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EV Energy Partners (EVEP)
Q4 2011 Earnings Call
February 29, 2012 5:00 p.m. ET
John Walker - Executive Chairman
Mark Houser - President and CEO
Michael Mercer - SVP and CFO
Kevin Smith – Raymond James
Ethan Bellamy – Robert W. Baird
[Tony Langham - Corey Partnerships]
Adam Leight – RBC Capital
Previous Statements by EVEP
» BreitBurn Energy Partners CFO, Vanguard Natural Resources CEO and EV Energy Partners COO Present at RBC Capital Markets MLP Conference - Conference Call Transcript
» EV Energy Partners' CEO Discusses Q3 2011 Results - Earnings Call Transcript
» EV Energy Partners' CEO Discusses Q2 2011 Results - Earnings Call Transcript
Thank you. I’m calling from Houston’s Intercontinental Airport while the rest of our team is in EVEP’s offices in Houston. Mike Mercer will elaborate on our financial results, but results were generally in line with guidance except for G&A expense, and I want to explain that.
On approximately $450 million of acquisitions in the fourth quarter, we recognized $2.3 million of due diligence and transaction related costs that flowed through to both EBITDA as well as distributable income.
Also, we recognized roughly a $4 million impairment charge on some noncore Austin properties that are going to be sold later this quarter. And that’s offset by the $4 million we received from Total and [unintelligible] from the sale of the assets in the Point Pleasant Utica NGL window.
Also, based upon successful efforts accounting, we had $9 million in dry hole costs, and that was primarily from the two horizontal wells that we drilled in the San Juan Basin. We continue to do a very good job of dropping our per-unit LOE costs. In 2010 these were $1.92 per Mcf equivalent, and we dropped those to $1.81 in 2011 and for the fourth quarter it was $1.78. We continue to expect to drive down costs in 2012. Our replacement costs were $1.43 last year and our acquisition costs were $1.21 per Mcf equivalent.
Our acquisition strategy of basin concentration allows us to continue to lower costs in a difficult natural gas and ethane market. Based on expected production, EVEP is about 90% hedged in natural gas, NGLs, and oils this year and 80% next year.
I decided to reorganize EnerVest, the GP, of EVEP in December of last year. Three of our entities, EVEP, EnerVest Institutional GP, and EnerVest [unintelligible] and the leaders named as CEO of those units including Mark Houser of EVEP.
The organization was needed as a result of the $3 billion in acquisition growth EnerVest entities have had within the last two years, and the further need to get even more focused on our assets. My role as CEO of EnerVest has not changed.
A few weeks ago, EVEP completed a 4 million share offering including the [sole] overallotment option for $268 million net to the company to provide a stable and conservative balance sheet. The offering was roughly three-times oversubscribed from both retail and institutional investors and obviously we’re very pleased with that.
In the Utica, EnerVest entities have participated with Chesapeake in 27 wells and have 5 producing. I want to particularly highlight the Burgett well, which had higher condensate yields than all the previous producing wells and we’re also pleased with how well the Burgett well is holding up.
We’re encouraged that the completion process in the NGL window is significantly improving and costs and days to drill are coming down. EnerVest Operating is drilling its first Utica well, the Frank 2H for EVEP and [Fund] 11 in Stark County to address, along with Chesapeake and other operators, the best completion technique for the oil window, and we still plan to commence the monetization process for our Utica assets later in the second quarter.
Now Mike Mercer will go over our financials, guidance, and [unintelligible].
Thank you John. For 2011 our adjusted EBITDA and distributable cash flow were $212 million and $126 million respectively, which were increases of 43% and 34% over 2010. These increases were primarily due to acquisitions completed during the fourth quarters of 2010 and 2011. Distributions related to 2011 were approximately $118 million.
Production for the year was 29.2 Bcf of natural gas, 891,000 barrels of crude oil, and 1.096 million barrels of natural gas liquids, or 41.2 Bcfe. This is a 47% increase over 2010 production of 27.9 Bcfe and, once again, it was primarily due to acquisitions we completed during the fourth quarters of 2010 and 2011.
2011 net income was $102.6 million, or $2.71 and $2.68 per basic and diluted weighted average LP unit outstanding, respectively. Several items to note that were included in that income for the year were $35.5 million of unrealized gains on commodity and interest rate derivatives, primarily due to the decrease in future natural gas prices that occurred from the end of 2010 to the end of 2011, and the effect of such prices on the mark-to-market value of our outstanding derivative portfolio.
$9.8 million of noncash compensation related costs contained in G&A expense. $2.9 million of property acquisition due diligence and transaction-related costs for the acquisitions we did in 2011 and a little bit of tail over from 2010 acquisitions. $12.1 million of dry hole and exploration costs for the year. $11 million of impairment costs, primarily that related to the divestiture of noncore oil and gas properties and assets held for sale at the end of the year, and a $4 million gain on the sale of assets related to a small amount of our Utica acreage that was part of the Chesapeake and Total agreement completed in December 2011.