Vanguard Natural Resources, LLC (NYSE:VNR)
Q2 2011 Earnings Call
August 4, 2011 12:00 pm ET
Scott Smith – President and Chief Executive Officer
Richard Robert – Executive Vice President and Chief Financial Officer
Britt Pence – Senior Vice President of Operations
Lisa Godfrey – Investor Relations
Ethan Bellamy – Robert W. Baird & Co.
Good day, ladies and gentlemen. Thank you for standing by. Welcome to the Vanguard Natural Resources Q2 2011 Earnings Conference Call. (Operator instructions.) This conference is being recorded today, Thursday, August 4th, of 2011, and I’d now like to turn the call over to Ms. Lisa Godfrey of Investor Relations. Please go ahead, ma’am.
Thank you. Good morning everyone, and welcome to the Vanguard Natural Resources LLC Q2 2011 Earnings Conference Call. We appreciate you joining us today. Before I introduce Scott Smith, our President and Chief Executive Officer, I have some information to provide to you.
If you would like to listen to a replay of today’s call it will be available through September 4th, 2011, and may be accessed by calling 303-590-3030 and using the passcode 4461501. 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 this morning’s earnings release. Please note the information reported on this call speaks only as of today, August 4th, 2011, and therefore you are advised that time sensitive information may no longer be accurate at the time of any replay. Before we get started please note that some of the comments today could be considered forward-looking statements and are based on certain assumptions and expectations of management. For a detailed list of all of the risk factors associated with our business please refer to our 10Q that will be filed by early next week and available on our website under the investor relations tab and on Edgar.
Now I would like to turn the call over to Scott Smith, President and Chief Executive Officer.
Thank you, Lisa, and good morning everyone and thanks for joining us on our conference call to review our results for Q2 2011. Joining me are Richard Robert, our Executive Vice President and Chief Financial Officer; and Britt Pence, our Senior Vice President of Operations.
During the call this morning I’ll briefly review the Q2 production results along with capital expenditures and then we’ll turn the call over to Britt for more specifics on the drilling we have done this year and our current activities in Q3. I’ll then wind up with a discussion of our business development efforts and provide an update on the timeline of the proposed merger with Encore Energy Partners, LP.
I’ll begin with a brief summary of this quarter’s production. Average daily production for Q2 was 13,286 BOE per day, consistent with Q1’s average daily production of 13,273 BOE per day and up 191% from the 4,569 BOE per day produced in Q2 2010. The increase in total production on a BOE basis is primarily due to the Encore acquisition effective December 31, 2010. The combined asset base of both companies continues to deliver production results which are very impressive when one takes into account the minimal amount of capital that has been expended on the properties during the first half of the year. Much of the credit for our stable production profile is attributable to the hard work done by our field-level employees, but primarily those in our largest operating areas being the Bighorn and Williston region and the Permian Basin.
Breaking down the production of each on an individual product, during Q2 average daily oil production was 7,367 barrels, NGL production averaged just over 1000 barrels of NGLs per day, and our natural gas volumes averaged 29,482 MCF per day. With respect to our 2011 CAPEX program, during Q2 we spent $4.5 million in total, which was split between Vanguard with $3.8 million and our approximately 46% of ENP’s CAPEX at $1.5 million.
Now Britt will provide a more detailed summary of our activities to date and what we have planned for the balance of Q3.
Thanks, Scott. As a reminder in the 2011 guidance that we put out in March, Vanguard’s capital budget was forecast to be between $27 million to $28.5 million which includes VNR’s 46% interest attributable to ENP’s planned capital spending for the year. Our 2011 drilling efforts are focused in three areas: the Parker Creek Field in Mississippi, the Bone Spring play in Permian Basin, and the Sun TSH Field in South Texas.
The drilling in the first half of the year has been in the Parker Creek Field. These wells have some of the best economics in our drilling inventory of proved locations. Therefore we wanted to get these wells drilled first in the first part of this year. Prior to initiating this year’s drilling program we and our partners reworked the 3D seismic data and decided to drill three 14,200-foot [Hawston] development wells, which were [ASE] for $3.5 million per well. Vanguard’s working interest is 53% in each well. Now that all the wells have been drilled, we believe the actual average well cost will be approximately $2.8 million or 20% less than budget.
The first Parker Creek well was completed June 11th at an average 441 barrels of oil per day for the first 44 days. The second Parker Creek well was completed June 27th and it averaged 171 barrels of oil per day for the first 28 days. We are pleased with these results as collectively they are in line with expectations. The third Parker Creek well will be cracked this Friday, and we are anticipating this well to produce over 100 barrels of oil per day after cleanup. There is one additional 53% working interest [Hawston] proved and developed location that we plan to drill sometime in 2012.
In the Permian Basin, the Miller 1H spurt on July 7th. This well is a 100% working interest horizontal oil well in the active Bone Spring play located in Ward County, Texas. The Miller well is estimated to cost $6.5 million, which represents approximately 37% of our total 2011 capital spending. We have drilled the 11,250-foot vertical pilot hole and logged 32 feet of pay across three Bone Spring spans. We are in the process of a planned site track to drill the wells horizontally for a lateral distance of approximately 5000 feet. Our completion plans include nine crack stages which is the same completion program used by other operators in the area, including [Simirex] and [Anadarco]. Based on the offsetting horizontal Bone Spring wells, we anticipate that the initial rate for this well will be between 300 and 400 barrels of oil per day. We anticipate completing this well in September, 2011, provided we can arrange a frack group for September.
In our Ward County leasehold there are four additional 100% working interest Bone Spring proved, undeveloped locations to drill over the next few years. Our third area where we have planned activity is in the Sun TSH Field in South Texas where we plan to drill three 100% working interests, 7900-foot, 20-acre infield vertical almost and Escondido gas wells that are estimated to cost approximately $1 million each. This is an attractive drilling play as the produced gas from these wells will be processed, and based on the other wells in the field we should see liquid yields of approximately 142 barrels per million cubic feet of produced gas. The combination of a high liquid content along with high NGL prices will result in favorable returns, even during today’s low gas price environment. We anticipate our first Sun TSH well will spud in the next two weeks. The wells take approximately two weeks to drill; we anticipate initial rates of 400 to 500 MCFE per day per well and an average EUR of approximately 0.9 BCFE per well.
There are 39 additional 50% working interest proved, undeveloped locations to develop in the Sun TSH field over the next several years. Now I will return the call back over to Scott.
Thanks, Britt. On the business development front as we announced this past Monday, Encore and Vanguard completed the acquisition of the Permian assets that were announced earlier in July. This acquisition is an excellent complement to our Permian asset platform and we’re confident we’ll be able to expand our footprint in the eastern portion of the Permian basin as we continue to work the area and reach out to other operators with suitable assets to fit the MLP structure. As always, we’re continually very busy evaluating, reviewing and making proposals for acquisitions of quality oil and natural gas properties. We’ve been very pleased with the deals that we’re seeing in the market and we feel good about our position to compete for frack transactions as we go forwad.
Obviously the biggest development at both Vanguard and ENP was the announcement on July 11th that the respective conflicts committees had reached an agreement to a proposed merger between the two entities and that a formal merger agreement had been executed. Once this process was completed our SEC council along with input from attorneys from both conflicts committees and the financial advisors have worked diligently to put together a joint proxy statement which I’m pleased to report was filed with the SEC on August 1st. We must now wait to hear from the SEC if they will subject this filing to a full review or approve the filing as it currently stands and allow us to set the unit holder votes for both companies sometime in September. Hopefully we’ll have some clarity on this front in the next couple of weeks.
That concludes my remarks and now I’ll turn it over to Richard for the financial review.
Okay, thank you. Good morning. Let me start the same way that I started the last call and reiterate that we are very pleased with the benefits we’ve seen from the Encore acquisition. We have had many employees and consultants working long hours to make the integration successful and we continue to work hard to ensure that the benefits we envisioned come to fruition. Each month we see more progress and each month we reap more rewards from the efforts people are making.
I’d also like to point out again that unfortunately the Encore acquisition adds a layer of complexity when reviewing our financial results and our reserve and production information. The Encore financial statements are consolidated into the Vanguard financial statement and the 53.4% ownership interest that we don’t own in ENP is backed out in one lump sum as a line item titled “non-controlling interest.” Also, because the Encore transaction is very material to Vanguard, the comparison to 2011 results, 2010 results is not very meaningful other than an indication of how much we’ve grown. I believe a better indicator of how we are doing this year is to compare our results to the 2011 guidance or expectations that we provided in a press release dated March 1, 2011, because that is what we use internally to gauge are success and therefore I’ll be making certain comparisons to this guidance during my prepared remarks.
With this in mind let me turn to our operating results. We reported adjusted EBITDA attributable to Vanguard unit holders of $36.5 million for Q2 2011 as compared to $19.1 million reported in Q2 2010. For the six months ended June 30th, 2011, we reported adjusted EBITDA attributable to Vanguard unit holders of $74.1 million compared to $37.7 million for the six months ended June, 2010. As a reminder, our adjusted EBITDA guidance for 2011 was a range of $140 million to $147 million, and if you annualize our actual results through June 30th we would exceed the high end of that range that we’ve provided. So we’re encouraged by these results, especially when considering some other factors that have impacted our general and administrative expenses this quarter, which I will discuss in more detail shortly.
Distributable cash flow attributable to Vanguard unit holders totaled $25.6 million for Q2 2011 compared to $1.1 million generated in Q2 2010. This level of distributable cash flow generated a distribution coverage ratio of 1.47 times based on our increased distribution of $0.575 per unit and will be paid on Friday, August 12th. However, as I have suggested in the past, distribution coverage should not be analyzed on a quarter-by-quarter basis when the timing of capital expenditures can significantly impact the number. Based on the projects that Britt outlined, we anticipate spending between $14 million and $17 million in capital in Q3 alone. Clearly this will impact our distributable income for Q3 and we expect our coverage ratio to be much lower than in Q1 and Q2. That being said we continue to feel confident that our guidance level which reflects a distribution coverage ratio of 1.4 times to 1.45 times for the entire year of 2011 continues to be realistic even with the current increased distribution level.
Vanguard reported a net income attributable to Vanguard unit holders of $31.8 million or $1.05 per basic unit for Q2 2011 as compared to net income of $3.9 million or $0.19 per basic unit for Q2 2010. Our unrealized non-cash gain of $31.5 million before excluding the non-controlling interest on commodity-driven contracts has significant impact on GAAP reported income. So after excluding the unrealized non-cash items and material transaction costs occurred on acquisitions and mergers as reflected in the reconciliation schedule attached to the press release, the adjusted net income attributable to Vanguard unit holders for Q2 was $15.7 million or $0.52 per basic unit compared to net income of $10.1 million or $0.50 per basic unit earned in Q2 2010.
On a more detailed level I’m going to discuss some revenue and operating expense results. Including the effects of our commodity hedges we have experienced a 31% decline in our average realized price per natural gas, an increase of 12% in our average realized price for oil, and a 61% increase in our averaged realized price of natural gas liquids when comparing Q2 2011 with Q2 2010. These averages are directionally the same when you look at the six month 2011 versus six month 2010. In hindsight, our decision about two years ago to start focusing more on liquids-based acquisitions has proved to be the right move. Our last five transactions, dating back to December, 2009, have all been liquids-focused which has significantly impacted our production mix. For the first six months of 2010, oil accounted for 36% of our total production and in 2011 it accounts for 56% of our total production. Conversely, for the first six months of 2010 natural gas accounted for 51% of our production and in 2011 natural gas accounted for 36%. Clearly we have shifted from a natural gas-focused company to a crude oil-focused company.
Now to the expense side of our operations, our lease operating expenses on a peripheral basis ran at $12.91 for the Q2 2011, which was up from $11.89 in Q1. The increase in Q2 can be attributed to results in Encore and reflect a more normal level than what was experienced in the Q1 of 2011. Q1 results included a reduction in LOE related to year-end accrual reversals, and Q2 included costs incurred to repair damage to roads and locations from severe winter storms in the Wyoming and North Dakota operating areas. In addition we have several electrical submersible pumps being worked on and we have a second rig running in Q2 to complete a backlog of work related to again, winter storms that prevented us from that work being done in Q1. Our guidance suggested that our LOE would run at between $12.85 and $13.50 per BOE so we are relatively pleased that our Q2 run rate at $12.96 is at the low end of that guidance.
Turning to our general and administrative expenses, I’d like to point out two major items that resulted in an increase in G&A expenses during Q2. First we elected to accrue $1 million each for both Vanguard and Encore for year-end 2011 bonuses for a total of $2 million on a consolidated basis. This is not something we have done in the past. Please note that this is an accrual of anticipated employee bonuses to be paid out in early 2012. These amounts were not paid out this quarter. As they are discretionary, historically we have not accrued year-end bonuses until the amount was calculated and approved which is normally in Q4, however we have decided to change this policy so that our Q4 results are not distorted by the bonus amount but rather are shown as an expected expense and accrued throughout the year. One other important item to point out is that our financial guidance that we publish over the year does not include the impact of bonuses, again because they are discretionary.
The second major item that affected our general and administrative expenses are integration and merger-related costs associated with Encore. As it relates to the merger, we incurred approximately $563,000 of merger-related expenses in Q2 and we anticipate a substantial amount of additional merger related expenses in Q3 related to financial advisors, legal advisors and filing fees. While it is difficult to accurately predict the additional amounts to be incurred in Q3 we expect that $1.5 million to $2 million is likely.
On the hedging front, I’d like to point out that we layered on new commodity hedges during the quarter which are primarily associated with the recently closed Permian acquisition and are depicted in the press release. Of particular interest to some I would note that we have layered in additional natural gas hedges in 2012 and 2013 at $5.32 and $5.62 per MMBTU respectively. In addition we have added oil hedges in the form of swaps, collars, and three-way collars to cover both oil and NGL production, mostly associated with the recently closed Permian acquisition. We continue to evaluate our hedge book and opportunistically add to our current position to ensure stable cash flow into the future.
In addition to commodity hedging we also have entered into interest rate swaps that protect us from increases and interest rates and provide more certainty to our future financing costs going forward. Due to historically low rates during the quarter we opportunistically extended two swaps for an additional two years, one of which we also increased the notional amount from $20 million to $40 million, allowing us to lower the rates from 3.35% to 2.6%, and 2.66% to 1.75% respectively. Last week we extended an additional $20 million interest rate swap for two years, allowing us to lower the rate from 2.38% to 1.89%. All three of these transactions allowed us to take advantage of the current low rates which allowed us to decrease our current interest expense while at the same time providing future stability in our financing costs.
Now onto our liquidity. On June 30th, 2011, Vanguard had indebtedness under its reserved credit facility totaling $185 million with a borrowings base of $235 million which provided for $50 million in undrawn capacity. However, in July we requested an interim redetermination of our borrowings base under our credit facility which resulted in a $30 million increase to our borrowings base to $265 million. Taking this increase into consideration and the funding of the recently closed Permian acquisition, as of August 3, 2011, we had $216.5 million of outstanding borrowings and $48.5 million of borrowing capacity under the facility.
You will note that our balance sheet includes a lot of bank debt and short-term liabilities. This includes the $175 million one-year term loan used to finance the Encore acquisition and all of the outstanding debt of Encore. In July we began the syndication of a new Vanguard credit facility that would retire the $175 million term loan and all of the outstanding debt of Encore upon the consummation of the merger with Vanguard. In the event that the merger is not consummated we will continue to evaluate our options which based on discussions with lenders include extending the term of the ENP revolving credit facility or refinancing it under a new revolving credit facility. We currently anticipate the new Vanguard facility will be significantly oversubscribed and will allow Vanguard to reduce its borrowing costs under its reserve-based credit facility.
At June 30th, 2011, Encore had $230 million outstanding under its credit facility and $137 million of remaining availability after taking into consideration the funding of the recently closed Permian acquisition but no interim requests for additional borrowing base related to the Permian acquisition. As of August 3, 2011, there were $354 million of outstanding borrowings and $146 million of borrowing capacity. We’ve made significant strides in the integration of the Encore acquisition and as demonstrated with the recently closed Permian acquisition, we have continued to create value for the VNR and ENP unit holders. You may have noticed as Scott mentioned that we did file a joint proxy statement on Form S4 with the Securities and Exchange Commission earlier this week. After the SEC has given us the green light to proceed with the vote we hope that both sets of unit holders will take the time to read the joint proxt statement, consider the merits of operating as a single entity and vote.
That concludes my comments. We’d be happy to answer any questions.
Thank you. Ladies and gentlemen, we will begin the question-and-answer session at this time. (Operator Instructions.) Our first question comes from the line of Ethan Bellamy with Robert W. Baird & Company. Please go ahead.
Ethan Bellamy – Robert W. Baird & Co.
Hello gentlemen. Britt, with respect to the Parker Creek wells and Miller 1H, can you tell us that the EURs on those are?
Yes. We anticipate those EURs to be approximately 500,000 per well on the Parker Creek. And then on the Bone Springs we’re looking at $400,000 MDO per well.
Ethan Bellamy – Robert W. Baird & Co.
Okay. And then on those well AFBs at $30.5 million that came in at $2.8 million, what were the components of the AFB that were lower than anticipated?
We drilled those wells in fewer days than what we’d anticipated. The drilling operations went very smooth without any problems.
Ethan Bellamy – Robert W. Baird & Co.
That’s nice news. Looking forward to CAPEX do you expect the same type of well costs and drill times there and if so does that mean we should expect you to trend towards the lower end of the CAPEX guidance range or will you spend that money elsewhere?
Well, going forward we don’t have any more Parker Creek wells this year; we only have one remaining proved location in Parker Creek. But yes, we do have some Odessa locations that are proved, undeveloped in Parker Creek but as far as the remaining program this year it’s primarily in the Bone Spring and that’s a $6.5 million well and it’s too early to call where that’s going to end up on actual costs.
I think generally speaking it’s unlikely that those costs will be offset elsewhere and it’ll just be reduction in overall CAPEX.
Ethan Bellamy – Robert W. Baird & Co.
Okay, that’s helpful, Richard. And what is the overall sort of weighted average decline rate for the total assets right now?
For the total we’re looking at approximately 13% I believe on total decline.
That’s obviously a function of how much drilling you’re doing. Obviously the more drilling you’re doing the higher that decline rate’s going to be because you have new wells that are coming on faster.
Ethan Bellamy – Robert W. Baird & Co.
Sure, and so Richard, as you think about that decline rate and the pretty substantial excess distributable cash flow coverage that you had, what portion of the excess do you see having coverage would you apply towards let’s call it the flush production from those wells coming on, relative to just sort of the base level business if you will?
I mean Ethan, I think if you look at it, we haven’t seen any real contribution from these wells at all – just a few days in Q2 is attributable to the well that came on in Parker Creek. We’ll see obviously a bigger impact here in Q3 but basically our production was essentially almost flat from quarter to quarter.
Yeah, you really didn’t see much decline at all.
Ethan Bellamy – Robert W. Baird & Co.
Okay. I mean that’s a pretty big coverage number. I guess where I’m going with this is at what point do you more rapidly accelerate your distribution growth rates? I’m just trying to get a sense for where your comfort level is on the base production where it is now.
Well, there’s two things to consider, Ethan. One is, and I think I’ve been clear that our capital is not spent evenly. The Q1 and Q2 we didn’t spend nearly as much capital as we’re going to in the second half of the year, so you’ve got to look at it on an annual basis. I think our coverage is going to be in that 1.4 to 1.45 times range which albeit is a little bit high for the year but we also have to look beyond this year into next year and there’s a recognition that we are not, our natural gas realizations on our hedges are going to be lower. So we’ve got to consider that and make sure that we have good distribution coverage for next year as well.
Ethan Bellamy – Robert W. Baird & Co.
Okay, fair enough. Thanks very much, appreciate it, guys.
(Operator instructions.) And I’m showing no further questions at this time, please continue.
Well with that, that’ll wrap up our comments. Thanks again everyone for joining us this morning. If anybody thinks of any questions they may have later please reach out to Lisa, Richard or myself and we’ll be happy to get back with you as quickly as possible. Again, thanks for joining us and we’ll look forward to visiting with you again in November.
Ladies and gentlemen that concludes our call for today, thank you for your participation. You may now disconnect.
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