Vanguard's CEO Discusses Q2 2012 Results - Earnings Call Transcript

| About: Vanguard Natural (VNR)

Vanguard Natural Resources, LLC (NYSE:VNR)

Q2 2012 Results Earnings Call

August 2, 2012 11:00 AM ET


Lisa Godfrey – Investor Relations

Scott Smith – President and CEO

Richard Robert – Executive Vice President and CFO

Britt Pence – Senior Vice President, Operations


John Ragozzino – RBC Capital Markets

Michael Peterson – McNicoll, Lewis, & Vlak

Abhishek Singhal – Macquarie Capital Securities

Lisa Godfrey

Good morning, ladies and gentlemen. This is Lisa Godfrey, Investor Relations for Vanguard Natural Resources, LLC. Welcome to our Second Quarter 2012 Earnings Conference Call on Thursday, August 2, 2012. We appreciate you joining us today.

Throughout today’s recorded presentation, all participants will be in a listen-only mode. After the presentation, there will be an opportunity to ask questions. (Operator Instructions)

Before I introduce Scott Smith, our President and Chief Executive Officer, I have some information to provide you.

If you would like to listen to a replay of today’s call, it will be available through September 2, 2012 and maybe accessed by calling 303-590-3030 and using the passcode 4555822.

A webcast archive will also be available on the Investor Relations page of the company’s website at, 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 This information was also provided in this morning’s earnings release.

Please note the information reported on this call speaks only as of today, August 2, 2012, and therefore you are advised that time-sensitive information may no longer be accurate at 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 will be available on our website, under the Investor Relations tab and on EDGAR. Also on the Investor Relations tab on our website, under presentation, you can find the Q2 earnings results supplemental presentation.

As a reminder, the next record date for our quarterly cash distribution is August 7th, with August 14th payable date. Unitholders of record will receive $0.60 for each unit held or $2.40 per unit on an annualized basis.

In addition, I’d like to point out Vanguard also announced today that we will launch a direct common unit purchase plan and a direct reinvestment plan that will begin on August 27, 2012.

The direct common unit purchase plan and DRIP will be administered by American Stock Transfer & Trust, LLC, also known as AST. AST will also become the appointed transfer agent and registrar for Vanguard effective August 27, 2012, replacing our existing transfer agent and registrar, Computershare Trust Company.

We will provide complete information on the direct common unit purchase plan and DRIP on our website on the August 27, 2012 launch and I can answer further questions at that time.

Please note that Computershare will complete our August 14th quarterly distribution and we will then transition to AST, who will be the transfer agent and registrar for our monthly distribution announced earlier today, with the first payable date of September 14th with a September 4th record date.

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

Scott Smith

Thanks, Lisa, and good morning, everyone. And thank you all for joining us on the conference call to review our results for the second quarter of 2012. With me are Richard Robert, our Executive Vice President and Chief Financial Officer; and Britt Pence, our Senior Vice President of Operations.

This morning, I’ll start with a summary of our production of the quarter then review this quarter’s capital spending and wind up with a few comments about acquisition activity, with an emphasis on our recently closed Arkoma Basin acquisition from Antero Resources. Richard will then provide a financial review and then we’ll open the line up for Q&A.

Before we get started, I wanted to remind everyone that although the Arkoma acquisition was effective April 1st, it did not close until June 29th. So in accordance with GAAP accounting rules, our balance sheet will show the impact of the acquisition while our income statement and cash flow will not.

In addition, the second quarter was the first quarter where the production associated with the Appalachian properties we exchanged for 1.9 million Vanguard common units at the end of the first quarter of this year was not updated. The Appalachian divestiture have the effect of lowering our second quarter production by over 1,300 Boe per day.

On to our production, average daily production for the second quarter averaged 12,338 Boe per day, down 7% over the 13,286 Boe per day produced in the second quarter of 2011 and down 9% over the first quarter production rate of 13,569 Boe per day.

On an individual product basis, the daily average production was 7,549 barrels of oil, 1,422 barrels of NGLs and 28,203 Mcf. We were pleased with the level of production we saw in the quarter, considering that the bulk of our spending -- capital spending focused on projects where production gains will come in the second half of the year.

In addition, as I just mentioned, this is the first quarter that production from Appalachia was not included, normalizing for the Appalachian unit property exchange, we ended the quarter a little above our first quarter production rate.

Now on to capital spending. During the second quarter we spent $15.1 million, which compares to $5.3 million than we spent in the second quarter of 2011. This level of spending is roughly 40% of our initial capital budget of $38 million that we sale out in the beginning of the year.

I’d also point out that almost half of the total capital invested was spent in June alone. For those investors and analysts that have followed us throughout our history, you’ll recognize this is not an unusual event, we typically have several quarters where our capital spending is concentrated in any given year.

As we’ve said time and time again, we believe our results should be measured on an annual basis and not on a quarter to quarter because of the nature of our capital spending throughout the year.

As we outlined in our earnings release this morning, we had some significant activities in the second quarter but saw minimal impact in our production this the quarter. We’re looking forward to these projects coming on line in the balance of the year and contributing to our results.

As the CapEx program has such a big influence on our DCF results, I thought I’d briefly go over the main areas where our -- majority of our activity was concentrated. First, I’ll start with the Elk Basin. We continue to have success in sand fracking the Madison formation in the Elk Basin field, which is our largest asset in Wyoming.

A total of four fracks were performed in the second quarter of 2012 and initial production from the first well began in mid-May and the last well was completed in June. The average cost per project was approximately $290,000, and yielded an average stabilized increase in production of 40 barrels of oil per day per well, for a total of 160 barrels of oil per day for the program.

Year-to-date, we’ve added roughly 200 gross barrels oil per day from the field through a total of five frack outs. We currently have six additional fracks planned for the balance of the year and I’d like to identified 20 additional candidates that we think have potential and we’ll move forward on it if we continue to experience the success we’ve had to date. We own a 67% working interest in this Elk Basin field.

In the Permian Basin, we drilled the Thomason Number 2 well, which is located in the Tex-Mex Field in Gaines County, Texas. This well is a north offset to our operated Thomason Number 1 well, which has produced a total of over 120,000 barrels of oil from each maintained well.

And [aspen and gel frac] was performed in the lower (inaudible) now in Wichita-Albany. In July, we installed broad pumping equipment in Wichita-Albany as we individually tested prior to moving up to test (inaudible) formation.

Once this well cleans up, we anticipate this well will have life at a rate of around 50 barrels a day. The completed well cost for this well is approximately $1.4 million and we own a 57% working interest in this well.

We also spent quite a bit of money up in the Williston Basin and Red River Formation. During the second quarter, we re-entered three vertical Red River wells in the Horse Creek field in North Dakota. The purpose of drilling horizontally to develop the Red River formation. Our average working interest in these wells is approximately 98%.

Unfortunately, operations had to be suspended on two other wells, due to wellbore problems caused by equipment failures. The Wagman 1130 was suspended after incurring $2.5 million of capital expense. We’ve begun settlement discussions with the various service and equipment vendors that were responsible for the problems we encountered to recover all the costs incurred in this well.

The second well, the (inaudible) 2-12, was suspended after $1.2 million of capital expense. In this well, due to equipment issues we’ unable to successfully cut a window and therefore remain in the effort.

The third well we drilled, the Olson 1130, was successfully drilled without any issues and reached total depth with a total of 4,500 feet of horizontal section being drilled. We’re in a completion phase and production is anticipated to begin in August.

We expect the Olson 11-30 to be at approximately 100 barrels oil per day. The total of completed well cost will be approximately $1.75 million and we believe we have an estimated ultimate recovery of approximately 200,000 barrels. As you may have noticed regarding the cost, this well does not require a frack job and it’s just conventional completion.

Also up in the Williston Basin, we drilled two vertical wells to develop the Red River formation in our Lonetree Creek well in Montana, the Jensen 3-9 and the (inaudible) 1-8. Our working interests in both wells is driving at 95%.

The Jensen well reached total depth in early June and the (inaudible) well reached total depth in mid-July. The Jensen is in completion phase and production will begin in early August. The (inaudible) completion will follow and should be online in mid to late August.

Both wells are expected to IP at approximately 100 barrels of oil per day with an estimated ultimate recovery of approximately 230,000 barrels per well. The total net profit for Vanguard for both wells is approximately $5.1 million.

We’re now going to talk a little bit about our Bakken activities. One of the first wells we participated in was the Brigham operated Braun 28-33 well, which was spud in mid-September of 2011, where we own a 12.5% working interest.

Although drilling operations went as planned, the operator experienced casing problems during the ninth stage of a planned 40-stage frack. Operations were suspended until remedial procedures were drawn up.

After sweep and all these was done to provide sufficient isolation to continue the remaining fracks, the balance of the frack job was successfully pumped and well listed on production in mid-May of 2012.

During the June of 2012, the first full month of production, the Braun well averaged 573 barrels of oil per day and 616 million cubic feet of gas per day on a gross basis. As we discussed in our first corporate earnings released, I apologize. So that’s all for that well.

On to another well, the Shepherd 55-01, we talked about this well in our first quarter’s release where we had previously sold to Oasis, the operator for $1 million half of our position and agreed to participate in a test well with a 25% working interest. The AFE well cost for this well was $9.6 million.

This well was drilled and completed with no significant issues or unplanned expenditures. The Shepherd well began producing at the end of May of this year and has produced 15,000 barrels during its first 30-day period, giving a 30-day IP rate of right of 5,500 barrels of oil per day. This well is currently producing above 275 barrels of oil per day.

(Inaudible) what I hope but I’m able to get across that we’re extremely busy during the second quarter. In fact the $15.1 million we spent during the quarter is the most to date we’ve ever spent in any quarter during our history. And as I said before, all this spending didn’t result in any material increase in our production for the quarter.

Looking forward for the rest of the year, we expect to spend approximately $28.5 million on capital projects. This spending breaks down as follows. In the Arkoma assets, we have some substantial operated and non-operated projects budgeted for the next six months in the Woodford Shale.

These projects range anywhere from a 3% working interest to a 45% working interest and are both operated and non-operated. During the third and fourth quarters, we anticipate spending of approximately $10.5 million of capital-related to developing primarily Woodford Shale wells.

Outside the Arkoma, we plan to spend approximately $18 million on projects, such as the continuation of our Elk Basin frac program, drilling another development well in our Parker Creek Field in Mississippi and spending approximately $4 million participating in two Bakken wells, one in the third quarter and another in the fourth quarter with an average working interest of approximately 0.2%.

Now, I’ll talk briefly about our acquisitions. Obviously, the highlights of the quarter was the announcement of subsequent closing of the predominantly natural gas assets in the Arkoma Basin that we acquired from Antero Resources. With this transaction complete, our production on a Boe basis will increase close to 100% over our second quarter numbers.

As we stated on our last earnings call, we believe that in the current environment it is a great time to buy quality natural gas assets and we’re very pleased to complete this large purchase of natural gas assets at these best prices.

The properties we acquired are located at Woodford and Fayetteville Shales and have total crude reserves of approximately 402 Bcfe and about 57% crude developed and 82% natural gas.

We’ve identified approximately 180 gross locations that we intend to develop over the next several years, which provide very good return even at today’s strict pricing. The optionality we gained from this transaction is the inventory of an additional 1,100 crude locations that we believe would be economic if gas prices recover to sustain $4 or $5 level. This acquisition truly has the potential to be a game changer down the road when natural gas prices improve.

In the meantime, however, with the hedges we acquired subsequently restructured, 100% of the natural gas full production is hedged for the next five years at a basis protected weight of average price of $5.04 per MMBtu.

An additional benefit of this acquisition was the effect on our PUD inventory. Our crude development reserves have increased from 13% of our reserves at year end 2011 to 28% of our reserves now, giving us ample years of low-risk drilling inventory.

Although, drilling is not a significant component of our growth, it’s nice to have an inventory of viable drilling opportunity that we can develop should acquisition activities slow down in the future.

With respect to other acquisitions, we have been actively reviewing opportunities and have been very pleased with deal flow. We’ll continue to look for look for assets that fit our business model and will be accretive to our unitholders.

Lastly, as I’m sure many of you saw this morning. We announced we’ll be changing our distribution policy from the customary quarterly distribution to paying a monthly distribution.

Overall, we feel this is a significant step in further aligning Vanguard with the interest of our unitholders. MLPs are designed to be an income vehicle, and what better way to pay unitholders looking for income than on a monthly basis.

Additionally, paying monthly will allow surpass on the benefit of accretive acquisitions quicker instead of having to wait an entire quarter. That being said, this does not change how we look at our distribution policy and we will continue our steady and measured approach to future increases.

We’re very proud of our ability to have increased our distribution over 41% since our IPO and consecutively over the last seven consecutive quarters and we look to continue that trend in the future.

Now, I will turn the call over to Richard.

Richard Robert

Thanks, Scott. Good morning, everyone. As I stated on our last earnings call, our goal during the first quarter was to improve our capital structure and generate more liquidity, so that we could effectively compete for larger acquisitions. We created that liquidity and in short order we executed the second part of that goal.

The Arkoma acquisition is our largest asset acquisition to date and we not only had the liquidity but also the infrastructure in place to effectively close the transaction and we are currently in the process of integrating these assets.

To aid in the integration, we have a two-month transition services agreement in place with Antero Resources, which greatly aids in making the integration as smooth as possible.

Obviously, exchanging senior debt for high yield debt came at a price in the form of higher interest expense. But we put that capital into work in the form of very accretive acquisition and we’re excited about the incremental results, which we will begin to see in the third quarter.

With that, I wanted to discuss four topics this morning. First, our financial results for the second quarter then our updated 2012 guidance and preliminary 2013 outlook, followed by our new and improved hedge profile and finally a brief liquidity update.

With respect to our financial results, we reported an adjusted EBITDA attributable to Vanguard unitholders of $44.5 million for the second quarter of 2012, as compared to $36.5 million reported in the second quarter of 2011 and down from the $53.2 million in the first quarter of 2012.

I typically like to open my discussion with a statement that we’re pleased with the quarter’s results. Unfortunately, I can’t say that this quarter. We faced several headwinds that negatively impacted the quarter. There were five primary factors that contributed to the lower EBITDA, as compared to the first quarter this year that I’d like to discuss in more detail.

First, average oil prices quarter-over-quarter have decreased almost 10%. We saw a high -- we saw a high of an average of $106 per barrel in March to a low of $82 per barrel in June. This impacted Vanguard in two ways.

First and foremost, we have to sell our physical production at a lower price translating to less revenue. Our hedges did mitigate some of this decline, but because we use collars in our hedging strategy, we do and will continue to see fluctuations of revenues even though we are almost 95% hedged on our oil production in 2012.

Over 40% of our hedged production in 2012 is made up of collars and three-way collars, which means we bear the cash flow risk or reward as oil prices go up and down in these volumes.

Unlike a swap, where you get the fixed hedge price no matter what, a collar allows you participate in the upside to a certain price or conversely as was the case this quarter, the downside to a certain price. In the first quarter of 2012, we were principally getting the ceiling price on our collars and in the second quarter we were typically getting the floor price.

Second, while we do our hedge -- while we do hedge our oil via NYMEX pricing, we are still subject to basis differentials in the various areas that we produce. The same supplier of oil barrel in West Texas receives a different price than one produced in the Rockies, for example. This is called basis differential.

This difference or differential than NYMEX pricing typically can’t be hedged in most cases and unfortunately oil differentials continue to be wider than expected in the second quarter.

Where we can hedge basic differentials such as the less market where we have production associated with our 2011 Gulf Coast acquisition, we have done so. However, for a majority of our oil production, this is just not possible or else we would, as we are always looking for ways to mitigate our risk.

Two specific examples of what we saw in the second quarter are as follows. Our Wyoming, Montana and North Dakota production experienced widening differentials due to a lot of supply trying to get to market, pipelines, trucks and rail are all being maximized.

However, the most significant impact to our revenue decline in this area occurred when an Enbridge oil pipeline system suffered three operational issues in succession during February, March and April. This exacerbated the already constrained oil transport capabilities in the area, which triggered pricing pressure. The most significant revenue impact we saw with Elk Basin, pricing which clearly reflected the incident.

Our Elk Basin pricing, which is the Gold River posting for those that want to get specific, reflected a negative differential of $11 in January this year. In March, that differential had widened to $30, in April it was $32 but by June, we were back down to $13, which is in line with historical norm.

In addition, we along with the rest of the industry saw the Permian Oil differential widened, due to some of the same issues as our Rockies production, too much supply trying to get to market. The inability for oil to find its way out of West Texas was and continues to be plagued by the lack of pipeline capacity, trucking issues and a lack of storage space at cushing.

Pipelines are in the process of upgrading and are expanding their systems, capacities as a cost to achieve such upgrades and expansion are recouped through pipeline tariff increases. Historically, these have been annual adjustments in the 1% to 2% range but the market is seeing 9% to 10% tariff increases currently.

In summary, our two largest areas in the second quarter were affected by widening oil differentials that just cannot be hedged. We saw a 9% decrease in the average NYMEX oil price from the second quarter of 2011 and our realized pricing decrease by 12%.

We are encouraged, however, that these have begun to normalize and we expect that the balance of the year will not see us heavily burdened by these issues. However, as I will discuss in a little while, our guidance reflects a more conservative oil differential going forward in 2012 and the full year of 2013.

Getting back to the five issues, the third issue was lower NGL price realizations. In the second quarter of 2012, we saw a 24% decrease in the average NGL realization from the second quarter of 2011 and a 16% decrease compared to the first quarter of 2012.

As a percentage of NYMEX oil, NGL realizations declined from 57% in the first quarter to 48% in the second quarter. Since NGL cannot be hedged effectively due to cost and liquidity constraints, we bear the cash flow risk and reward related to NGL price fluctuation.

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

In addition, none of our NGLs are priced off the Conway listings. So we do not see some of the expressed levels that other companies are facing as it relates to Conway pricing, where average realizations have been as low as 30% to 35%.

While, there has been some improvement in the NGL market of late, our updated 2012 guidance and preliminary 2013 outlook, which I’ll get into shortly. Reflect a more conservative assumption for NGL price realizations. We hope that there is upside to the assumptions but we felt that it was more prudent to be conservative.

Fourth, as Scott mentioned, this was the first quarter we did not have the contribution from the Appalachian properties that we exchanged for Vanguard units at the end of March. Production from these assets average over 1,300 Boe per day and is a large reason why our natural gas production, in particular, decreased quarter-over-quarter. Normalized for this, total production was slightly up from the first quarter.

The fifth, the largest issue was prior period adjustment or PPA as we call them. PPAs are normal, recurring part of this business. It is typical to process revenue checks and joint interest billings that include items for prior periods. It is typical to true up for crude revenue and lease operating expense estimate when actual amounts are known -- when actual amounts are known, which can be several months after the fact, particularly on acquisitions with non-operated properties.

Typically, PPAs are not material but this quarter they were. They negatively impacted our EBITDA by $4.6 million. As such the PPAs had a negative impact on reported LOE production volumes and revenue, which lowered our realized pricing. So the good news is that our actual realizations on a production basis were better than our accounting reported numbers.

And just to give you an example of a PPA that we were faced with this quarter, on the LOE side, we had acquired -- as part of the Encore transaction we acquired a non-operated well that we had been receiving revenue on. And we recently noted that there were no expenses associated with that revenue. And when we looked further into it, we found that Encore had never paid these operating expenses on this property from 2008 forward.

And so, we were stuck with about a $1 million bill, that we had accrue this quarter on that particular issue. So not a good thing to find out and but you might ask that well, is that typical? And the answer is certainly not. There are too many operators out there that will pay you revenue and not allow you to pay your bills. In any event, not at least is what is typical.

So, no, we do not anticipate finding anymore $1 million hits like that. So I just wanted to give you a little perspective on what we were faced with. In a nutshell, we saw some significant headwinds that caused our EBITDA to decrease in the second quarter. However, we are hopeful that with recent improvements in oil pricing and NGL pricing and the normalizing of oil differentials the second half of the year we’ll see improvements over the first and second quarter.

Lastly but certainly not least, with the closing of the Arkoma acquisition we have further diversified our revenue stream and have also hedged the basis differential through swaps for the next five years on 100% of the expected crude production. In terms of our distributable cash flow, the second quarter 2012 totaled $18.9 million or $0.36 per unit. Although, this level of distributable cash flow generated coverage ratio of less than one-times for the quarter.

I want to remind you, as Scott has already, that we looked at our distribution coverage on an annual basis, not quarterly, since capital expenditure swing from one quarter to the next. This is evidenced by the fact that our first quarter 2012 coverage ratio was in excess of 1.4 times.

In addition to the factors, I just discussed that impacted EBITDA. We also had an increase of capital expenditures in the second quarter that Scott has gone over in detail and full impact to our interest expense for the senior notes issuance.

I’d also like to point out, that we take a fairly conservative view on how we characterize our capital spending. All of our capital spending is considered maintenance capital. Even though, a portion of what we did spend will grow our oil production.

Now, we’d like to review our updated 2012 guidance and a preliminary 2013 outlook. With the changes in our capital budget and the Arkoma acquisition, we felt it was important to financial and production guidance and provide more transparency to what we are expecting for the full year 2012 and 2013.

In addition to adding the Arkoma acquisition to our forecast, we also took this time to rationalize our capital budget on existing assets. As Scott mentioned, this acquisition has a significant drilling component. And we felt that it was prudent to delay some of the Vanguard projects that we had originally slated for 2012 and put them into 2013.

Some of the other major assumptions and changes that we’ve made for our previously issued guidance, that I believe are important highlight are our NYMEX oil swaps pricing has decreased from approximately $108 per barrel in 2012, to approximately $90 per barrel for the remainder of 2012 and for the full year of 2013. With natural gas prices staying relatively flat.

Differentials have been widened to reflect the current market conditions in both the oil and NGL markets. We have updated the guidance through reflect the March equity offering and the April bog offering and for purposes of computing distribution coverage levels with our guidance. We assume no additional acquisitions, no additional equity or debt offerings and that the current distribution rate of $0.60 per quarter or $0.20 per month will not change.

Please keep in mind that the reality is that all these things will change over time. In light of more conservative assumptions which reflect the current environment we’re in. The anticipated impact of new wells coming on through the rest of the year and a positive impact of the Arkoma acquisition, we expect to generate between $240 million and $250 million in adjusted EBITDA in 2012 and $150 million to $162 million in distributable cash flow equating to a coverage ratio of approximately 1.25 times for the full year of 2012 at the midpoint.

Taking the conservative approach to our 2013 outlook, we’re anticipating a significant increase to our EBITDA and distributable cash flow principally, as a result of the Arkoma acquisition. Based on the numbers outlined in the earnings release, EBITDA is expected to range between $270 million and $285 million and based on our current annual distribution rate of $2.40 per unit.

We expect to generate a distribution coverage ratio of about 1.3 times, again at the midpoint, for 2013. Our number one goal is to provide a stable yet growing distribution to our unitholders for the long-term and not only do we feel very comfortable with our distribution coverage for 2012 and 2013. We believe we are well prepared for almost any price environment.

This leads me 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 at adding to our hedge positions primarily as a result of the gas hedges associated with the Antero acquisition.

In addition to the assets, we also acquired a hedge portfolio valued at approximately $100 million. These hedges were priced significantly higher than the current NYMEX, 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 substantially in 2012 and 2013. We felt there is more prudent to take this value and by lowering the swap price to $5.04, we increased crude production hedge to approximately 100% for the next five years.

What is of equal importance is that our swap also hedged the basis or in other words our hedges -- our hedge pricing is based on the Transco Zone 4 Index, which is also the index that we’re getting paid on. So that we are now locked into margin no matter what happens to the basis or net gas pricing in this area.

In terms of percent of production hedged, 2012 expected gas production is 88% hedged, 2013 is 100% hedged. 2014 is hedged at 86%. 2015 is 76% hedged. 2016 is 75% hedged and the first half of 2017 is over 75% hedged. All that weighted average prices of about $5, which is significantly higher than the current crude levels.

Considering the last quarter, we had natural gas hedges only going up to 2014. We have made considerable headways improving our natural gas hedge portfolio.

On the oil side, 2012 expected oil production is about 95% hedged. 2013 is 91% hedged. 2014 is 66% hedged. Unlike gas, the weighted average hedged oil price closely approximate the current market but you must consider -- but you must remember one thing. The weighted average price we report only takes into consideration the floors of our collars. Traditional collars and three-way collars constitute 45% to 50% of our hedges in 2012 and 2013 and almost 30% in 2014.

What this means is that we do have the ability to participate in the upside above our weighted average price for approximately $91. And we aren’t expected to see any more material negative cash flow impact if oil prices continue to decline for the rest of 2012 and 2013, because we’ve already hit our floor price.

Conversely, if oil prices improve we have many ceiling in excess of $100 and even some as high as $120. So there is ample room to reap the cash flow benefit should oil price improve. More details on our current hedge portfolio and percent hedged can be found in supplemental Q2 information package posted to our website this morning.

Let me turn to our credit facility for a quick update. In March, our borrowing base was reaffirmed at $755 million but was reduced to $740 million on March 30th for the Appalachian unit change and further reduced to $667 million for the senior notes offering in April, which is standard practice.

However, with the Antero acquisition, it was increased to $975 million, taking into account the additional value of the reserves and hedges. Taking this into consideration at June 30th, Vanguard had embedded under its reserved-based credit facilities totaling $734 million.

As Scott mentioned in the beginning, because the Arkoma acquisition closed on June 29th, we did not see any benefit to our income statement, EBITDA, or DTF. But had the full impact of the acquisition on our balance sheet.

This simply means that we had increase borrowing associated with the acquisition on our balance sheet but not the cash flow, which will make our debt metrics seem high. We have the potential to reduce our borrowing at our credit facility utilizing proceeds from cash flow from operations. And currently Vanguard has $725 million in outstanding borrowings under the revolver, which provides us with $250 million in current capacity under the senior revolver.

As Scott mentioned, we’re proud of the fact that we’ve increased our distribution to unitholders by over 41% since going public while still maintaining a very strong annual distribution coverage ratio. On that same sense, we’re not done.

We believe the Encore and now Arkoma acquisitions demonstrate the type of growth that Vanguard is capable of. Our future growth potential is significantly enhanced with the addition of senior notes in our capital structure, as it will allow us to access significant amounts of acquisition financing in a very timely manner.

Finally, we hope that our transition to a monthly distribution policy demonstrates that we are listening to our unitholders’ wants and helps create long-term value for our unitholders. This concludes our comments. We’d be happy to answer any question you might have at this time.

Questions-and-Answer Session


(Operator Instructions) The first question comes from John Ragozzino. Please go ahead.

John Ragozzino – RBC Capital Markets

Good morning, everybody.

Scott Smith

Good morning, John.

John Ragozzino – RBC Capital Markets

Richard, you talked about some really good details as far as the second half of this year’s CapEx budget as far as geography is really a concern. Can you give us a better feel for how each quarter shakes out in terms of total absolute value, whether it’s going to be more 3Q weighted or 4Q weighted?

Richard Robert

I would expect that 4Q is probably going to be a little heavier than 3Q just because it’s going to take us a little while to get everything related to Antero up and running in terms of permits and what have you?

Scott Smith

But to follow up, it’s not going to be materially different. Maybe just slightly skewed to the fourth quarter but for the most part, it’s pretty balanced.

John Ragozzino – RBC Capital Markets

Okay. And then the updated guidance, there was a slight downtick in the crude volumes. Is that relation-- is that related to the Appalachian sale, or is that-- you had mentioned some shipping of capital in terms of making room for Antero. I thought that the majority of production in the Appalachian areas was natural gas.

Richard Robert

Yeah. That’s true. It is the latter of what you were suggesting. We did defer the oil projects that Vanguard had into 2013, which slightly reduced the 2012 guidance in terms of production.

John Ragozzino – RBC Capital Markets

Okay. That’s helpful. Let me see what else we’ve got here. Talking about Antero, if you think about 2013, current gas price environment, you gave us a pretty good feel for what activity levels will look like. Is there a lot of upside to that? If we were in, say, like a $4.50 gas environment, a $5 environment, would there be a significant shift in your plans there?

Scott Smith

I think it’s -- if that happens, the industry would be quite happy. We would be. And I think probably what we would have, if we saw that happen we would shift more of our capital spending to the Antero asset base and away from some of our other projects that we had in our plans already that were used in our forecast, increase that level of spending because the returns are quite good at those levels.

Richard Robert

My concern is we, along with everyone else, would chip their spending for gas. If the gas supplies were altered and we wouldn’t be at that $4.50 range anymore.

John Ragozzino – RBC Capital Markets

That’s not what I’m modeling either way. It’s strictly hypothetics. Just one or two more, Richard, big picture, could you just talk about your view as far as it relates to distribution growth and the immediate pass-through of DCF accretion when you do deals as size as the Antero deal and just the way that you view the strategy there?

Richard Robert

Sure. Our strategy has walked a little bit from early on where we would typically see a large increase and then nothing for a couple of quarters until we get another transaction where we have another increase and then nothing. I think again we’ve been listening to investors and what we’ve been hearing is, they prefer slow and steady.

And so that’s kind of the course we’ve elected. We won’t give everything all up at once but we anticipate giving a little bit every quarter. So that we can achieve our internal goal of 5% to 6% distribution growth per year.

John Ragozzino – RBC Capital Markets

All right. Just one more, just clarification. You had mentioned that nothing gets priced in the NGL side. Does that include the Antero assets as well?

Scott Smith


John Ragozzino – RBC Capital Markets

Where do those go down to?

Scott Smith

Those got to Bellevue Brighton.

John Ragozzino – RBC Capital Markets

Okay. Great. Thanks very much, guys.

Scott Smith

You’re welcome.


Thank you. The next question comes from Michael Peterson. Please go ahead.

Michael Peterson – McNicoll, Lewis, & Vlak

Good morning, gentlemen. And welcome back, Lisa.

Lisa Godfrey

Hi. (Inaudible).

Michael Peterson – McNicoll, Lewis, & Vlak

Sure. Richard, if you could share your thoughts on the capital structure. I’m interested in hearing a little bit about how you think about the utilization on your recently increased credit facility and the capital structure in general.

Richard Robert

Well -- now with the addition of senior notes in our capital structure, it give us obviously an opportunity to term out borrowings on our revolver. It kind of matches our long-term assets with the long-term debt. From a facility standpoint, we like to know what our interest costs are going to be and obviously the bond market allows us to do that as well.

We will continue to look for opportunities to term out debt under the revolver and the revolver will becomes foreign acquisition facility that we’ll use as needed to fund transactions initially and then, again, look for opportunities to term it out.

Michael Peterson – McNicoll, Lewis, & Vlak

That’s helpful. Thank you.

Richard Robert



(Operator Instructions) Thank you. The next question comes from Abhishek Singhal. Please go ahead.

Abhishek Singhal – Macquarie Capital Securities

Yeah. Hi. Just wanted to add on to the previous question, like, I was wondering if you could provide some color on what kind of debt to EBITDA or leverage ratio you would be comfortable with and what do you see for the remainder of the quarters and the next year.

Richard Robert

Debt to EBITDA is something that we focus on. We prefer to operate at lower levels. Currently, obviously we’re willing to lever in order to get a transaction done, especially a transaction of this size.

With the anticipation of lowering that, the equity offerings began on an opportunistic basis. We want to operate under three times on a long-term basis. And we’ll get there, again, via equity offerings, as well as using our excess cash flow to pay down our debt over time.

We do have relatively good excess cash flow after distributions, after maintenance capital and after debt service. So we anticipate using those dollars to reduce our debt over time as well.

Abhishek Singhal – Macquarie Capital Securities

Thank you.


Thank you. There appears to be no further questions.

Scott Smith

Okay. Again, everyone, thanks so much for joining us this morning. If any questions do pop up on the investor relations side with regarding the DRIP program or the direct stock purchase program, please reach out to Lisa. And then on any of the information that was in the releases this morning, please reach out to Richard or myself. So again, thanks for joining us and we’ll look forward to visiting with you again in November.


Thank you. This does conclude the conference call for Vanguard Natural Resources quarter two 2012 earnings call, sorry. Thank you for participating. You may now disconnect.

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