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Executives

Lisa Godfrey – Director-Investor Relations

Scott W. Smith – President and Chief Executive Officer

Richard A. Robert – Executive Vice President, Secretary and Chief Financial Officer

Analysts

Ethan Bellamy – Robert W. Baird & Company

Dan Guffey – Thomas Weisel Partners

Michael D. Peterson – MLV & Co. LLC

John J. Ragozzino – RBC Capital Markets

Adam Leight – RBC Capital Markets LLC

Praneeth Satish – Wells Fargo Securities LLC

Vanguard Natural Resources, LLC (VNR) Q4 2012 Earnings Call March 4, 2013 11:00 AM ET

Operator

Good day, ladies and gentlemen. Welcome to the Vanguard Natural Resources Fourth Quarter and Year End 2012 Earnings Call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions. (Operator Instructions) This conference is being recorded today, Monday, March 4, 2013. I would now like to turn the conference over to Lisa Godfrey, Director of Investor Relations. Please go ahead.

Lisa Godfrey

Good morning everyone and welcome to the Vanguard Natural Resources LLC fourth quarter and year-end 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 April 02, 2013, and may be accessed by calling 303-590-3030 and using the pass code 4599724#. 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 Friday’s earnings release. Please note, the information reported on this call speaks only as of today, March 04, 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-K that was filed last 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 Q4 and year-end 2012 earnings results supplemental presentation. As a reminder, the most recent record date for our monthly cash distribution was March 1, with a March 15 payable date. Unitholders of records will receive $0.2025 for each units held or $2.43 on a per unit on an annualized basis.

In addition, the company’s 2012 K1 tax packages will be available for immediate download from our website at vnrllc.com by this Thursday, March 7, with original 2012 K1 tax packages mailed to all unitholders later this week as well. For any questions regarding schedule K1, unitholders are invited to call the tax package for helpline at toll free 866-536-1972 or via e-mail at VanguardK1Help@deloitte.com.

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

Scott W. Smith

Thanks, Lisa. Welcome everyone and thanks for joining us this morning on the fourth quarter and year-end 2012 conference call. This morning, I’ll start with the summary of our two large acquisitions in 2012 and our recently announced Permian transactions with Range Resources. Then we’ll review our results for the year and I’ll conclude my remarks with a brief discussion of our year-end reserves and operations. Richard will then proceed with the financial discussion and then we’ll open the line for Q&A.

Before we get started, I would like to point out that reserve and production numbers we will be referring to this morning in the call do not include any contribution with the Permian assets we are acquiring from Range.

2012 was a very active and successful year for Vanguard in the acquisition front, and marked a strategic shift towards natural gas property, a very different highlight when I spoke to you on last year’s call. Although our 2012 revenue was primarily weighted towards liquids at 85%, our production mix shifted from 35% natural gas in 2011, to 49% natural gas in 2012. We project natural gas will comprise approximately 65% of our total production in 2013, excluding the contribution from the new Permian assets.

Should the trajectory of natural gas hold true and prices rebound from the current 12-month strip of 350 to the mid $4 levels in 2017 as the futures markets predict, there are decision to invest in the large quality natural gas assets will create significant upside potential for the benefit of our unitholders.

First major transaction 2012 is the $434 million acquisition of Woodford in Fayetteville Shale assets near Arkoma basin that we purchased from Antero Resources and which closed in June of 2012. Highlights of this acquisition include total proved reserves of approximately 362 Bcf, calculated using year end SEC pricing. Approximately, 54% of the reserves will classify at year end as proved developed producing with the balance in the proved undeveloped category.

Fourth quarter net production in the Woodford was 52.8 million cubic feet equivalent per day, and the Fayetteville is right 8.7 million cubic equivalent per day. Using established production rate, we have an R over P ratio of 16 years from these two areas. A significant characteristic of this acquisition is the Woodford drilling location we are able to include in our PUD reserves, which add to our inventory of viable projects for this year’s capital budget, and which will be a significant portion of our capital spending plans for several years in the future. This acquisition added 180 drilling locations, which are economic at today’s script pricing, and there are approximately 1,100 gross Woodford locations that were not included in our services, but would be economic natural gas prices by $4, $5.

As I will describe in more detail shortly, we have a 10 well program in place this year that we are confident will generate attractive returns. Although, it was a minor part of the transaction, the Fayetteville assets have continued to get attention by the primary operator in the area, Southwestern Energy. We have seen a steady stream of A & B from MS, they focused their development activities in their highest return areas, where we fortunately have a minority working interest position. This activity is an added bonus to this transaction and as we did not contribute any value to undeveloped reserves in our assets.

Second large transaction of 2012 closed at the end of the year and was $335 million acquisition of primarily natural gas assets in the Piceance, Wind and Powder River basins from Bill Barrett Corporation. With this purchase, we have increased our operating footprint in two of the largest producing basins in Wyoming and also added a high quality non-operated position alongside what we believe the leading development company in the Piceance Basin of Colorado.

One of the challenges we faced in negotiating this transaction was to structure the acquisition in such a manner as to negate the near-term declines of production in order to maintain cash flow. We and the Barrett team solve this issue by structuring the acquisition of the Piceance assets, which comprised approximately 60% of the total package to include gradually increasing working interest overtime. Initially, our working interest is set at 18%, but the interest gradually increases through 2015 held its cap at 26% as of January 1, 2016. By implementing the structure along with our edging strategy, we anticipate having relatively flat cash flows each year through 2016 absent any significant capital expenditures.

I want to reiterate that this is absent any significant capital expenditures. This is important because we and the Barrett team haven’t modeled any PUD development drilling on the acquired property until 2016. Current production from this acquisition is approximately 60 million cubic feet equivalent per day, which is broken now at about 1500 barrels of liquids, 51 million cubic feet per day. And our R over P ratio based on our year-end pricing reserve estimates is right at 14 years.

Using SEC year-end pricing the total reserves from this acquisition are approximately 151 Bcfe, with 83% of the reserves being proved developed producing. You might notice much lower than the reserves we stated in our closing press release, which were calculated using script pricing and the time. As you are all aware SEC did takes the industry use to previous 12 months average prices for both natural gas and oil in our case $2.76 per MMbtu, $94.60 per barrel to calculate our year-end reserves. Using this methodology we saw reduction of about 164 Bcfe from our reserve estimate at year-end on this transaction that were done using script pricing. And saw roughly 23 Bcfe reduction in our internal evaluation of our Woodford and Fayetteville reserve that which were done on the same basis.

However investor should take comfort in that we fully hedged both of these transactions when we saw in the respective PSA or in the case of the Arkoma acquisition, the hedges that came with the transaction. So the value of the asset the effective cash flows we acquire are effectively locked in. Bidding investors should focus more on reserve values calculated at NYMEX script pricing that is a much more reflective of the true value of the Company value.

In addition, as we stated earlier, the expected production from these transaction has been hedged for the next four or five years. So our cash flows are protected. This strategy is a core principle of the Company. We believe it’s paramount to successfully managing next treatment would be.

During the course of the year, we also completed several small bolt-on acquisitions in our core operations. In total, we closed three other small acquisitions for about $25 million and added reserves about 1.7 million barrels.

Last week we’re pleased to announce, we have entered into a purchase and sale agreement for $275 million acquisition with Range Resources, for package for producing assets in the Permian Basin. These assets were mature low risk properties with significant upside potential through the hindsight of opportunity in infill development drilling, and are an excellent addition to our current portfolio of Permian assets.

Highlights of this transaction include, total proved reserves of 22.8 million barrels of oil equivalent approximately 56% of the reserves are in the proved developed producing category; 22% are considered PDNP and are associated with recompletions in existing producing wells and the balance of reserves are PUD reserves to be developed through infill drilling.

The assets are currently producing approximately 17 million cubic feet of equivalent per day with approximately 41% being natural gas, 28% oil and 31% NGLs. The reserve mix is approximately 43% natural gas, 25% oil, and 32% natural gas.

Additionally, these assets have a relatively low LOE cost of just under $7 per barrel oil equivalent. As I mentioned earlier, this acquisition includes a large inventory development projects roll through recompletion work in drilling. What we believe we can deploy approximately 25% of free cash flow from the assets and grow production and cash flow over the course of the next four to five years.

I would point out that although we have modeled this transaction using this type of development plan, we do have the ability to accelerate capital spending on the assets should we choose to do so. We’re looking forward to closing its transaction next month, beginning to start a recompletion program in the second half of the year.

Now, we will review our year-end total proved reserves on a company basis. Year end 2012 total proved reserves calculated at using SEC pricing were 152.2 million barrels of oil equivalent, up 90% over a year end 2011 reserves of 79.3 million barrels of oil equivalent.

The PV10 value of the reserves using this pricing methodology is approximately $1.6 billion. From the commodity perspective, our reserve mix balance was 28% oil, 12% NGLs, and 60% gas. In addition, our percentage of proved producing reserve decreased year-over-year from 86% in 2011 to 74% of total crude reserves.

As I said earlier, we think investors should focus on the company’s reserves and value using split pricing rather than the static SEC price. Our year end internal reserves calculated using strip pricing at the beginning of 2013.

Our 184 million barrels of oil equivalent had a PV10 value of approximately $1.9 billion. On a reserve basis, this is the 18% increase over the SEC. It includes the value of our hedge portfolio in this calculation, the PV10 value of our asset base would be approximately $2 billion. Including the acquisitions we’ve closed in 2012, we replaced just under 1200% of our 2012 production at a reserve replacement cost per BOE for approximately $9.16.

We’ll now review our production results in capital spending. First off, average daily production for the fourth quarter was 22,803 barrels of oil equivalent per day, up 67% over the 13,686 barrels of oil equivalent per day produced in the fourth quarter of 2011. And down 6% over the third quarter production rate of 24,367 barrels of oil equivalent per day, we saw in the third quarter.

On a product basis, the average daily production was 7,575 barrels of oil, 2279 barrels of NGLs and 77,688 Mcf of natural gas. Although this production figures include the impact of the Arkoma acquisition, there was no contribution from the Barrett acquisition which closed at the end of the year.

Average daily production for the full year was 18,298 BOE per, up 37% over the 13,405 BOE per day produced in 2011. On a product basis, the average daily production was 7,536 barrels of oil, 1813 barrels in NGLs and 53,695 Mcf of gas. Again this will not include any benefit from the Barrett acquisition and only half the year Arkoma acquisition.. Additionally, I’ll remind you that we exchanged our Appalachian assets in the second quarter which is included in the 2011 production numbers.

An important note, and that over the course of the year, our oil production actually increased slightly, here we did not do any oil acquisitions, this is direct results of the capital we spend at 2012, which was focused on high return oil projects.

For 2013, Vanguard has already begun several capital spending strategies that we are confident, we’ll generate long-term value to our unitholders. Our engineers have reduced the inventory of drilling and development projects available and created a drilling and capital expenditure budget for this year they calls for increase in capital expenditures over 2012 spending levels to approximately $55 million with an additional $5 million to $10 million in operating projects identify should we need to reallocate resources as some of the non-operated development plans get behind.

This capital budget is focused on deploying capital on higher rate of return projects that are aimed to reducing the impact of the natural declines in our oil in natural gas production. It includes new development drilling in the Woodford Shale, Fayetteville Shale, and non-operated horizontal Bakken wells in addition to other high return activities across the asset base. Our drilling operations are already underway as we are near conclusion of the drilling pace of the first five well development plan at the Woodford.

I’ll highlight a few of the main details of our 2013 program. Approximately $23 million are reliant on non-operated drilling primarily focused on the Bakken, Woodford and Fayetteville Shales. This is important to note because over 40% of our budget relies on other operators. Although being a non-operated partner allows Vanguard to benefit from the scale and operational expertise of our partners comes at a cost, they do not executive on the timeline we forecast. That is why we have a contingent budget in place to help build the gap should we recognize this year that certain projects are not going to come declaration.

On the operated side we intend to spend approximately $32 million, roughly 35% of the spending has been focused on the Woodford assets, where we plan to drill 10 gross, 4 net wells in the liquids rich portion of the field.

We have determined along with our partners that the best development plans to drill up to five wells in a section, and see all the wells at the same time. This allows us to achieve efficiencies in both drilling and completion stages, while also not tracking into currently producing offset wells.

We’ve already seen the benefits of this approach in our current drilling operations as each wells have been drilled successfully faster and at less cost and we think our overall completed well cost on a gross basis, will run around $4 million or approximately 15% less than we originally forecast. The first five wells are plan to be online by June of this year, with the second five wells being drilled and completed during the third quarter. Additionally, we plan to continue our very successful Madison refrac program; and had scheduled 12 throughout this year at a net cost of approximately $2.7 million.

Remaining capital spreads throughout our area is focused on high return projects and other maintenance related activities, including approximately $4 million on the recompletion program on the new range assets.

In summary, 2012 was another great year for the Company. We managed to achieve excellent results on all fronts, and most of all, successfully closed two major acquisitions. Our results are the reflection of the efforts of our employees and their hard work on behalf of the company to achieve its goals. With the addition of the accretive acquisitions and associated increase in our cash flow, we’re able to increase distributions over 5% from December of 2011, and have achieved an overall distribution growth of approximately 43% since 2008.

Additionally in August of last year, we instituted a monthly distribution program, which continue to be a major differentiating factor from all of our peers in the MLP space. We believe that over time, this practice will be instituted by more of our peers as they recognized the merits of paying distributions monthly to their unitholders.

It continue to be our goal to essentially increase our distribution in a manner that we feel sustainable over the long term. Our current distribution is $2.43 annually based on Friday's closing price of $27.77. We are currently trading in attractive yield of 8.8%. We continue to add this to the capital markets in an active acquisition market as evidenced by our recent range now. We are poised to continue the momentum of growth for 2013. We're extremely padded up the prospects for the balance of the year and it remain confident that with our structure and cost of capital we can compete effectively and competitively for the right type of assets, which will propel our growth for 2013 and beyond.

That wraps up my comments now I'll turn the call over to Richard.

Richard A. Robert

Thank you Scott, good morning everyone. The fourth quarter was a very active one for Vanguard. We took over operations on the Arkoma assets. We closed the Barrett transaction on December 31. We completed $200 million add-on to our existing senior notes due in 2020.

The first-quarter of 2013 hasn’t slowed down as we closed 9.2 million unit offering for net proceeds of $246 million, and quickly put that to work we are recently announced agreement to acquire the Range Permian assets for $275 million. The equity and high yield debt transactions resulted in higher financing costs then if we simply use our reserve base credit facility, with the banks, but we feel it is very important for Vanguard and to sellers of assets that we have the liquidity in place so that when we make offers to buy assets, we don't have to include financing contingencies.

This has proven valuable in negotiations as sellers can feel comfortable that we have the financial capability of closing the acquisition and can execute transactions quickly. We feel that the higher costs of capital and hence negative impact of the fourth quarter and to our 2013 guidance as well work being in the position to execute on the next large transaction.

With that being said, I want to discuss four topics this morning: first, financial results for the fourth quarter and full-year 2012; second, an update on our hedge profile; third, our credit facility and liquidity update; and lastly, the outlook for 2013.

Let me first turn to our financial results. We reported adjusted EBITDA attributable to Vanguard unitholders of $67 million for the fourth quarter, an increase of 24% when compared to the $53 million reported in the fourth quarter of 2011, and relatively flat from the $66 million in the third quarter of 2012. For the full year of 2012, we’ve reported adjusted EBITDA of $231 million, which is a 40% increase over 2011.

Starting in the second quarter of 2012, during each earnings call, I have spoken it has a volatility in oil differentials, well, unfortunately nothing has changed. We continue to see tremendous volatility in the fourth quarter and into the first quarter of 2013, specifically the Big Horn Basin to a lesser extent the Williston, and for the first time, the Permian Basin, where the most volatility has been experienced.

The fourth quarter differentials were on average, better than those experienced in the third quarter, but still greater than we expected. October and November oil realizations had actually improved significantly over the third quarter, but in December wide to almost the worst levels we have seen all year. And this unfortunately hasn’t continued into 2013. However, we have been able to mitigate the risk associated with another Permian Basin oil differential blow out.

By putting on new basis hedged that fix the Permian versus WTI differential at weighted average price of negative $1.50 for March through December, 2013, a negative $1.40 for 2014.

Put it into perspective, the Permian differential widened to as much as negative $17 in January, but the prospect of new pipeline infrastructure coming online in the March-April timeframe had a positive impact and allowed us to hedge at attractive levels. As lower Permian differentials starting in March is reflected in our 2013 forecast.

You will note that our expected oil differential in the first quarter of 2013 is much wider than the differential for the remainder of the year. Unfortunately, hedging oil based differentials in our Big Horn and Williston areas is currently not available, if it was, we would have done it. We are actively looking for alternative markets for our barrels in these areas. For the moment, we will have here and there volatility in these areas until a new pipeline and rail infrastructure can catch up with the growing supply in these markets, such that the barrels can move to less congested markets and pricing can improve. But I hope as conveyed is that we are currently living in a very different world as it relates to oil differentials in some of our major oily areas.

To give you some perspective on the oil differential impact in monetary terms, if our weighted average oil differential reflected in our 2013 guidance for the first quarter was the same as the oil differential in the fourth quarter of 2012. Our forecast would reflect an additional $5 million of revenue just in the first quarter, and that’s pretty significant, and I hope that’s the current environment in perspective. In the immortal words of four steps, that’s all I have to say about that.

Moving on to one more negative topic before proceeding to more positive topics, NGL price realization significantly declined in 2012 versus 2011. However, we did see improvement over the third quarter as we exited 2012. In the fourth quarter of 2012, we saw a 43% decrease in the average NGL realizations from the fourth quarter of 2011, but we had an 18% increase when compared to third quarter of 2012. As a percentage of NYMEX oil price, NGL realizations increased from 41% in the third quarter to 48% in the fourth quarter.

Historically, we elected to not hedge our NGLs price exposure due to cost and liquidity constraints and because NGLs represented a relatively small percentage 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 butanes, which are the higher price components of the NGL stream and the reason that our realization as a percentage of NYMEX, were historically higher than most producers.

However, the Arkoma Basin acquisition and the Barrett acquisition added more NGL barrels and the benefit of the Big Horn Basin heavy NGL stream has been reduced. As such, we have elected to mitigate some of our NGL price exposure by recently adding NGL product hedges through 2014 that I’ll discuss in more detail when I provide the hedging update.

These swings in oil differentials and NGL realizations from quarter-to-quarter overshadow some of the benefits we have seen on the performance of the assets themselves. For example, in the Big Horn where we saw the largest variances in terms of cash flow due to the unpredictable nature of the oil differential, oil production declined less than 4% for the year and with very minimal CapEx being spent in the area.

In fact, oil production in the area has actually increased slightly over the course of the year. from a production standpoint, this asset is one of the most predictable MLP assets in our portfolio. The same thing can be said about of our Permian Basin assets, production has declined marginally on a BOE basis since the first part of 2012 with less than $10 million spent in CapEx.

Prior to 2012, our NYMEX priced oil hedges that we have in place would have insulated us from declining cash flow profile as our capital program successfully targeted high return low risk oil projects, which allowed our oil production volumes to exit the year flat. But due to the differentials we’re seeing over the course of the year, fast cash flow in the Permian decreased fairly significantly over the course of 2012.

There are some other positives that I would want to point out. The recent natural gas acquisitions where the basis has been hedged while substantially increasing our size and scale and help diversify our cash flows.

Many people hear natural gas acquisition and instantly have a negative view, but we have the opposite reaction and here is why. First off, if you buy gas at today’s prices and hedge at these levels, you lock in the margin that you valued the assets at or in other words, we pay a price based on prevailing strip pricing and hedged accordingly to capture the expected return on that investment, that's what the MLP model is all about, capturing margin.

Secondly and more importantly with natural gas, you can effectively hedge the basis differential, which is very different than oil, securing that margin even more. So not only have we diversified our cash flow, but we have locked in that diversification end margins through basis hedges.

Lastly with natural gas, there is a significant amount of upside potential due to the PUD inventory that we didn’t pay for because many of the PUD drilling locations are not economical to drill at current prices. Should prices increase in the future, we are not only able to sell our production at higher prices, but additional drilling locations that we didn’t pay for become economic.

Our leased operating expense is another prospect. LOE has decreased from over $17 per BOE in the fourth quarter of 2011 to just over $9 BOE in the fourth quarter of 2012. This is partially a function of producing more natural gas, which has lower LOE cost on a BOE basis, but some of the declines due to realizing cost efficiencies as we grow in size and scale. We expect this benefit to continue into 2013 as our LOE per BOE is forecasted to decline to less than $9.

In terms of our distributable cash flow, the fourth quarter of 2012 totaled $41 million or $0.70 per unit, generating a coverage ratio of approximately 1.15 times based on our current distribution of $0.2025 per month or $0.1675 per quarter. Distributable cash flow totaled a $141 million for the full-year of 2012 and when compared to the total distributions we paid our coverage ratio for the year was just under 1.1 times.

As a reminder, by issuing equity in September and high yield at October, we intended to create enough liquidity to take advantage of opportunities we expected to see in the fourth quarter. This was fortuitous as we consummated the $335 million Barrett transaction. But please note that this transaction did not close until December 31 and thus had no positive impact on our fourth quarter results.

As a reminder, we take a more conservative approach than all our peers and don’t include any pre-closing acquisition cash flow in our calculation. If we did so, our second quarter results would have been vastly improved due to the Arkoma acquisition and our fourth quarter results would be vastly improved due to the Barrett acquisition, making the full-year of 2012 lot much better.

Using our peer’s methodology of adding back cash flow from effective date to closing date on acquisitions, we would have added another $27 million EBITDA, making our distribution coverage for the year approximately 1.3 times.

For the fourth quarter, we reported adjusted net income attributable to Vanguard unitholders of $16 million or $0.27 per unit. Our GAAP reported net loss was $202 million or $3.41 per unit.

For the full year of 2012, we have reported adjusted net income attributable to Vanguard unit holders of $64 million or a $1.18 per unit. Our GAAP reported net loss for the year was $169 million or $3.11 per unit.

Before moving on to our hedging activities, I would like to spend a little time discussing the non-cash impairment of oil and gas properties in the fourth quarter. As Scott previously mentioned, due to SEC pricing, we along with virtually every other natural gas oriented company recorded impairment in the fourth quarter. Our impairment charge was $230 million. This was not unexpected.

For those that remember my comments on the third quarter earnings call, we did expect to take a material impairment charge in the fourth quarter. I’d like to reiterate that this is a non-cash item that does not impact our EBITDA or our DCF, but does impact our GAAP net income. I want to be very clear that, it is an item that I continue to expect to see as long as we are acquiring significant gas assets and upward natural gas price curve environment.

This is not something we believe investors should be worried about. This was due to SEC pricing being much lower at 2012, causing our reserves at PV-10 across the board to decline due to wells dropping off, because they are uneconomic and future cash flow has been less.

However, the majority of the charge was due to the Arkoma and Barrett transactions. We paid a price for these reserves based on the forward strip of natural gas which has prices increasing each of the next several years. We can feel comfortable evaluating and paying price based on this, because we lock in the expected margins via natural gas price hedges.

So we bought these natural gas focused assets and hedged production for the next four to five years, but are required to evaluate the future cash flows as though we are only going to realize the SEC average 12 months price of $2.76 for the life of the reserves and don’t get to include the impact of the hedges. Clearly, this will indicate that you won’t recover the price you paid for the assets and therefore an impairment is required for GAAP purposes.

Next, let me move on to our hedging portfolio. As I regularly note, we continuously evaluate our hedge book and opportunistically add to our current positions. We’ve been quite accurate recently in adding to our hedge positions, primarily as a result of the Barrett acquisition. Our natural gas hedge book in particular has drastically changed over the course of 2012.

We ended 2012 with a gas hedge portfolio that extended to only 2014 and approximately 70% of the production was hedged. As a result of the two natural gas related acquisitions, we are now just under 90% hedged through the middle of 2017, a great improvement year-over-year. Excluding the impacts of new hedges put in place for Range Permian transaction, in terms of percentage of production hedged, 2013 expected gas production is 94% hedged, 2014 is hedged, 2015 is 95% hedged and 2016 is 93% hedged and the first half of 2017 is approximately 49% hedged. All that weighted average prices of about $4.66, which we’re hopeful that by 2017, we can re-hedge future natural gas production at comparable levels thus avoiding a cash flow cliff.

On the oil side, 2013’s expected oil production in 100% hedged, 2014 is 81% hedged and 2015 is 21% hedged. Unlike gas, the weighted average hedged oil price closely approximates to current market, but you must consider one thing, the weighted average price we report only takes into consideration the floors of our callers.

Traditional callers and three-way callers constitute a relatively large portion of our overall hedged portfolio and has been a reason in the past why our cash flow can vary from quarter-to-quarter even though we are as well hedged as we are. Three-way collars and traditional collars as a percent of our hedged portfolio comprise approximately 30% in 2013 and 25% in 2014.

As this shows, we still have a significant portion of our portfolio that will allow us to have the ability to participate in the upside above our weighted average full price of approximately $92.82.

More recently, we added NGL hedges on 500 barrels a day or about two-thirds of the NGL production associated with the Barrett transaction through 2014. To do this we hedged the individual components of the NGL stream also called the basket at a weighted average price of $40.30 per barrel or $0.96 per gallon. Again we felt that it was prudent to lock in these prices to insulate us from any major future swings in NGL prices for these properties.

More details regarding our current hedged portfolio and percent hedged, as well as the recent hedges entered into for the Range Permian acquisition, can be found in the supplemental Q4 information package posted to our website.

Returning to our credit facility and liquidity for a quick update, as previously mentioned we completed a $200 million senior notes add-ons to our existing 2020 notes in October and most recently a $9.2 million unit offering in February racing proceeds of approximately $246 million.

Although we have sufficient liquidity asset of Barrett 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.

At December 31, Vanguard had indebtedness under its reserve based credit facility totaling $700 million. In connection with the closing of the Barrett transaction, our borrowing base increased to 1.2 billion, leaving Vanguard with liquidity of approximately $500 million. After consideration of the repayment of revolver debt with the unit offering proceeds, and free cash flow we used to repay debt, as of February 25 Vanguard had $449 million in outstanding borrowings under revolver, which provides us with approximately $759 million in current liquidity taking into consideration about $10 million in cash we have on our balance sheet. After paying for the $275 million Range Permian acquisition we will still have close to $500 million of liquidity.

Now let me turn to our outlook for 2013; we are expecting some good results in 2013 even though we are forecasting some larger differentials in the first quarter and for the full year. But before I get into the details let me reiterate as stated in the press release and as a matter of policy, we do not attempt to provide guidance on a variety of items, but most notably we do not include the impact of any potential future acquisitions or the impact of unrealized non-cash gains or losses from hedging instruments. Our guidance also does not include the pending $275 million Range Permian acquisition which is expected to close on or around April 1.

We are expecting our total daily production to be between 31,350 barrels of oil equivalents and 33,317 barrels of oil equivalent. 35% of the production is expected to come from oil and natural gas liquids in 2013, but we expected to account for over 70% of revenue. I want to point out that total production is declining quarter-over-quarter and we plan on exiting the year at a level about 5% lower than the first quarter. This is due to two primary reasons; first, we are not drilling the Arkoma assets as quickly as Barrett did. These natural gas assets are defining faster than we are drilling.

Similarly, with the Barrett transaction, we are not drilling anything I guess that was Barrett, that was Arkoma. Yeah, first we are now drilling the Arkoma asset as quickly as we acquired from Arkoma as interactive. And similarly with the Barrett transaction, we are not drilling anything and so the assets are declining.

If you remember, we are sitting out – getting a step up in the working interest to offset this decline, but that will not occur until the first quarter of 2014. So next year, you will see the Barrett production go up from the fourth quarter of 2013 to the first quarter of 2014.

That being said, our oil production is projected to increase this year about 2% and our NGL volumes are staying flat. Our total production declining marginally on a BOE basis should not be a concern as our strategy has always been to spend enough capital to maintain cash flow in our production.

The only reason our equivalent production is declining is because we are spending more capital on increasing our liquids volume than our natural gas volumes.

On the expense side, we are forecasting LOE per BOE to be in the range of $8.25 to $9.25, which is a little below the 2012 rate of $11.10 per BOE, but includes a full year impact from our gassy acquisitions, which generally incur lower LOE cost on a BOE basis as compared to oil properties and expect some efficiencies from increased scale.

Production taxes are forecasted to be between 8.5% and 9.5%, G&A is expected to be between $1.25 and $1.27 per BOE, which is lower than 2012 due to adding a significant amount of production with little incremental expense. The first quarter of 2013 is expected to have an old differential of about negative $13.85, which is almost $7 worse than the fourth quarter of 2012, and has an impact of about $5 million Cash flow, as I said earlier this is just the impact of the first quarter.

For the full year, we are expecting differentials to improve over the course of the year, but still remains fairly depressed. This assumption has a significant impact on expected EBITDA for 2013 and we hope that there is some upside to this, but we can't count on. Additionally to mitigate any increased downside we have hedged the Permian basis differential through the end of 2013 and partially in 2014.

Based on the 2013 script price of $93.61 per barrel per oil and $3.56 per MMBtu for natural gas, and the previously discussed assumptions we expect to generate approximately $303 million in adjusted EBITDA. This is a significant increase of over 30% from the 2012 EBITDA of $231 million.

Scott has already discussed our 2013 capital spending, which is expected to increase from 2012 levels to approximately $55 million from the $50 million spend in 2012. This level of capital spending amounts to approximately 80% of EBITDA and is lower than the 2012 investment rate of 22% due to the benefits we expect to derive from the Barrett transaction structure where no capital is being spent.

As it is normal, we are expecting some lumpiness in the capital spending quarter-to-quarter, so I caution that distribution coverage will vary quarter-to-quarter because of this lumpiness we have detailed our expected capital spent by quarter in our guidance, but caution that these numbers are always prone to adjustment as the timing of capital projects tend to shift during the year.

Interest expense is expected to be approximately $64 million and includes the impact of the recent equity offering at $200 million high yield add on we did back in October. Based on the numbers outlined in our guidance, and based on our current annual distribution rate of $2.43 per unit, we expect to generate a distribution coverage ratio of 1.1 times.

Our number one goal is to provide a stable yet growing distribution to our unitholders for the long-term. Therefore we feel very comfortable with our distribution coverage for 2013 and are well prepared from almost any price environment, what is not included in our guidance is the impact of the recently announced Permian acquisition.

Our guidance does not reflect the added production and associated cash flow or capital we used to finance it. We feel it is more prudent to wait for closing to update guidance versus adding it now and risk having to back it out later. I will say that this acquisition has the significant amount of accretion that is largely driven by the development behind pipe opportunities that Scott discussed.

We expect this acquisition to add approximately $30 million in EBITDA for the nine months, it contributes in 2013 and certainly increases through 2016 due to the production growth anticipated from the behind pipe and development drilling opportunities.

Overall, we believe 2012 was a very successful particularly on the acquisition front. As discussed, we faced some challenges as related to oil price differentials and NGL price realizations. However, our conservative philosophy of slow and steady distribution increases served us very well this year, we did not immediately declare larger increases to our distribution as a result of our acquisitions, but chose to keep some coverage and reserve, issued uncontrollable variables such as oil price differentials and NGL pricing remain volatile.

In hindsight, the exclusivity was the prudent thing to do, the reason we need to operate at a higher distribution coverage level is to predict our distribution when unforeseen circumstances occur. All that being said, we were still able to increase the distribution 5% in 2012 while maintaining distribution coverage of approximately 1.1 times.

As we continue to do acquisitions, like the recently announced Permian deal and or the old differentials and NGL pricing improves, we should see Vanguards distribution coverage increase. By carefully rationalizing our portfolio of assets and capital projects, building an experienced employee base and operational platform from which to operate, we continue to improve the overall level for the company.

This concludes my comments, we will be happy to answer any questions you might have at this time.

Question-and-Answer Session

Operator

Thank you, sir. (Operator Instructions) And our first question comes from the line of Ethan Bellamy. Please go ahead.

Ethan Bellamy – Robert W. Baird & Company

Good morning, everybody. Congrats on a good year.

Richard A. Robert

Thanks to you Ethan.

Ethan Bellamy – Robert W. Baird & Company

Let me keep the Forrest Gump theme going, Richard. I'm not a very smart man. Could you explain to me the rationale for and the mechanics of the range bonus accumulators? I had to use the Google machine on that, and I'm still not clear on the rationale for those.

Richard A. Robert

Well, it’s really just layering on another product on top of existing swaps that helps produce the incremental income. As long as prices stay within a certain defined range which is a very large range, we generate incremental dollars for every barrel that’s under that swap. So it’s just I hate to say it’s free money, but it’s something like free money to us, which is why we’ve elected to use some of those.

Ethan Bellamy – Robert W. Baird & Company

Okay, fair enough. With respect to the acquisition potential this year, where do you think you’ll come in better or worse than 2012 in terms of closing deals?

Richard A. Robert

Let’s go for better.

Ethan Bellamy – Robert W. Baird & Company

Okay.

Richard A. Robert

Put it this way, I mean it’s hard to forecast how much we’re going to do every year, but clearly we’ll be disappointed we can do at least as much that we did last year.

Ethan Bellamy – Robert W. Baird & Company

They…

Richard A. Robert

I guess what I would suggest Ethan is that it's nice to already have a fairly significant transaction already essentially done in the first quarter, where last year we worked all the way to June before we had the first significant thing down. So I will say deal flow is excellent, there is a lot of price in the market. We’re engaged in discussions on we think kind of starting and some pretty interesting negotiated type of opportunities. So from what I have seen and what we’ve already accomplished like I said I think what we did last year is very reasonable goal and hopefully we can do better.

Scott W. Smith

And I think what I think is happening is if sellers are recognizing us as a partner they want to do transactions with, we’re relatively easy to work with. We try to be creative and make transactions a win-win. So we listen to what the seller wants at the end of the day. And I think that’s paying dividends now as we see better quality transactions negotiated dealers coming directly to us as opposed to having to rely on options.

Ethan Bellamy – Robert W. Baird & Company

Okay. Last question and then I'll let Praneeth ask you about puts. The monthly distribution strategy, I think, is genius and it's been a pretty good innovation. Anecdotally, what's been the response from your investors so far?

Richard A. Robert

I think the retail investors appreciate it. I mean that’s why we did it for at the end of the day is to generate more timely cash flows for our retail investors and the feedback has been very good. And we're hopeful that others lend recently announced it, I think they were moving to a monthly distribution, so hopefully we have created a trend that will continue throughout the MLP space, because I think it’s a positive one. I know I like getting my money quicker.

Ethan Bellamy - Robert W. Baird & Company

Me too, all right. Thanks, you all.

Operator

Our next question comes from the line of Dan Guffey. Please go ahead.

Dan Guffey – Thomas Weisel Partners

Good morning, guys, and congrats on a good quarter. Can you give a little detail around the infill opportunities and the PDNP opportunities you're going to see in the Permian from this Range acquisition, I guess specifically targeted formations?

Richard A. Robert

Sure. Basically the majority of the opportunities are in all New Mexico and we are looking at – this is a very old mature property, kind of the main field it’s in a area called Eunice, which is a huge oil field and very small percentage of what we are going to own, but you’ve got production tax pay, I think there is seven or eight different intervals, but the main producers are the Grayburg, San Andres, Blinebry, Tubb, Drinkard, and Abo and what you've got is quite a few wells and that are only producing from one or two zones than what we are looking at doing, it’s just developing going up hole in existing wells, to add behind pipe pays or taking downspacing from 40 acres down to 20 acres and some portion of the fields that are already build to that density.

So with every wells that’s going to be drilled, probably down through the basin, the bottom zone, which is the Abo, and then we’ll just gradually work our way up overtime. The beauty of this particular area in the Permian, we have a lot of stack pay.

There is also some opportunities in another area called loving field, it’s freshly gaining production. There is some just a few locations, so there is water flood expansion, which although its there, I’m not so sure it works for our structure, because they’re not a capital involved, and then in another areas that in Texas again, we didn’t have any upside out there, although which in a fairly close to the horizontal growth take place, perhaps will get locked again, the trend will come to us.

Dan Guffey – Thomas Weisel Partners

All right, great. And then Richard, can you talk about how much you think could be added to your borrowing base, following the close of this Range acquisition?

Scott W. Smith

Well, generally it depends on how much PDP, and how much PUD is in each transaction, but kind of a good rule of thumb of 50% of the transaction value. This could be a little bit more, because there’s a little more PDP and PDNP heavy, but rule of thumb at least 50%.

Dan Guffey – Thomas Weisel Partners

All right, great. And then last one from me, can you guys just talk about the economics you’re seeing in the Woodford currently, I guess your five well development plan and five more wells later this year. What kind of returns do you think those that place generating right now?

Scott W. Smith

Sure. I’ll say when we first got starting and looking at these opportunities like that we were looking at capital program, well completed well costs about $4.6 million, like I mentioned during the call that we think we’re in that $4 million range. At that level of script pricing we’re coming at mid-50 type rate of return, and I think we’re being conservative at least I hope somewhat at $4 million I think we could drive costs lower than that, and incrementally it gets substantially better if we can get the thing down to the $3.5 million range, we’re talking north of 70%. So it’s very sensitive to drilling cost, but we are definitely have the right team in place with the right operating partners that I think overtime will continue to refine these numbers, hopefully kind of low cost producer and developer in the area.

Dan Guffey – Thomas Weisel Partners

Sounds good. Thanks, guys, and congrats again.

Scott W. Smith

Thanks.

Operator

Our next question comes from the line of Michael Peterson. Please go ahead.

Michael D. Peterson – MLV & Co. LLC

Hi, good morning everyone.

Scott W. Smith

Hi, Michael.

Michael D. Peterson – MLV & Co. LLC

Hey, how are you? I know that access to capital is a primary focus for you guys. Given the meaningful developments within capital structure in the sub-sector in 2012, are there any structures or strategy that might be suitable or attractive for Vanguard either in 2013 or into 2014?

Scott W. Smith

You must be referring to the LinnCo models?

Michael D. Peterson – MLV & Co. LLC

That model or other approaches to try to tap into a more institutional investor base, exactly, Richard.

Richard A. Robert

Well, you hit the nail on the head. The key is to tap into the institutional investor base that is going to be paramount to generating enough capital to prosecute all the opportunities that I think we are going to have over the course of next several years. I am hopeful that ultimately that institutional base will become more accepting of investing in the upstream space overtime. I mean the space is still relatively young, I mean Lin started about six years ago or so.

So I think by and large, the space has proven it to be a viable sector, but I think some institutions have still Larry and maybe in the next – over the course of next year or two, they will see that our incremental yield that we provide is well worth the perceived incremental risks over the midstream sector.

So I am hoping it will happen naturally, but if it does not, clearly the LinnCo structure which we call the VanCo structure out here – it's certainly a viable strategy, but we would have to change our strategy because right now what makes the LinnCo structure work is the tax shield that's generated from all the drilling that Linn does and we don't drill that much.

So we would have to make a conscious decision to change our strategy and employ growth capital and so right now we don't feel like we have to do that, because we are at level – we look at transaction sizes that can be funded via the traditional retail equity systems that we use today and that's nothing, we have got a great set of investment banks to help us raise capital, we've got virtually every large equity shop out there helping us raising capital

So for the moment I think we're fine, longer-term it’s certainly something we are thinking about.

Michael D. Peterson – MLV & Co. LLC

Very helpful, Richard, I appreciate the detail. Just a follow-up question and it's a little bit of a follow-up to Dan's question with regard to the Range acquisition in the Permian. What are your estimates for PUD conversion costs?

Richard A. Robert

Well I think we looked at our recompletion cost run about $250,000 for re-completion.

Michael D. Peterson – MLV & Co. LLC

Okay.

Scott W. Smith

I think the well cost, I think we reached $1 million per well which I think, that's based on the historical range of data, hope that we can do it cheaper, but again we just basically use fair numbers historically with days we come across.

Michael D. Peterson – MLV & Co. LLC

Okay thank you Scott. All I have this morning.

Operator

Our next question comes from the line of John Ragozzino, please go ahead.

John J. Ragozzino – RBC Capital Markets LLC

Hi, good morning everybody.

Richard A. Robert

Good morning.

Scott W. Smith

Good morning.

John J. Ragozzino – RBC Capital Markets LLC

Obviously, in 2012, you had a clear focus on building some significant optionality into the portfolios related to natural gas pricing permits in the future. Do you see this strategy continuing into 2013? And do you have a targeted product mix when you think about the overall portfolio?

Richard A. Robert

Well, obviously the first acquisition we did was an oil base deal, I think highly liquids focused. strategically, we’re not just starting to look at natural gas deals. But again, we look at transactions John, as we’re looking for margins, if it comes in barrels of oil, NGLs or Mcf, we’re kind of agnostic to it.

Obviously, it’s nice to have a balance and I think just as we see transactions coming to us, we will see a balanced portfolio over the year, but there isn’t a conscious decision to say, we should get more liquids focused or get more gas focused. Again, we’re looking; it’s much more faster of the type of acquisition, the accretion in the fit into our structure that’s I am most concerned about.

John J. Ragozzino – RBC Capital Markets LLC

Yes, the type of reserves.

Richard A. Robert

Right, I think probably saying that it’s tough thing we had, even in the Range transaction, we’re in this roughly 35%, 40% NGLs. I don’t think we’d be comfortable taking anything more than that. So that’s why (inaudible) as we look at transactions, as we don’t really want to have too much NGL exposure. I think we should keep that in that 15% to 20% tops on a reserve basis.

John J. Ragozzino – RBC Capital Markets LLC

Okay, that's helpful and the just pounding away on this Permian acquisition and on top of Dan's question – what type of reserves are associated with these recomplete PDNP projects? And I think you gave roughly $250,000 conversion cost, so what are you looking for in terms of the associated reserves per interval?

Scott W. Smith

I have always looked at – I’d now look at on an individual basis, I actually look at on a program basis, because again, there’s like 70 or 80 different recent completion opportunities that we’ve modeled over the four, five-year period. but I will tell you, which you’re getting the combination of oil, some of them are more oil focused, some are more liquids focused and so then you get some of the associated natural gas as well directly, that directly was drilling to.

Richard A. Robert

Yeah. Well, I mean I’d tell you from an overall production perspective. we do anticipate it increasing each year over the next three years by a fairly healthy margin. So it is growth.

John J. Ragozzino – RBC Capital Markets LLC

Okay, fair enough. And then last one, what did you pay for the Permian assets around PV basis?

Richard A. Robert

Well, I got to tell you that if you look at it on a – we’d just tell you what’s your view on your natural gas liquids pricing. If you think it’s going to stay flat at about roughly 40%. we’re probably in the PV 12-13 range. As you look at, I think we’re going to get it escalating, more to historical levels, it’s probably more in the 15-16.

John J. Ragozzino – RBC Capital Markets LLC

Okay, great that’s very helpful. Congrats on a great year, guys. We’ll talk to you soon.

Richard A. Robert

Thanks, you bet.

Operator

Our next question comes from the line of Adam Leight. please go ahead.

Adam Leight – RBC Capital Markets LLC

Good morning everybody. First question I guess on the Permian acquisition, what is the decline rate, and how much spending you think you might need to have to make it grow?

Richard A. Robert

As I mentioned, I mean we expect to actually increase production year-over-year for the next three or four years just based on the development drilling program what we have in place. We are anticipating spending about 25% of the cash flow on this transaction in drilling and recompletions. and we’re seeing a double-digit increase in production year-over-year.

Scott W. Smith

The PDP decline rate is 8%.

Richard A. Robert

Not 8% on a PV basis.

Adam Leight – RBC Capital Markets LLC

Great, thanks. And then could you just give me some color on Range reported a different production mix on this asset than you all have. Is there anything to that or is it?

Richard A. Robert

They just stay around a two, how they reported this in their accounting system was on a two-stream basis just gas and oil, and they include NGLs and their gas stream.

Adam Leight – RBC Capital Markets LLC

Okay. That’s what I was trying to figure out. And on the reserves that you’re acquiring, I presume that was on a strip basis? If that’s correct, can you…

Richard A. Robert

That is correct. Yes.

Adam Leight – RBC Capital Markets LLC

What would it have been at SEC, just we can kind of make a comp to the existing assets?

Richard A. Robert

We didn’t run it on SEC pricing on it.

Adam Leight – RBC Capital Markets LLC

Okay.

Richard A. Robert

That is mostly liquids focused. I can’t imagine, it would have changed very much.

Scott W. Smith

Yeah. Most of the value is liquids, so we probably wouldn’t have that bigger change.

Richard A. Robert

Because of strip…

Scott W. Smith

Yeah. But it will have…

Adam Leight – RBC Capital Markets LLC

There are no bottlenecks on the liquids takeaway at this point?

Richard A. Robert

No.

Adam Leight – RBC Capital Markets LLC

And then separately, do you have any update on the DRIP response?

Scott W. Smith

DRIP, Lisa, how is our DRIP going?

Lisa Godfrey

There’s over 120 participants.

Scott W. Smith

Yeah, slow and steady. We’re getting more each quarter, but certainly, we’re looking for 120 right now. Hopefully, we will get more over time.

Adam Leight – RBC Capital Markets LLC

Okay. And then lastly in your reserve revisions were there anything were not price related significantly?

Scott W. Smith

On the reserves, we have some revisions for some LOE increase, this in some areas that performance wise was minimal.

Adam Leight – RBC Capital Markets LLC

Okay, great. Thanks very much.

Scott W. Smith

You bet. Thank you.

Operator

Our next question comes from the line of Praneeth Satish. Please go ahead.

Praneeth Satish – Wells Fargo Securities LLC

Hi, good morning. Unfortunately, I don’t have any quick questions, but I do have a question on the NGL hedges. It looks like the pricing was pretty good or at least in line with current prices. Just wondering why you didn’t hedge more of your overall NGL production exposure? Or is this something that you could increase in the future?

Scott W. Smith

Yeah. We’re certainly looking at adding incremental hedges where we’ve been monitoring the market. They’ve been somewhat volatile, so we’re trying to pick our opportunities as we see them, but certainly the Barrett transaction we did, because we had a certain price level in our economics and we exceeded those, that price level by putting these hedges in place. So we’re happy to do that and we’re looking to do the same thing for the Range barrels as well.

Praneeth Satish – Wells Fargo Securities LLC

Okay.

Scott W. Smith

So, it is something that we will add to, but keep in mind, it’s historically we’re at a fairly significant level in terms of where we are, hedging at 40% when the average has been in the 50s, it’s not something you want a steadied item. and so you kind of look at your exposure, you think how – can it get a lot lower, hopefully not, but again, we will put on additional ones as the year progresses.

Praneeth Satish – Wells Fargo Securities LLC

Great, that’s all I had. Thank you.

Operator

There are no further questions in the queue. Please continue with closing remarks.

Scott W. Smith

All right. Again, I should appreciate everybody dialing in today and joining us on the call. Like I said, I thin our 2012 was a good year, pretty much on all fronts other than the differentials, which I guess proportionately none of us has first of all, where that’s going to come out, but wondering about midstream company, they will find a way to solve the problems and we’ll put enough dollars to it, rail pipelines or whatever alternatives they may have to hopefully bring those down to more historical norms. but 2013 again, we’re off to a great start with this Range acquisition. Our drilling program and the Woodford couldn’t be more pleased with that, and I think, as we continue through the year, we’re going to hopefully see more excellent opportunities to actually our portfolio and continue what we think will be a very productive capital program.

So with that, we look forward to talking to you again after the first quarter.

Operator

Ladies and gentlemen, this does conclude our conference for today. If you would like to listen to the replay of today’s conference, pleased dial 303-590-3030 or 1800-406-7325 with access code 4599724. Thank your for your participation. You may now disconnect.

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