2012, which for the natural gas was $2.77, and support to know that the SEC rules do not allow the inclusion of the value new hedges.

So let’s take our recent Arkoma acquisition as an example, which is the impetus for the impairment charges for the quarter. We paid a price for the Arkoma reserves based on the forward script for natural gas which has prices increased each of the next several years. We can feel comfortable evaluating and paying a price based on this because we can lock in the expected margins to be a natural gas price hedge. So we bought these assets and headed the production for the next five years at $5.04 but are required to evaluate the future cash flows as though we were only getting $2.77 for the life of the reserves.

Clearly, this will indicate that you won’t recover the price you paid for the assets and therefore an impairment loss is required. The only reason that we didn’t have to book an impairment loss in the second quarter when we closed the Arkoma acquisition is because we had built a significant cushion over the years buying oil assets and seeing the price of oil increased over that time.

The cushion was sufficient to observe the impairment loss based on the 12 month average price at June 30, but the 12 month average price in the third quarter was lower than the second quarter and tipped the scales to require a smaller impairment. Note that I mentioned the $18 million impairment is small relative to what it would have been have we not had a large cushion. Do not be surprised when we record a large impairment in the fourth quarter related to the closing of the Barrett acquisition and continue to record impairments on the day of closing on all significant natural gas asset acquisitions, this will occur as long as we operate in an upward natural gas price curve and the SEC doesn’t change.

Now on to hedging, as I regularly note, we continuously evaluate our hedge book and opportunistically add to our current positions, we were quite active in adding to our hedge positions, primarily as a result of the gas hedges associated with the Antero acquisition, the acquired hedge portfolio was valued at approximately $110 million and we’re at prices definitely higher than current IMAX ranging in prices from $5.58 to $6.50 through 2015.

Instead of keeping the hedges as is, which frankly would have increased our EBITDA much more for the first few years, we felt it was more prudent to take this below and by lowering this oil price to $5.04, we could increase the volume production hedge to approximately 100% for the next five years, and additionally our swaps wouldn’t know that the hedge is that – that the basis is hedged and we are – it is based on – known for index, which is also the index that we get paid off.

So, that – that we are locked in our margin no matter what happens to the basis or natural gas pricing necessary there. In terms of percentage of production hedged and excluding the impacts from the pending acquisition of 2012, expected gas production is 88% hedged, 2013 is a 100% hedged, 2014 is 86% hedged, 2015 is 76% hedged, 2016 is 75% hedged, and 2017 is over 75% hedged, all at weighted average price above $5, which we’re hopeful that by 2017 we can re-hedge future natural gas production at comparable levels, less of cash – and cash flow cliff.

On the oil side, 2012 expected oil production is 95% hedged, 2013 is 91% hedged, 2014 is 72% hedged. I’d like to ask that the weighted average hedged or priced, closely or approximately at the current market, like you must remember one thing, the weighted average price, we report only takes into consideration the flows of our callers, additional callers, callers constitute a relatively large portion of our overall hedged portfolio, and has been a reason in the past by our cash flow can vary from quarter-to-quarter even though we are as well hedged as we are.

To partially mitigate these swings, in the third quarter we converted over 800 barrels per day in three-way collars back to swap into 2013. In doing so, we were actually able to increase our swap price because of the value the options had at the time. Now three-way collars and traditional collars as a percent of our hedge portfolio comprise approximately 45% in 2013, 35% in 2013, and 25% in 2014.

We still have a significant portion of our portfolio that will allow us to have the ability to participate in upside above our weighted average floor of approximately $91.50 over that three-year period. But at the same time we felt there was little more stability in the revenues in the fourth quarter. In addition, as is our strategy, we intend to significantly hedge natural gas and oil production through 2016 and the NGL production in 2013 through the Bill Barrett acquisition. More details regarding our current hedge portfolio and percent hedge can be found in supplemental Q3 information package posted to our website this morning.

On to our credit facility and liquidity, we did complete as I mentioned a 6.9 million unit offering in September for net proceeds of $182 million and a $200 million senior notes add on to our existing 2020 notes in October. Although we had good liquidity after the Arkoma acquisition, we felt it was more prudent to take advantage of the current market conditions and create more liquidity to finance future acquisitions. It is obviously not our preference to trade 2% debt under our credit facility for more expensive equity and high yield bonds, but it was an opportunistic decision to place Vanguard in the best strategic position from a capital perspective in order to achieve our long-term growth targets. I’m happy to say that it didn’t not take very long to do just that.

We have ample liquidity to close pending Barrett acquisition by year-end and after closing this acquisition and the banks performance an interim morning base redetermination. We will have ample liquidity to continue our growth through acquisition strategy. However, as a reminder, creating this liquidity comes at a cost, which will be held in the fourth quarter. As we don’t get the benefit of any EBIDTA related to the Barrett acquisition until 2013.

As Scott mentioned earlier, we take a more conservative approach than any of our peers. And don’t include any pre-closing acquisition EBIDTA in our calculation. If we did so our second quarter results would have been badly improved due to the Arkoma acquisition and our upcoming fourth-quarter results would be vastly improved related to the pending Barrett acquisition.

At September 30, the Vanguard had indefinites under its reserved base facility totally $570 million with liquidity of 405. In early October, our borrowing base was increased to $1 billion that was reduced to $960 million on October 9, with a mandatory production related issuing the additional 200 million in Senior Notes. We used the proceeds from the 200 million Senior Notes add-on to reduce our borrowings over revolving.

After consideration of the $34 million deposition for the pending Barrett acquisition, Vanguard had 404 million in a standing borrows under the revolver, which provides us with 556 million in current capacity as of today. We’re proud of the fact that we’ve increased our distributions to unit holders by 41% that’s going public, while still maintaining a very strong annual distribution covered ratio. The Arkoma acquisition and the pending Barrett acquisition like the Alcor acquisition before it are four stepping stones in Vanguard’s future growth and success.

We’ve always stated that we prefer to operate at a distribution coverage of at least 1.2 times and our number one goal has always been – has always been to provide security to the current distribution to the long-term. I’m very pleased to say that as a result of the Arkoma and (inaudible) acquisition and despite the more challenging commodity price environment we now operate in, we will be able to resume our measured approach for rolling our distribution.

This concludes my comments. We’d happy to answer any questions.

Question-and-Answer Session

Operator

Thank you. Ladies and gentlemen, we’ll now conduct a question-and-answer session. (Operator Instructions) Your first question comes from John Ragozzino from RBC. Please go ahead.

John Ragozzino – RBC

Hi, good morning gentlemen.

Scott Smith

Good morning, John.

Rich Robert

Good morning, John.

John Ragozzino – RBC

We’re just taking the Baird assets and giving unique structure with the working interest there, can you give us a feel for what an estimated managed CapEx level would like today if you did have to spend some capital. And then what kind of spending did you foresee in 2016?

Scott Smith

Excuse me John. Again we have again working with them and I’ll say they’re a great company to work with. Collectively we looked at the assets and in the Piceance in particular which is the largest piece of the transaction. Again they don’t plan any capital expenditures. They will be operator with obviously a much larger interest than we have.

And collectively we said, look we don’t intend to spend any money until 2016. At that point in time the IRRs at that gas price start becoming attractive and we start looking on capital expenditures, I have to apologize, I was working on this till late last night. So my – I don’t have all of the facts right in front of me, but we’ve start having a capital program that’s probably in the $20 million to $30 million range, depending on how aggressive they want to be. We also have some plans Powder River spending, again those CBM wells become pretty attractive in that, the gas pricing which now is available in that 2016 timeframe and that’s kind of in the $7 million range. So I guess, about $40 million all them starting in 2016. But again, obviously a lot of things can change between now and then.

John Ragozzino – RBC

Okay, great. And the next question I have is related to some of the asset in the Powder. Do you have – as a percentage of the total reserves that are actually CBM and what stage in the process are there, are there some of that stuff that’s still dewatering. Is there an expectation for a slight production ramp and maybe the associated production levels?

Scott Smith

It’s very matured production, if – there’s a lot of wells here, somewhere in the order of – I think it’s close to 700 wells or more. And it’s mature, there may be some wells that are dewatering, but we are not modeling in production ramp at all. In fact, I think it is the highest individual decline property of asset, although it may be the smallest in terms of value. I think our model from a PDP basis only is 20% decline from 2013 to 2014. But again, it’s the smallest terms of value. The big driver is the Piceance Basin, where we’re looking at a 5% decline in 2013 and 2014.

John Ragozzino – RBC

Okay. You guys have been super busy this year with your acquisitions, do you have any expectation for an impact on per unit G&A expenses and could you perhaps maybe touch a little bit about – into the processes with the integration of these two fairly sizeable assets and it’s maybe staffing requirements that have associated well?

Rich Robert

Sure, John, it’s Richard. It’s fair to know our G&A on a BOE basis is going to go down, as I mentioned we did make a lot of investments in 2011 from a back-off perspective IT and SAP as well to be able to manage not only the Encore integration but also future integration of assets. So, I think to a large extent we’ve made the investments necessary and that’s why you’re actually seeing our asset dollars come down. But you’re not talking about a lot of people, although with this transaction we’re looking at some of the neighborhood 35 field people coming along with the wheel...

Scott Smith

But they’re all LOE, so..

Rich Robert

Yeah, but that’s all LOE, so that doesn’t relate to G&A, so and that is where most of your – that’s where most of your incremental costs come from frankly is in the operating personnel fields and the beauty is, operating personnel comes with the asset. So there are no hiccups in relation to keeping the wells flowing and keeping the cash flow flowing. And as far as the – we’re all looking to update our guidance after this transaction closes, so I would expect sometime in January to put out the revised 2013 guidance.

John Ragozzino – RBC

Okay, and as you think about 2013, given where gas prices have kind of run up to and keeping in mind that the (inaudible) potential, have you written any expectation for some flexibility in terms of capital spending in that area and would that be a reallocation of capital from another area or would you be able to increase the total budget based on the expectation for increased activity in the stated book.

Scott Smith

John, we’re still in the capital budgeting process for next year, obviously we have this five well program planned which will go into 2013, and I anticipate that we sit down and look at our – our total opportunities that’s just in front of us as we look for next year that we’ll have additional drilling beside those five wells plan, but it’s a little early for us to take that. We have – it’s all going to shake out now that we can have a little deeper opportunity set. We are also seeing more activity in the Bakken, and then some of the other areas where we think there is some good opportunity. So, it’s a little early but we’re on the capital budget side. I think as we get into later this month and end of the December, we will present them to the board, and then we probably come out. Richard, Doug, and Scott will talk about the budget.

Rich Robert

Yeah, keep in mind John that – that the budget has to be fluid because it’s all relative to your opportunities that which changes every time you make an acquisition. So, we are going to reallocate every time we’re doing an acquisition based on the opportunities that we see, but overall I think you can continue to expect us to spend somewhere in the neighborhood of 20% of EBITDA.

John Ragozzino – RBC

Okay. Then just one quick one, and I’ll let somebody else, I promise that, talked you guys long enough. Given the estimate for what the total portfolio PDP decline rate is, pro forma for the bad acquisition?

Scott Smith

So, we said this particular acquisition was around 12% on a decline, if we look at combined with a total portfolio. So, it’s probably going to be just under that, although that – Rich will be going to read numbers real quick and I’ll split....

Rich Robert

Without the – we were looking at about a 16% decline.

Scott Smith

For PDP.

Rich Robert

Yes.

Scott Smith

Okay, that’s PDP,

Rich Robert

PDP..

Scott Smith

I thought including the numbers we’re going to throw up. So, with including – then it would go down in 2013. We are looking at about 2012.

John Ragozzino – RBC

Okay, great. Thanks very much, guys.

Scott Smith

Thank you.

Operator

Your next question comes from line of Ethan Bellamy from Baird. Please go ahead.

Ethan Bellamy – Baird

Hey guys, good morning. Congratulations on the acquisitions.

Scott Smith

Thank you.

Ethan Bellamy – Baird

Let’s see, I want to dial in accretion estimate a little bit more. Can you just review for me what’s your gas and NGL price realization expectations are? And if you can give us any color on, what the incremental G&A expense of the acquisition, that would be helpful?

Rich Robert

Sure Ethan. We ran this on what we think is pretty realizable for 2013, and this is what we’re hedging at. So it’s not that far off. We’re expecting about $88 per well, about $3.85 for gas and we actually modeled NGL realizations at about 28%.

Ethan Bellamy – Baird

28% of NYMEX or of your realized oil price?

Rich Robert

NYMEX.

Ethan Bellamy – Baird

And G&A?

Rich Robert

There is going to be very little incremental G&A.

Ethan Bellamy – Baird

Okay.

Rich Robert

We did put some overhead dollars in the power, on the operated assets, but again that was just kind – but it’s not big numbers. Let me – one point on that gas price Ethan, that is a NYMEX price and then we use a differential of CIG basis, which is probably around $0.22 and then we added a Nickel for that. We basically NYMEX plus 27 range.

Scott Smith

Well, that 91% NYMEX is on the gas side. That’s what we’re looking at. And it realization is about 88% on oil and like I said 28% on WTI, for NGL.

Ethan Bellamy – Baird

Okay, that’s helpful. I assume that your intent was to be vague about the accretion in the release, but I guess I’ll just ask can you give us a ballpark on your estimated accretion?

Scott Smith

Well, obviously you have to run kind of what capital structure you’re going to run the accretion based on, everyone is going to be different as to what they expect, but Scott gave a number of $50 million to $55 million in EBITDA incremental. So when the accretion is pretty significant. And when you consider that the expectations that they have any capital requirement. And that’s the beauty of this deal is this working interest ramp up each year eliminates the need for us to do so and still keep your cash flow flat. So it’s really from an accretion standpoint quite attractive.

Ethan Bellamy – Baird

Okay. And just to recap on the working interests, should we think about that – that change in working interest structures basically just offsetting the PUC client rate to keep production flat?

Rich Robert

Yes, and, and...

Scott Smith

I wish everyone will do that for us.

Rich Robert

Yeah.

Ethan Bellamy – Baird

Right.

Rich Robert

I mean it’s also an increasing gas prices well that’s helping keep that cash flow flat as well. We’re not hedging at a flat price, we’re hedging at – we are distributed each year.

Ethan Bellamy – Baird

Okay. With respect to the release at 12% of HPP in the Wind River and so are we take that you’d lose some of that acreage as part of the deal if you didn’t deploy the capital or is there a capital plan in 14 or 15 that would keep that acreage, how do you think about that?

Scott Smith

We have no undeveloped reserves booked in November month, this was an exist for them. The acreage there is – if there is upside associated with it, it’s all projects that are uneconomic in today’s pricing. We have a part of the transaction as they have to right to request farm outs on that acreage, if they come up with a deep play. And obviously, we encourage that. We are one of the leading resource play developers in the Rockies out work in this data for us, if they happened to buy something. We’ll have a nice ability to participate in that in terms of an overall working interest. But as far as the win again, we put no acreage value on that. It is a big position and may be the good fortune will fall into one of these deals like some of our peers are having.

Rich Robert

Maybe you will Utica.

Ethan Bellamy – Baird

Good luck with that. I hope so. And then one last for Richard, where do you expect the revolver to shake out after this pro forma?

Rich Robert

We’re going to have probably $700 million borrowed on the revolver and if you give us a reasonable amount of cost base increase as a result of this transaction, pro forma will have somewhere in the $25 million to $50 million range in liquidity as this transaction close.

Ethan Bellamy – Baird

Okay. And is that pro forma for, I’m sorry, I just don’t have the number from me. Any additional borrowing capability you would get from the reserves or the existing?

Rich Robert

Yeah. That includes the incremental.

Ethan Bellamy – Baird

Okay.

Rich Robert

So, I’m thinking we’ll somewhere in the neighborhood of $450 million at year end.

Ethan Bellamy – Baird

All right. Then we’ll spin it all in one place. Thanks very much. Good luck.

Rich Robert

Thank you.

Scott Smith

Thank you.

Operator

Your next question comes from Ipsit Mohanty from Bank of America Merrill Lynch. Please go ahead.

Ipsit Mohanty – Bank of America Merrill Lynch

Good morning, guys.

Scott Smith

Good morning.

Rich Robert

Good morning.

Ipsit Mohanty – Bank of America Merrill Lynch

Just a quick, couple of quick questions, starting from a more broader general view. You guys did two acquisitions big one here to date primarily in the gas focused assets. Is it a reflection of your sort of bullish view on gas is going forward or are you being opportunistic, just looking at what you can do with sort of the cheaper gas assets, or does is it more of a shift in portfolio, what’s your view on that / it?

Scott Smith

I think the view is really, these were opportunities that as we pursue them, we felt that it had the right attributes for what we were looking for going forward. Again, we are seeing everything in the market, and as you’d look at lot of the oiler plays are going from very, very aggressive valuations. We think these act, the acquisitions that we’ve done are more accretive, and it also have the benefit of the upside in the gas markets rebound into – you want to clock more historical levels, you know, in the later part of the 2016, 2017, 2018 and beyond.

Again, there is a lot of upside, that we are not paying for, but are inherent in these assets, which is not, which you know, which is a typical, I will tell you, if you can find an oil deal, you will pay for all of the upside today, and it’s like that, and we are hedging it for a long enough period of time that in the – we are modeling it at current pricing. So we feel comfortable, and we know what our returns are going to be. We hedge the assets, but again, we do have this upside now in the interior and the spirit transaction of the rebound of gas prices, but again, we did have to pay for.

Rich Robert

Yeah, and let me just add that, if you look at the length of the hedges, that we are doing, significantly larger than what we’ve done in the past, I think that would indicate that if anything were bearish, on where gas prices are going to go, we don’t want to take any risk associated with margin deteriorating and I would say that we’re still going to be optimistic. We’re still looking at all transactions. We’re not trying to simply do gas transaction and I think you will continue to see us do both going forward.

Ipsit Mohanty – Bank of America Merrill Lynch

All right. Wonderful. I apologize if I miss this before, what’s on an overall portfolio basis, what’s your percentage of operator to non op?

Rich Robert

On a cash flow basis, we haven’t done the calculation after this, considering this pending acquisition.

Ipsit Mohanty – Bank of America Merrill Lynch

Sure.

Rich Robert

We’ll get to you on that number.

Scott Smith

Yeah, it was about 75% before this transaction. I would guess, it’s not going to change that much.

Ipsit Mohanty – Bank of America Merrill Lynch

Okay. Thank you.

Scott Smith

It’s really on our cash flow basis.

Ipsit Mohanty – Bank of America Merrill Lynch

Sure. I might have heard a little bit about the NGL hedges. Are you planning into layer some new hedges? What’s your…

Scott Smith

Yeah, we’re going to hedge two-thirds of the production on the asset, that’s our intention...

Scott Smith

Of the NGL.

Rich Robert

Of the NGL.

Scott Smith

Just for 2013.

Rich Robert

Just for 2013, markets liquid for a year maybe.

Ipsit Mohanty – Bank of America Merrill Lynch

Got it. Thank you guys.

Scott Smith

Thank you.

Operator

Your next question comes from Michael Peterson with MLV. Please go ahead.

Michael Peterson – MLV

Hi, good morning folks. I have three questions. I think they are all likely to go to Richard. First one Richard would be in terms of the LOE that we saw, the decline in the third quarter, do you think that’s the ballpark steady state for the Arkoma? I’m trying to understand how to integrate in the announced acquisition today? The second question if you could give us some perspective on the range bonus accumulators that you included in the hedge book. And lastly if you have any feedback in terms of the monthly distribution and DRIP program are they, are you seeing any uptick in liquidity, is it too early, any color there would be helpful.

Scott Smith

Sure. First question related to LOE in terms of run rate, yeah, I mean, there is no reason to believe that run rate isn’t frankly going to improve as we continue to do gas transactions, last year transaction have lower LOE comps on a BOE basis, so hopefully that run rate will go down on a BOE basis going forward.

Michael Peterson – MLV

May be something slightly below 8 then into the first quarter after closing.

Scott Smith

After closing, exactly you won’t see that in fourth quarter, but you will see after we get the benefit of this, these operations – second question was the rate balance (inaudible).

Michael Peterson – MLV

Yes.

Rich Robert

What we did is one of our counterparties approached us and after the structure we hadn’t seen before that we thought was relatively attractive and decided to utilize, essentially it allows us to get an extra $3 per barrel on a volume of oil we did 1,000 barrels in 2013 and when it stays, when the pricing stays between $70 and $110 we get paid $3 on that 1,000 barrels, if it goes over, if it goes over, over that $110 level which is not sound, nothing happens, we don’t get paid anymore and if it goes below that $70 they can put it to us. So we will trade at 65 and we have to pay $5, so and in conjunction with that we put a hedge in 2013 on an additional 500 barrels at $92.50. So we’re essentially improving our pricing on that – on that spot.

Michael Peterson – MLV

Okay, okay, thank you.

Rich Robert

And finally on the monthly distribution in DRIP, we’ve done a lot of very good feedback on the monthly distribution, I think people will understand why we did it and our motivations are clear. And those that use just to pay their bills on a monthly basis are very happy about it. Clearly the institutions don’t really care too much I would think, but over 65% are unit holders are small guys, less than 750 units. So I expect this was something that appeal to them.

As far as the DRIP program is concerned, it is a little bit new. We’re still working with ASG to work out the (inaudible) in terms of making it easier for people to sign up for it. Currently, I think we only about 25 people signed up and I hope that as we make it easier for people to sign up, people are more aware that its available, because it is somewhat unusual for MLPs to have this available. Hopefully, the word will get out and more people will sign up and – create a nice way for them to add to their VNR position in a cost efficient way and create a little bit of liquidity for us at the same time.

Michael Peterson – MLV

I appreciate your insight. Thank you, Richard.

Rich Robert

Thank you.

Operator

Your next question comes from Praneeth Satish from Wells Fargo. Please go ahead.

Praneeth Satish – Wells Fargo

Hey, guys. Good morning. Just a couple of questions. The 28% NGL realization you’re assuming in the EBITDA guidance seems a little bit low. Is that because the NGL production is based on Con-way pricing or has a higher ethane mix? How should we think about that?

Rich Robert

Well, keep in mind, this was a just a bare transaction that we modeled it at 28%. We hope it is conservative. It doesn’t come with ethane rejection as well, just to be clear on that, and it is the pricing it is not Conway pricing.

Scott Smith

Those payrolls are about 650 Tnf fee to get there from the Colorado area from the Piceance II, that’s you’re going to take basically what you would guess pricing available in Belvieu and take 650 off. And again I think that the number we’re using is conservative.

Praneeth Satish – Wells Fargo

Okay, that makes sense. And, then just could you provide any guidance around production cost for the acquired assets. I mean how does the LOE for the acquisition compared to VNR’s current metrics?

Rich Robert

Well, I think what we will put a bullet point in our – this morning. I think it’s about $1 for Mcfe as what these costs are.

Praneeth Satish – Wells Fargo

$1.35 if you include production taxes.

Rich Robert

And that compares to.

Scott Smith

Which is less than what Vanguard is, it’s always going to be less when you look at a gas transaction (inaudible). So it should improve our metrics on a BOE basis.

Praneeth Satish – Wells Fargo

Okay. And just last question, just thinking about clearly. I mean once the escalation and working interest completes in 2016. Do you still expect the decline rate of the acquired properties to be in that 8% range?

Rich Robert

It will probably, yes it should in that 8% range, basically – and then like I said what we hope and I think in the share this thought is that gas prices as with the current future market indicates on a level where we can start kicking on the end and start developing pretty robust PUD inventory in excess to 350 wells already identified and ready to go. So in a long-term with them, we sure look to be developers. Essentially this is a resource play. It’s drilled to on 10 acre spacing and in a space that we just put you know more pins on the footprint. So, it’s a great MLP very super low-risk, very tight rock type asset again with the good NGL component that gives you the addition in the pricing.

Scott Smith

Yeah, and then other thing to note is we are buying only a small portion of Barrett’s interest of (inaudible). It’s a low – a very large interest and so fairly if – if they decide to sell in the future more of their interest, which will be in line to take advantage of that kind of be a very easy transactions to integrate.

Praneeth Satish – Wells Fargo

Okay, great. Thank you.

Scott Smith

Thank you.

Operator

Your next question comes from Jeff Robertson from Barclays. Please go ahead.

Jeff Robertson – Barclays

Thanks. Scott can you talk about your ability to propose activity in the Piceance basin and what rights you will have with Barrett if you decide commodity prices get to a point where it makes sense to drill and they are focused on other plays?

Scott Smith

Sure. We are – we will be under an operating agreement based on standard form that either side can propose and the penalties are in or out. So if they don’t go, they are out of that individual well. It’s – it’s either side wanted to create some sort of big accounting headache here. Again, I think our interest for align I think prices rebound to the point where we want to that it makes sense to drill, I think they will bell along with us.

Again, we tried to create in the structure real alignment between the two companies, but I think – Bill Barrette is a big company. They have lots of other things going on. If something happens that it makes sure not to do it. Obviously, we will prepare to just go it alone. When we drill, we drill complete the well and turn it into the pipeline system. We are picking up an undivided interest into the gathering system, the gas gathering system, the water handling system, all the facilities that go along with operating field.

Jeff Robertson – Barclays

Okay and will you all be able to report production on a three stream basis from those assets?

Scott Smith

Yes, most of the production obviously in the operated stuff that we’re going to be doing in the Winds and the Powder River won’t be a problem and then from the Piceance basin, there it has, if you look at their financials, they don’t do it. But no, we will have plant statements from all that gaskets processed at the enterprise plant, the micro plant. So, yes we will break that out and you saw that in our press release this morning how we plan to do that going forward.

Jeff Robertson – Barclays

Okay, thank you very much.

Scott Smith

Thank you.

Operator

(Operator Instructions) Your next question comes from Adam Leight from RBC Capital Markets. Please go ahead.

Adam Leight – RBC Capital Markets

Hey good morning, I think it’s still morning. It’s been pretty exhaustive just a couple more, I think if you were to report these reserves that you’re acquiring using trailing 12 prices, what kind of volumes would that be?

Scott Smith

It would be last for certain. We took that into consideration somewhat when we reported the reserves we’re acquiring but under SEC guidelines, clearly the amount of reserves would be less. We haven’t done the calculation beyond this and obviously the year’s not done yet, so we have to guess, but....

Rich Robert

I think one way to look at, if you look at Barrett’s press release that they did, one minute before ours this morning, they were using 2011 reserve pricing.

Adam Leight – RBC Capital Markets

Good.

Rich Robert

And obviously they – I think they were around 240 Bcf or something like that, so.

Adam Leight – RBC Capital Markets

Yeah.

Rich Robert

I’m not exactly sure what that price I think it’s probably a little bit less than what is current, or what was this – in these last 12 months. It’s going to be in that level probably.

Adam Leight – RBC Capital Markets

Okay. That’s kind of what I was getting at, thanks. And then, just for going forward, how do you account for the working interest increases in your rules in your, sorry?

Rich Robert

It will just flow through our reserve report, I mean the assignments will be made with that closing, they’re actually held by a trustee and on January 1 of each year, we’ll get a little FedEx and hopeful – and hopeful we’ll record it and that will adjust their joint interest billing tables at revenue deck, and that’s how it will be accounted for. It’s contractually bound to do it, so it will be reflected in our reserves.

Adam Leight – RBC Capital Markets

Does it flow through under acquisitions?

Scott Smith

Yeah, I don’t think we are – I mean, we haven’t really thought through the accounting. I don’t think we’re going to show any kind of differed purchase price, if that’s what you’re referring to.

Adam Leight – RBC Capital Markets

Yeah, okay. That’s fair enough. And then, lastly, have you any discussion with rating agencies on the impact of this transaction?

Scott Smith

Rating agencies are under water, it would seem. But I’ve had email conversations with them and I have meeting setup later in the year to discuss the impact.

Adam Leight – RBC Capital Markets

Okay, great. That’s all from me, thanks.

Scott Smith

Thank you.

Operator

Our last question comes from David (inaudible) Capital. Please go ahead.

Unidentified Analyst

Thanks for taking my call. The first question I had regarding the Barrett transaction for the Piceance, you said 2016 was potentially 20 to 30 million, was that a net or gross number?

Scott Smith

It would be a net number.

Unidentified Analyst

And then, if you could help me just understand a little bit on the ramp up, on the working interest. I guess just to understand why it’s structured that way and if there is any timing, is it just tied to timing or hurdle production rates or...

Scott Smith

Literally, I mean, it was designed looking at the total assets that they wanted to sell and what we were looking to acquire. It was painfully obviously when we first started looking at it that the decline rate was a little too steep than we would normally acquire. Again, without offsetting capital per spending that we could use to maintain our EBTIDA. So we looked at it and said, look here is the other asset where you guys are going to maintain your working interest, taking to account the future’s prices in the market basically in escalating gas price.

And then a declining production base basically what the other third leg of the stool would be lets add additional working interest volumes that helps to mitigate that drop off and we worked with them, and we were able to come up with the situation that way we are able to get agreed to and papered up. When we have this gradual increase over time and by doing that it mitigates the cash flow drop, again what we’re looking to buy and what they were happy to sell us at the price that we did is a relatively stable cash flow stream.

In this case, we have the benefit and again we collectively share this goal of not having to spend capital until the gas prices get better and again futures market tells us today it’s around 2016 obviously knock on wood, it gets better faster, that’s good for everybody. But that was really the trade-off in looking at what we paid and structuring in order to design something that keeps our cash flow relatively flat and that was the methodology of doing it, because the Piceance is by far and away the largest asset.

Rich Robert

Our strategy is quite simple. We are creating stability in cash flows. All the decisions we make are just that, trying to create stability, avoiding cash flow cliffs and that’s the structure that allowed us to make that happen.

Unidentified Analyst

That’s very helpful. That makes complete sense now. And I guess – that’s pretty unique structure and your goals, how are you able to come across this transaction. Is it an auction or private deal or how did you...

Rich Robert

It was a negotiated transaction, introduction through business contacts in the Denver community.

Unidentified Analyst

And then my last question is you mentioned that the opportunity could exist to further expand if Barrett wanted to sell acreage. Do you have a first rate of fusil on those assets or is it...

Rich Robert

No, we don’t. I think going through a process like this, obviously you get to know the company. They were comfortable with the valuation and I think as we did with numerous parties where you had non-operating interest, once you’ve done a transaction like this and people are comfortable with who they’re working with, evaluation is good. In the event, they’re off doing, they have a project that they need either funding for, that’s a bigger focus for them as they continue to develop these resource plays. If they need capital, I would hope – anticipate that we would be one of the first calls we would – they would make, because they know we can move quickly. We know we will – our (inaudible) interest in the assets of getting a transaction done pretty seamlessly as long as you can reach the right valuation should be clear.

Scott Smith

And all the agreements were already negotiated that makes the transaction pretty easily complete.

Unidentified Analyst

Got it, I appreciate it. Thank you, guys.

Scott Smith

Thank you.

Operator

And there are no further questions at this time. Please continue.

Scott Smith

Okay, thanks again everyone. I should appreciate you all join us this morning, obviously big news on the acquisition front. We continue to look and be active in the market. There is a lot of stuff, still people are trying to get things done here before yearend and were still looking at several projects and we’ll see what happens on that. And we are very excited about the transaction. It is obviously very accretive. As Richard said, we’ll help to drive I think our back on the distribution growth stream which is what I’m sure lot of our investors are very enthusiastic about and we think it’s good long term acquisition for us and we look forward to visiting with you again in 2013. So, thanks again.

Operator

Ladies and gentlemen, this concludes the conference call for today. Thanks for participating. You may now disconnect your lines.

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