Vanguard Natural Resources, LLC (NYSE:VNR)
Q4 2013 Earnings Conference Call
February 27, 2014 10:00 a.m. ET
Lisa Godfrey – Director, Investor Relations
Scott Smith – President and CEO
Richard Robert – EVP, CFO and Secretary
Kevin Smith – Raymond James
John Ragozzino – RBC Capital Markets
Michael Peterson – MLV & Company
Praneeth Satish – Wells Fargo
Ladies and gentlemen, thank you for standing by. Welcome to the Vanguard Natural Resources Fourth Quarter and Year End 2013 Earnings Conference Call.
During today’s presentation, all parties will be in a listen-only mode. Following the presentation the conference will be opened for questions. (Operator Instructions) This conference is also being recorded today, February 27, 2014.
I would now like to turn the conference over to Lisa Godfrey, Director of Investor Relations. Please go ahead.
Good morning, everyone and welcome to the Vanguard Natural Resources, LLC's fourth quarter and year end 2013 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 Executive Vice President of Operations.
If you would like to listen to a replay of today’s call it will be available through March 28, 2014 and may be accessed by dialing 303-590-3030 and using the pass code 4663736#. 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 firstname.lastname@example.org. This information was also provided in yesterday’s earnings release.
Please note the information reported on this call speaks only as of today, February 27, 2014. 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 which is expected to be filed by tomorrow February 28, 2014 and will also be available on our website under the Investor Relations tab and on EDGAR.
Also on the Investor Relations tab of our website, under Presentations, you can find the Q4 and year end 2013 earnings results supplemental presentation. As a reminder, the company’s 2013 K-1 tax packages will be available for immediate download from our website next Wednesday March 5, with the original 2013 K-1 tax packages mailed later next week as well. For any questions regarding schedule K-1, unitholders are invited to call tax package support helpline at the toll free number 866-536-1972, or via email at VanguardK1Help@deloitte.com.
Now I would like to turn the call over to Scott Smith, President and Chief Executive Officer of Vanguard Natural Resources.
Thank you, Lisa and thanks for joining us on the call this morning. I will start with a brief summary of our recently closed Pinedale acquisition. Then we will review our operational results for the fourth quarter and full year 2013. We’ll then briefly recap our capital spending during the fourth quarter and our plans for 2014. Lastly, I will discuss our acquisition outlook for the year. Richard will then proceed with a financial discussion and then we will turn the line over for Q&A.
First, I would like to start off by saying how pleased we are to have been successful in the acquisition process run by Anadarko for their non-operated working interest in the Pinedale field. We’re able to negotiate a PSA within a week of agreeing our price and closed the transaction as planned on January 31. This timeline was aggressive to say the least and is a testament to the hard work by the Vanguard and Anadarko teams that we were able to get this transaction across the finish line in such short timeframe.
As we said on previous calls, beginning in 2012 with our Kome [ph] acquisition we began a strategic shift towards natural gas liquid property. Since that acquisition, we’ve completed five primarily natural gas acquisitions for more than 1.5 billion and acquired approximately 1 point Tcfe of reserves. With [ph] the long-term price of natural gas as reflected by the current natural gas curve holds true, and [ph] our decision to invest in these large quality natural gas assets will create significant long term upside potential for the benefit of our unitholders.
The Pinedale acquisition is the largest investment we have made to date in natural gas property and it’s the second largest transaction we have done in our history. With this acquisition, we’ve established a non-operated position in one of the most prolific natural gas deals in the United States, primarily operated by two of the leading independent oil and gas companies in the Rockies, Ultra petroleum and QEP Resources. Both of these companies have demonstrated the ability to consistently achieve best in class operating results while
Since 2006, both operators have reported total well costs decreasing almost 30% and as reported by Ultra last week, their drilling costs continued to decline due to efficiencies in the drilling and completion practices. We feel this is a perfect asset for Vanguard to introduce a growth component to its capital spending strategy. Not only has the drilling improvement in this area to be very successful but with the PUD inventory we acquired, we believe we and our partners will be developing this field for over 10 years, taking this growth sustainable over the long term.
I want to point out a few detail for the transaction before moving on to company’s reserves. Total proved reserves [indiscernible] we acquired approximately 847 Bcfe [indiscernible] 3% proved developed and 57% proved undeveloped. Using SEC pricing of $3.67 per mmbtu, $96.90 per barrel and the January 31 closing date, total proved reserves are approximately 765 Bcfe, approximately 45% of the reserves are proved developed, 55% undeveloped.
Our current production rate is approximately 113 Mcfe per day. Using this average production rates, this reflects an ROAP ratio of approximately 19 years. As I previously mentioned, a significant characteristic of this acquisition is the undeveloped reserves we acquired. We are recognizing 970 PUD location [indiscernible] reserves and will add same store inventory revival projects to this year’s capital budget. This high quality undeveloped resource will be a significant portion of our capital spending plans for many years to come. Additionally, we believe there are up to 5200 additional development locations that will not appear in our reserves due to current expectation that they will not be drilled within the five year period as required by the SEC for reporting proved reserves.
Lastly, we have an average working interest of approximately 10% and expect an 8 rig drilling program in 2014, with each rig anticipated to drill two wells per months. But I will get into that more detail in shortly.
Now let me turn to an update on our year end 2013 reserves. Our yearend total proved reserves calculated using SEC pricing were 172 million barrels of oil equivalent, up over 13% from our year end 2012 reserves of 152 million barrels of oil equivalent. The PV10 value of the reserves using SEC pricing was approximately $1.8 billion.
From a commodity perspective, our reserve mix is 26% oil, 17% NGLs and 57% natural gas. In addition, our percentage of proved developed reserves increased year-over-year from 74% to 78% of total reserves.
Because the Pinedale acquisition closed in January, these reserves are not included in our 2013 year end reserves. If we were to include the Pinedale reserves, [indiscernible] using the same SEC pricing we would see a 74% increase in our 2013 year end reserves to approximately 300 million barrels of oil equivalent and our PV10 would increase by 25% to $2.3 billion. From a commodity perspective, our reserve mix would [indiscernible] 17% oil, 17% NGLs and 66% natural gas. In addition, our percentage of proved developed reserves would decrease from 78% to 64% of total proved reserves. So as you would expect, this acquisition makes us more gas focused and increases our percentage of proved undeveloped reserves.
Now I will review our production results and capital spending. Average daily production for the fourth quarter of 2013 was 36,903 BOE per day, up 5% over the 35,250 BOE produced in the third quarter of 2013 and a 62% increase over the 22,803 BOE per day produced in the fourth quarter of 2012.
Production for the quarter was approximately 64% natural gas, 24% oil and 12% NGLs. However, even with our significant increase in natural gas production, our revenues are still more weighted to liquids with 59% coming from oil, 13% from NGLs and the balance from natural gas. We did experience downtime as did other operators during November and December due to severe winter weather and infrastructure issues that negatively impacted our operations in the Permian basin, Arkoma and the Rockies. This had a 1% impact on our fourth quarter production which equates to a loss of approximately 8000 barrels of oil and 127 million cubic feet of gas during the quarter.
Additionally, we did not experience any material long term damage to our operation but our production was temporarily curtailed or shut in and that lasted into January. Average daily production for the full year of 2013 was 35,448 BOE per day, up 94% over the 18,298 BOE per day produced in 2012. Production was approximately 65% natural gas, 24% oil and 11% NGLs, which 61% of our 2013 revenues coming from our oil production, 11% coming from NGL production and the balance from gas. The primary increase over year-over-year is due to the [indiscernible] and Range Permian acquisitions which closed in 2013.
Now I will turn to our capital spending. During the quarter we spent just over $14.5 and for the year we spent $56.7 million. In 2013, our capital program was highlighted by our activity in the Woodford and Fayetteville along with some excellent results in several of our other areas of operations.
To quickly recap, in our Arkoma basin, we drilled 8 and completed 5 operated horizontal Woodford wells in Pittsburgh County, Oklahoma with approximate 48% working interest. We also participated in the drilling of 14 horizontal wells and completed 5 horizontal wells in Hughes and [indiscernible] county in Woodford Oklahoma with working interest ranging from 6% to 14%. In the Fayetteville, during the year we participated in the drilling of 56 gross wells, 3.4 net and completed 43, 2.3 net horizontal wells mostly in [indiscernible] counties.
In the Woodford, I also want to highlight our workover program where we had a bit of success acidizing wells and installing artificial liquid [indiscernible]. We began this program in July and have completed the work on 35 wells at a net cost of 3.4 million. For this investment we saw a net uplift of 4.4 million cubic feet equivalent per day. These projects generated greater return and we are looking forward to continuing this program on our inventory of projects in 2014.
Our Permian recompletion and frac program continues to ramp up. During 2013 we completed 25 workovers which included 17 fracs and recompletions and eight acid jobs. These projects added a gross uplift of 300 barrels of oil per day and approximately 600 Mcf per day or 255 million barrels per day [indiscernible] net with an investment of $3.5 million. This program achieves returns of almost 700% and we are looking forward to continuing this program in 2014.
Lastly, we completed another successful [indiscernible] stimulation program in 2013 where we achieved an uplift of over 450 gross barrels of oil per day, 275 net from the 12 wells we’ve worked on between May and September. These are projects that deliver returns in excess of 100%, we will be continuing this program again in 2014.
If you look at our 2014 budget, we are anticipating a total capital spend of approximately $137 million, with 114 million designated to maintenance and $23 million as growth capital. Let me quickly go into some of the more details of some of the larger capital outlays that we have planned.
The largest component of our CapEx program will be the newly acquired Pinedale assets where we will be spending approximately 60% of our total CapEx dollars and this is where all of our growth capital will be focused. As previously mentioned, Ultra and QEP, each plan to drill 8 wells a month for a total of 16 gross wells a month to Vanguard. This equates to 4 rigs running for each operator beginning on February 1 this year. Our drilling and completion costs are forecast to be between $3.8 million to $4.2 million of wells and VNR’s net capita spending is expected to run approximately $81 million for the 11 months in 2014. All the wells are drilled vertically to depths of between 10,500 to 13,300 feet and have approximately 16 frac stages and take between 10 and 12 days from spud stage to [ph] production stage.
The expected ultimate recoveries are generally in 4 to 6 Bcfe range and our typical 24 hour additional production rate is – from about 5.5 million to 6.5 million cubic feet per day. Because we are a non-operator, we are able to leverage the experience and technical expertise of Ultra and QEP on executing this drilling plan. We feel it’s a great position for Vanguard because we are deriving the benefits that these companies have achieved absent the investment in people and equipment which would be required if we were to try and manage for our own account. A perfect example of the upside we have seen a being partner in this field and something I mentioned earlier, with the announcement by Ultra last week that their drilling and completion costs in the fourth quarter of 2013 averaged $3.6 million a well, a $200,000 decrease from their third quarter average of 3.8 million and they managed to reduce drilling costs by approximately $1 million per year in 2013 from their well costs in 2012.
To achieve these types of results take a long time and big investment – and with the Pinedale acquisition we will be the beneficiary of the significant strive these two companies have continue to make and develop in the field. Additional, Ultra reported their average initial production rate for the new operated wells was at 8 million cubic feet per day. Hopefully these cost savings and results continue and our capital assumptions prove to be conservative.
In the Permian – Permian will be our second most active area in 2014 with over 15% of the total capital budget. This encompasses our successful Range Permian recompletion project that we gained last year. We have planned 27 operator projects at a net cost of $4.3 million and have forecasted a net uplift of right at 450 BOE per day. Additionally in 2014, we are participating in a horizontal Wolfcamp project operated by [indiscernible] where we have a working interest ranging between 25 and 35%. This property is in Boston County, Texas just north of lot of the Wolfcamp activity. The initial well has been drilled and should be completed in early March. If this initial well is successfully completed, we anticipate [indiscernible] will initiate a continuous development program in the area which encompasses 7000 gross acres and just under 2400 net acres. Should this transpire there is a good chance we will be increasing our CapEx growth accordingly.
As I previously mentioned in frequent conference calls, in the Woodford we have an active drilling program with Jones as well as having another non-operated drilling activities that are currently underway, all of which are continuation of our 2013 CapEx program in the area. Specifically the 5 operated wells we drilled with Jones where we have a 40% working interest have been completed in May and are in the processing of cleaning up. There is also 10 wells where we have working interest ranging from 8% to 13% that are also in various stages of completion as well.
On the drilling front, we’re currently participating in one Jones operated well in their BP joint venture where we have a 7% working interest. In total we expect to spend $17 million during 2014 or 13% of our total capital budget in the area. Approximately $11 million of the allocated to drilling and completing horizontal wells at varying working interest and the balance will be on continuing our various successful workover programs that we talked about earlier.
The remaining capital in our budgets spread across our operations on projects such as our Madison frac program in Elf [ph] basin and participation in non-operator Fayetteville horizontal wells. With the closing of the Pinedale acquisition we took a long look at our overall capital spending program and concluded that our unitholders are best served by including more of our Pinedale capital spending as maintenance capital and deferring other projects primarily in the Woodford that are HBP [ph] and can develop when we determine its beneficial increase our activity level in those areas.
This being said, although we had initially modelled significant growth component in this acquisition, with this reallocation of capital, our growth CapEx program will be approximately $23 million in 2014.
Now I will [ph] just look at on acquisitions, we continue to evaluate numerous transaction of various sizes and remain prudent in our bidding approach to ensure the assets we successfully acquire are accretive to our unitholders. In total we bid on over 30 deals in 2013 with a value of more than $6 billion which excludes the acquisitions that we have closed. It remains a very competitive market for MLP type asset but I continue to believe that Vanguard is well positioned to be very competitive on quality packages that fit our business model. With the introduction of growth capital into our strategy, we feel we can be more competitive in bidding on assets that may have larger drilling component than we have looked at in the past.
That being said, we will continue to be disciplined in our approach to evaluating acquisitions. Assets that have a growth component need to have a repeatable program like we have in the Pinedale assets can be executed for many years to come. Again we would rather buy nothing than to spend dollars on marginal transaction that doesn’t have any accretion. Our goal has always been to grow cash flow which ultimately benefits our unitholders in the form of increased distributions.
In summary 2013 was a challenging year on the acquisition front and as Richard will discuss later, we did run in some headwinds with oil differentials that unfortunately [indiscernible]. However we ended the year having successfully signed a major acquisition that will generate long term benefits to the company and marks a strategic shift in our capital spending plans and which positions us to be more competitive in the acquisition market in the future.
Our results are reflection of the efforts of our employees and our hard work on behalf of the company. It continues to be our goal to judiciously increase our distribution in a manner that we feel is sustainable for the long term. With the Pinedale acquisition behind us, the board has approved an increase to our monthly distribution for February payable this April of quarter of a penny per month or $0.03 per year. Our current annual distributions sits at $2.52 and based on yesterday’s closing price of $31.37 we trade again a yield right at 8%.
With continued access to the capital markets and an active acquisition market, we are poised to continue the momentum of growth for 2014. We are extremely excited about the prospects of the balance of the year and are confident that with our structure and cost of capital we tend to compete effectively and competitively for the right type of assets which will continue to propel our growth.
With that, I will turn the call over to Richard for the financial review.
Thank you, Scott. Good morning everyone. I would like to start this morning by first discussing our quarterly and annual financial results then turn to my regular update on our hedging portfolio and liquidity, and then we’ll review our outlook for 2014.
First to our financial results. We reported adjusted EBITDA of approximately $74 million for the fourth quarter of 2013, an increase of 12% when compared to the $67 million reported in the fourth quarter of ‘12 but an increase of 10% from the $83 million reported in the third quarter of 2013.
For the full year of 2013, we reported adjusted EBITDA of $310 million , which is a 34% increase over 2012. Obviously this was not our best quarter. However I get some comfort when I expected [ph] the reasons behind the pro forma through the quarter and [indiscernible] that it was a function of our assets not performing.
The decrease in adjusted EBITDA from the third quarter to fourth quarter is primarily attributable to first, wider oil differentials, second, the production downtime due to severe weather and third, negative prior period adjustments related to LOE.
First let me discuss the impacts lot of differentials had on our average realized prices as these had the biggest impact to our fourth quarter revenues. WTI oil prices did decline significantly from the third quarter to fourth quarter but our hedges mitigated the impact of this decline. Primary driver of our lower oil revenues was that oil differentials companywide weakened by almost $7 per barrel from the third quarter. This was not a complete surprise. As I mentioned in our last earnings call in October, we were expecting an increase in the negative oil differential in the fourth quarter. When asked, I predicted that the company wide negative oil differential would likely worsen from the around negative $8 we experienced in the third quarter to approximately negative $10. Unfortunately I was wrong. The company wide differential widened out to more than negative $15. Clearly I need to take my crystal ball into repair.
This differential blow out had a negative impact of $5.3 million to our fourth quarter oil revenues. Our Big Horn area was the largest contributor where unfortunately it’s not unusual to see wide swings quarter to quarter. Specifically the Big Horn differential in the fourth quarter widened to an average of more than negative $27 per barrel from the negative $13 per barrel we saw in the third quarter.
This alone had an impact of almost $4 million to our oil revenues in the fourth quarter where over 70% of the variance is due to oil differentials. I will get into our 2014 expectations shortly but I want to point out here that we are anticipating some improvements in the 2014 Big Horn differential. January had a $22 differential but we have seen some significant improvement in February to the tune of $14. We are anticipating that during the middle of the year the negative differential here will average around $11 and then begin to widen beginning in September as we have seen in the past.
After taking into account the larger differential and our hedges, our average realized oil price, including hedges, decreased by approximately $5.70 in the fourth quarter. Gas realizations continues to average approximately 66% of NYMEX and decreased slightly quarter over quarter. This may seem like a low realization but keep in mind that this also includes transportation costs that are quite high on our Arkoma assets and the acquired [indiscernible] assets. This netting of transportation cost against natural gas revenues is nothing new and it’s just how we choose to report those costs.
The pricing of natural gas liquids or NGLs on the other hand has improved recently. Unfortunately though this is not readily apparent in our quarterly numbers, due to our prior period adjustment on one of our major non-operated properties which added NGL volumes with no associated revenue change, thus distorting our realized NGL price for the fourth quarter. Excluding this prior period adjustment, average realized NGL pricing has improved quarter-over-quarter and specifically during the last couple of months and it’s primarily due to the strengthening of propane and the heavier components of the NGL stream.
Since our NGLs are largely unhedged, the recent price increases from these loads will have a positive impact on revenues going forward.
Turning to production, as Scott mentioned, we experienced downtimes just like many of our peers during November and December due to the severe winter weather and infrastructure issues. This had approximate 1% impact to our fourth quarter production which equated to approximately $1 million in lost revenue during the quarter. Fortunately we did not experience any material long term damage but our production was temporarily curtailed or shut in and lasted into January.
Finally, LOE for the fourth quarter was higher than expected and should not be considered a run rate by any means. Fourth quarter included a negative prior period adjustments in the amount of $1.5 million. This adjustment related to an operator billing us our share of the cost of the compressor for the full year of 2013 all in December. This clearly made our LOE per BOE seem unusually high in the fourth quarter, that’s the reason. This was the last major item that impacted our fourth quarter EBITDA
I won’t go over all the numbers in the release but I will point out that our LOE and G&A expenses for 2013 came in as expected when compared to our 2013 guidance and it is attributable to efficiencies we have achieved both on a corporate level and at the field.
In terms of our distributable cash flow, the fourth quarter 2013 totaled approximately $43 million or $0.55 per common unit generating a coverage ratio of about 8.88 times based on our current monthly distribution of $0.20 and $0.73 per month or $0.62 at quarter’s end per quarter. For the full year our distributable cash flow totalled approximately $185 million generating a coverage ratio of 1 times.
As it relates to predicting our coverage ratio I was right. I did mention on our last conference call that we were expecting to average 1 times for the year. So I am not sure why anyone would be surprised by our 0.888 times coverage for the fourth quarter. That being said I will be the first one to say that we got there little differently than how we had anticipated since we spent less capital than forecasted. However I hope that what I portrayed and what I consider the bright side of all this is that fourth quarter was impacted primarily by things that were out of our control and not issues with our actual operation. The differential blowout in the break [ph] were alone accounted for all the passage [ph] of our fourth quarter variance. That and the production downtime we experienced due to severe weather are two things that have already improved in the first quarter.
Next I will turn to our hedging portfolio. During the fourth quarter and into the first quarter, we have been very active as a result of the Pinedale acquisition and have been able to take advantage of some recent price product and natural gas price for 2014. Specifically to the Pinedale acquisition on the NYMEX gas side, we added 85,000 mmbtu per day at an average of $4.26 in 2014, 85,000 mmbtu per day at an average of $4.17 in 2015, 50,000 mmbtu per day at an average of $4.12 in 2016 and 50,000 mmbtu per day at an average of $4.14 in 2017. This equates to a 100% of the expected PDP production and 40% of the uplift from new drilling we expect in 2014 and 2015. In total we hedged approximately 80% of the proved production in 2014 and 70% in 2015. We are not fully hedged in the outer years primarily as a result of being a non-operator position in the Pinedale.
As I just mentioned we have hedged 100% of the PDP production through 2017 but as we get further out the curve specifically in 2016 and 2017 we thought it was prudent to hold off hedging in production that we expect to come on drilling new wells. As we are not in control of these plans and our partners are not active hedgers we need to make sure that we do not end up in a position where we are over hedged because they slowed their drilling plans. We will look to opportunistically add additional volumes as time goes by and we were able to get a better idea as to what their drilling plans are for the future. Additionally to protect ourselves from potential swings in gas differentials, we added northwest Rockies basic swaps in 2014 for 80,000 mmbtu per day at an average negative differential of $0.20 and 75,000 mmbtu per day for 2015 at a negative $0.29.
I want to point out that this is one of the advantages of acquiring natural gas assets versus oil assets. Certainty of cash flows is easier to generate on gas assets due to being able to hedge price differentials. There is a liquid market to do this for most gas price indices which is not the case for a while.
On a total basis, our natural gas is hedged 85% in 2014, 92% in 2015, 85% in 2016 and 47% in 2017 all at weighted average prices of about $4.42. I will note that this does not assume any CapEx plans in 2015 and beyond. So specifically in the Pinedale where there is a significant amount of drilling anticipated for years to come, we are not as heavily hedged as this would indicate.
In terms of oil, 2014 expected oil production is 93% hedged, 2015 is 64% and 2016 is 24% hedged, all at a weighted average price of approximately $92.71 per barrel. Recently we were able to take advantage of the recent increase in the oil curve to layer on to 3-way [ph] collar for an additional 1000 barrels a day in the first half of 2015, again as is our strategy, we will continue to opportunistically increase our hedge percentage in 2015 and 2016 to protect our future cash flows.
More details regarding our current hedge portfolio and percent of hedge can be found in the supplemental Q4 full year 2013 information package posted to our website.
Let me turn to our credit facility and liquidity for a quick update. We are currently in the process of our semi-annual borrowing base redetermination and we expect to complete this in April. I anticipate that with the inclusion of our recently closed Pinedale acquisition, our borrowing base will increase to approximately $1.5 billion. As we have done in the past, I do not anticipate absent for bank commitments to increase beyond the current $1.3 billion until it is needed.
As of today Vanguard has $935 million in outstanding borrowings under the revolver which provides us with $375 million in current liquidity after taking into consideration the current $1.3 billion borrowing base and $10 million in cash.
At the end of November, we instituted our new ATM program which allows us to sell both common and preferred units at market prices during the normal trading day. Since that time we have raised approximately $46 million via our common units and $1 million via our preferred units. We have been very pleased with the performance of this program and absent any large acquisitions this will be our preferred method of raising capital via the equity markets.
Now let me turn to our outlook for 2014. We are expecting some good results in 2014. 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 activities. Our guidance does include the recently closed Pinedale acquisition beginning in February. So January financial results will not include this acquisition.
We are expecting our total daily production to be between 51,830 barrels of oil equivalent and 55,220 barrels of oil equivalent. Only 17% of the production is expected to come from oil and 14% from natural gas liquids in 2014. But this still accounts for over 50% of the expected revenues. I want to point out that total production [indiscernible] quarter over quarter except in the first quarter where you see only two months of impact from our Pinedale acquisition. So you will see an increase from the first quarter to second quarter.
On the expense side, we are forecasting LOE per BOE to be in the range of $6 to $7 which is below the 2013 rate of approximately $8 per boe. This is largely attributable to the increase in natural gas production associated with the Pinedale acquisition. Production taxes are forecasted to be between 10.5 and 11% and G&A is expected to be between $1 and $1.20 per boe, which is also lower than 2013 due to having a significant amount of non-operator production with little incremental G&A expense necessary.
First quarter of 2014 is expected to have an oil differential of about negative $11.25. We are expecting differentials to improve over the course of the year but still remain fairly depressed to average just under a negative $10. This assumption has a significant impact on expected EBITDA for 2014 and we hope that there is some upside to this but we can’t count.
The natural gas differentials, the first quarter of 2014 is expected to be negative $1.05, for the balance of the year we are forecasting differential of about negative $1.20. NGL realizations are forecasted at approximately 33% of WTI which translates to a $31.60 per barrel for the year and is based on a weighted average basket across the company of 38% ethane, 27% propane and 9% isobutene, 13% normal butane and 13% natural gasoline. I want to point out that transportation gathering and processing costs are included as a reduction of revenue and as such are reflected in our differential assumptions not LOE, which has been our standard practice.
Based on a 2014 strip price of $97.65 per barrel of oil and $4.92 per mmbtu for natural gas and the previously discussed assumptions, we expect to generate approximately $415 million in adjusted EBITDA representing a 30% increase over 2013. Scott has already discussed our 2014 capital spending which is expected to increase from 2013 level of 57 million to approximately 137 million with a 114 million designated as maintenance capital and 23 million as growth capital. This level of total capital spending amounts to approximately 33% of our 2014 expected EBITDA. Our cost and distribution coverage will vary from quarter to quarter because of this lumpiness we have detailed our expected capital spend by quarter in our guidance but these numbers are always from the adjustment as the timing of our capital projects tend to shift during the year especially since about 75% is expected to be non-operated capital.
Interest expense is expected to be approximately 72 million and includes Pinedale acquisition as currently financed on the credit facility. This does not take into consideration any long term financing assumptions whether that be capital raises via the high yield debt, common, or preferred equity markets.
Based on the numbers outlined in our guidance and based on our recently increased distribution of $0.21 per unit, we expect to generate a distribution coverage ratio of between 1.1 and 1.5 times for 2014. Our number one goal is to provide a stable yet growing distribution to our unitholders for the long term. We feel very comfortable with our distribution coverage for 2014 and we are well prepared for almost any price environment. This comfort level is supported by the distribution sensitivity slide that can be found in the supplementation information posted on our website which indicates very stable coverage levels regardless of NYMEX gas prices or WTI oil prices. However I will reiterate that Pinedale acquisition only had 2 months of contribution to the first quarter. Combined with higher forecasted differentials in the first quarter and a high forecasted capital spend, we expect the first quarter distribution coverage to be approximately 1 times.
Maintenance capital has received a lot of attention over the last few months and I want to reiterate that Vanguard’s policy is to spend enough maintenance capital to keep cash flow flat, not production or reserves. As we all know, one barrel of oil is not equal to 6 mcf of gas on a value basis, and as an MLP we are paying out a majority of our cash flow to our unitholders so our focus is on cash. The company can keep their production on an equivalent basis flat through gas drilling, ultimately ending up with a declining cash flow profile and potentially not being able to maintenance their distribution. In that scenario we do not believe you are not spending enough or the right kind of maintenance capital.
We went through an extensive capital budgeting process and maintenance calculation has come up with what we need to maintain in 2014. Because 2013 only included 9 months of our Range acquisition and no benefit from our Pinedale acquisition we needed to calculate what these impacts would have on our reported 2013 adjusted EBITDA that ultimately need to be maintained in 2014. Not before you have done the math but if you are interested, these details can be found in our supplemental information posted on our website. What I will point out is that the EBITDA we are trying to maintain in 2014 is based on our 2013 performance and acquisitions and is approximately $408 million.
We then went through the forecast for our base assets in 2014 to determine how much capital we need to spend to offset the natural PDP decline in our cash flow year over year. Ultimately this equated to approximately $114 million in maintenance capital. The balance of our capital spend for the year or 23 million will be considered growth and will be solely in the Pinedale.
For financial reporting purposes, what this means is that every quarter we will show 73% of the Pinedale capital spend as maintenance capital assuming we stay at the expected 8 right drilling program. Lastly, we do not intend to maintain our growth EBITDA from year to year and thus will not increase our distribution based on that cash flow. We do not want to get on that treadmill and put ourselves in position where we will have to spend more and more growth capital every year in order to maintain our distribution level on increasing. Acquisitions will continue to drive distribution increases.
Cash flow generated from our growth projects will be designated to pay down debt, thereby helping to reduce our leverage which in turn to require us to issue fewer common and preferred units as we continue to grow. We feel that this is the most conservative and prudent approach to including growth capital into Vanguard’s strategy.
Our conservative philosophy of slow and steady distribution increase served us well this year. We do not immediately declare large increases to our distribution as a result of our acquisitions, but choose to keep some coverage and reserve should un-controlled leverage rolls [ph] as oil differentials and NGL pricing remain volatile.
In hindsight it clearly was the prudent thing to do. The reason we need to operate at a higher distribution coverage level is to protect our distribution when unforeseen circumstances occur. All that being said, we were still able to increase the distribution 2.5% in 2013 while maintaining a distribution coverage of 1 times.
As Scott mentioned, and as noted in our press release yesterday, we have increased our monthly distribution of $0.25 for the month of February or $0.03 annualized to $0.21 per month or an annual distribution of $2.52 per unit.
We are very encouraged by recent events in natural gas market and the level of acquisition deal flow which we feel will ultimately lead to a successful 2014. This concludes my comments. We’d be happy to answer any questions you might have at this time.
(Operator Instructions) Our first question is from the line of Kevin Smith with Raymond James.
Kevin Smith – Raymond James
Would you mind updating me on the 15 well horizontal Woodford program, if my memory is correct, I think you were targeting those wells to come online in January?
I am sure we hope they were going to come on January but as I said in my comments, the first 5 that we drilled in the Jones joint venture, actually they are cleaning up right now, there were some delays – some of it is winter related, this couldn’t get in there because of the freezing weather in Oklahoma, so those are all cleaning up, I think four of them are doing about as expected, versus one that’s going to need some gas lift equipment that will be installed probably next couple of weeks – that’s online, those are just doing fine. The other wells where we have smaller interest some are operated by Jones, some are operated by Pablo. They are in various stages of completion, and I think Pablo wells are, six of those we participated in and they are all in the flowback right now. So hopefully by the middle of March we’d pretty much have – all that completion operations will be finished.
Kevin Smith – Raymond James
And then as we look through 2014, are you going to have another kind of lumpy Woodford completion schedule, I am sorry I missed that in your prepared remarks?
I think most of our activity as we laid in the comment on how we are going to spend, most of this will have taken place already in the first quarter. And most of our spending there again except for the recompletion efforts that we are going to be doing, the reworks, there is some drilling that’s planned for later in the year and I think we have – I think we may have those couple of wells in the latter part of the year but it’s not anything like the number of wells that we participated in 2013.
And keep in mind, Woodford I tell you represents about 13% in our capital budget, we think this year is going to be the Pinedale area, we are pretty consistent developing there.
Our next question is from the line of John Ragozzino with RBC Capital Markets.
John Ragozzino – RBC Capital Markets
I am trying to figure out something to make myself sound smart here. Scott, you mentioned a non-op project with the Diamond Bag [ph] there in the horizontal Wolfcamp and a possibility of a slight increase in your non-op CapEx budget contingent funds and success there? Can you give us a little bit of an idea of what magnitude is on potential increase?
Well, the wells are about 8 million, we already participated in the first one again, and it will be supposed to be flat I think in the next couple of weeks. That’s 2.7 million, and obviously this is an area where Diamond Bag bought an interest as part of fairly large acquisition. We were very fortunate to already have a percentage in. What they have implied to is – they get to see the success that they hope for, that they will go into development mode. I am not sure if that means a one rig program, a two rig program or three rig program. I think it remains to be seen but obviously it’s right in the horizontal Wolfcamp play, in ventures [ph]. If it works it should then be well positioned to be in from our perspective, because it’s an area that basically came as part of the small acquisition. So we have a low investment and lot of upside. I think we would just look at it at the time and see what kind of returns are, and we know what their drilling plans are. So it could be material depending on the number of rigs they decide to deploy on.
John, I will point out, you hit on one of the reasons that we chose to cut back our growth capital in terms of our guidance because of this type of situation we expect changes to our growth capital budget over the course of the year, for things that unforeseen currently, I mean we wanted to leave some room for things like that which is why we started that $23 million instead of the 50 million that we initially anticipated at Pinedale.
John Ragozzino – RBC Capital Markets
And then one more just I guess a bigger picture question – there has been quite a bit of just shift shuttling around and change I guess when you look at that portfolio I guess from maybe 2010, through today, and could you help give a good idea of what – of like rank order of returns for the various core project areas at the current – commodity price environment?
I think we got over kind of the anticipated returns in remember the Pinedale area, certainly – we’ve had some very good results. So those returns are expected to be in excess of 50% at current economics, and the Permian, our recompletion program, we are anticipating somewhere in the 66%, rate of return for the recompletion projects we are doing. We also mentioned the Arkoma where we have – not as robust probably closer to the 25% type rate of return, but those are very NGL price dependent. So obviously there could be some upside if NGL pricing continues to improve. The Big Horn, as we said we had some great success there in the stimulation program, not large dollars. So those are the largest dollars, hopefully that answers your question on the expected returns.
Our next question is from the line of Michael Peterson with MLV & Company.
Michael Peterson – MLV & Company
I have two questions. First one regards differentials, now appreciate the perspective you shared, Richard, in your prepared remarks and specifically as you talked about the differences in commodity, there has been an ongoing dialogue between the sub sector with regard to wellhead hedging, is it still your perspective that it’s not cost effective or depth of the market isn’t quite there?
I mean we hedge wherever we can, I mean unfortunately there are just certain areas that there is no liquidity, there is no market. Even if you wanted to, I mean specifically in the Big Horn, where we have the most volatility there is an opportunity to hedge which is again why I said it’s one of benefits of metgas acquisition, you cannot withstand [ph] to that differential. So you can really – you know what your returns are going to be, you lock that in, there are certain oil markets that you can hedge and we have. I mean we have put a number of midlands hedges in place which insulate some of our Permian differential but we can’t do that everywhere. We also put some hedge in place too. So we do it where we can, unfortunately we can’t do it everywhere.
Michael Peterson – MLV & Company
In terms of acquisitions, you have a commodity bias looking into 2014?
Not really. We are opportunity driven. I think as we said earlier we kind of made the decision a while back in 2012 to go gas and obviously we have done that. It’d be nice to see some liquids focused opportunities but so many of those that we are seeing are very, very pricey, anything in the Permian really is extremely difficult just to make work in our judgement. So hopefully we will see some other conventional oil opportunities from other places that perhaps valuations won’t be quite frothy but if we see a good gas deal we are not going to – we are going to do whatever acquisitions fit the profile.
On the oil side, you see – as you know a very speculative price tag which as a disciplined buyer we continue to use – because that’s where we can hedge. I think that you will find that there is lot of other firm, PE firms in particular that are willing to speculate that, that curve is not accurate. So they are going to bid a lot more than we are, if they are willing to take that risk. On the gas side, I think that’s where we are going to see more opportunities, you’ve got a price tag with $4 every year going forward. It’s been a while since we have seen that, and so I think sellers, you are going to see more gas opportunities than you are on oil in general because –
Our next question is from the line of Praneeth Satish with Wells Fargo.
Praneeth Satish – Wells Fargo
I guess just staying on the theme of differentials, I mean is there anything that you guys can do proactively to improve differentials, maybe get into real opportunities or is there any pipeline on the horizon, I guess anything going on there?
We are as proactive as we can be. The primary market out there is Marathon and we are in discussion with them about looking at rail opportunity, there is plenty of pipeline capacity but again this is not a big growth area, and this isn’t like the Bakken, this is very mature, and the production is typically maintaining, but it’s not growing, there is no new infrastructure being built. So we are constantly looking at new markets and new opportunity to get barrels out, lot of time with Marathon who is going to be 800 pound gorilla for the basin area.
We are also looking at trying to get our oil price on difference index. That’s another avenue we are looking for to mitigate some of the volatility.
Praneeth Satish – Wells Fargo
And can you just remind us how much of your NGL production is price off of Conway versus Belleview [ph], just kind of see what the exposure to that blowout in propane prices in Conway?
Unfortunately none, my understanding is everything is priced on Belleview [ph]. We don’t have any Conway exposure.
And our next question is from the line of Michal Guidant [ph] with Robert W Baird.
Can I ask, as it relates to the ATM program, relative to a modest growth capital budget and stable balance sheet backdrop that you have now, how should we think about your objective on the quarter to quarter basis in terms of raising equity funding through the ATM program?
The impression, is we are very consistent month in, month out. I expect that we will use the program and raise a little bit every month. The way we have modelled this is such that by the end of the year, we would be back to a 3 times debt to EBITDA type level.
Can you provide any color on your first quarter realized differentials could be relative to your guidance?
Our guidance was based on kind of what’s already occurred and what we see – what we predict happening over the course of the next 6 weeks, 5 weeks. The differential has improved, the Big Horn differential which is the biggest factor, it just came in with that 27—it was at 27, then in January it was 22 and here in February it was 14. So we are anticipating that trend to continue but still it’s why there has been – and we expect it to be on an average basis for the whole year.
At this time there are no further questions in queue. I would like to turn the call back over to Scott Smith for closing remarks.
Thank you, Doug. Again thanks everyone for joining us this morning. As I look at our script this morning, this is probably the most longwinded call that we’ve had in our history. So obviously we had – lots to go over, lot of activity this year. Again can’t say enough how pleased we are to have this Pinedale acquisition done. I think it’s going to be a great cornerstone property for us long term. Again we are very excited about opportunities we are seeing in the acquisition market, I think it’s going to be a much – lot more conventional assets coming to market than we saw last year. And with that, hopefully it would be very competitive and we need to make some quality deals to continue the grow the company. So we will visit with you all again in May, or in April. So with that you guys have a great day and if you have anything else please reach out to Richard or myself. Thank you very much.
Thank you ladies and gentlemen this does conclude our conference for today. We like to thank you for your participation and you may now disconnect.
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