Good morning. My name is [Mason] and I’ll be your conference operator today. At this time I would like to welcome everyone to the Energen First Quarter 2010 Earnings Conference Call.
All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. (Operator Instructions).
I would now like to turn the call over to Ms. Julie Ryland, Vice President of Investor Relations, you may now begin.
Thank you, Mason. Good morning to all of you. Today’s conference call is being held in conjunction with Energen Corporation’s announcement yesterday of the results of operations for the first quarter of 2010.
Results were provided on a consolidated basis as well as for Energen Resources Corporation, our oil and gas exploration and productions subsidiary and for Alagasco, our small single phase natural gas utility.
Please note that our prepared remarks will include statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor Provision of the Private Security Litigation Reform Act of 1995.
Except as otherwise disclosed, the company’s forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. All statements based on future expectations rather than all historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that may be outside the company’s control and could cause actual results to differ materially from those anticipated.
A discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the company’s periodic reports filed with the Securities and Exchange Commission.
At this time, I’ll turn the call over to Energen’s Chairman and Chief Executive Officer, James McManus. James?
Thanks, Julie. And good morning to all of you joining us today. Yesterday’s we reported a 22% increase in Energen’s first quarter earnings to $1.62 per diluted share. A big driver of this increase was higher realized sales prices for natural gas, oil and natural gas liquids production. Helped by our significant hedge position, the average realized price of oil grew up to 50%, gas 10% and natural gas liquids 60%.
In large part, due to our solid first quarter results, we also raised our earnings guidance for 2010 by $0.10 to a range of $4.30 to $4.70 per diluted share. In addition, we would adjusted our assumed prices for unhedged production for the remainder of the year to more closely reflect the current market outlook.
In other words, we’ve lowered our assumption for natural gas from 550 to 450 per Mcf and raised our assumptions for oil and liquids to $85 per barrel and $0.92 for per gallon respectively.
For the last nine months of 2010, we had hedges in place for 71% of our total estimated production of 87 Bcf equivalent at a NYMEX-equivalent price of $9.65 per Mcf. This price strength is due in a large part to having oil and liquids comprise almost 40% of our 2010 production.
Please note that our 2010 earnings guidance does not include potential benefits from unidentified property acquisitions, Alabama shales exploration or stock repurchases. Neither does it make any assumption related to the potential impairment of capitalized unproved leasehold related to Alabama’s shale’s acreage; in total, our non-cash leasehold exposure, its $24.4 million or 0.34 per diluted share.
Key assumptions included in our guidance are detailed in our news release and I will refer you that document for more information. In other matters our new Chattanooga test well has been drilled to a vertical depth of approximately 8,700 feet and logged. Westervelt 19-2 #1 located in Tuscaloosa County. We not plan to drill 3,000 foot of horizontal leg, test the well, and make an assessment of the economic viability of the Chattanooga shale this summer.
We also had decided to reenter the market in 22-16 #1 in Bibb County. You may recall that the Marchant well was drilled to a total depth of 12,400 feet in 2008 in conjunction with Chesapeake Energy. The well had good shows on the mud logs and 6-8 potential pay zones but it did not produce meaningful amounts of gas when Chesapeake fracced the lowest interval at 11,500 to 11,700 feet in the well.
We believe that we can run a good deal about the kind inside of those shows economic potential in a cost effective way by first leaving more work in the Marchant rather than leaving for immediately to drill a new well as we had originally planned.
Our probable and possible reserves has been reassessed for year-end 2009 and we have seen a slight rise in that inventory about 2% 1.9 billion cubic feet equivalent. The unrisked costs about unproved reserves were basically unchanged; $1.25 per Mcfe for probable reserves and $1.17 per Mcfe for possible reserves.
After applying our own risking we estimate that the risked cost apparently developed our full inventory of probable and possible reserves to be $1.70 to $2.10 per Mcfe. Virtually all of our probably and possible reserves are located in the San Juan and Permian Basin in more than half of our unproved reserves or oil and natural gas liquids.
Activities to prove-up our probable inventory encompass infill drilling, primarily in the San Juan Basin at 300 Bcf equivalent, step-out drilling, primarily in the Permian Basin of 294 Bcf equivalent, performance improvements of a 107 Bcfe and horizontal drilling of 83 Bcfe.
Our San Juan Basin possible reserves are heavily associated with the horizontal drilling of primarily non-coal reservoirs of 486 Bcfe and step-out drilling at 209 Bcfe. And our possible reserves in the Permian Basin relate largely to CO2 expansion. Please refer to our news release for a breakout of our probable and possible reserves by Basin.
Before turning the call over to Chuck Porter our Chief Financial Officer for a review of the first quarter results, I want to mention that last week our $200 million, bilateral line of credit with Regions back was renewed for another 364 days through April 22, 2011. This credit facility is allocated $165 million to Energen and $35 million to Alagasco.
We also had negotiated a $35 million line of credit with Northern Trust, of which $10 million is allocated to Alagasco; and Citibank has renewed its $35 million line of credit, with $15 million allocated to the utility. In total, Energen and Alagasco have access to $475 million of committed credit facilities.
At this time I will ask Chuck Porter to review our results of operations in the first quarter 2010. Chuck?
Energen’s consolidated net income in the first three months of 2010 totaled $116.7 million, or $1.62 per diluted share, and compared with $95.6 million, or $1.33 per diluted share, in the first quarter of 2009. Energen’s resources net income for the first quarter 2010 totaled $71.7 million and reflected a 52% increase from the same period a year ago. And this growth is the results of higher realized sales prices and increased oil and liquids production partially offset by increased DD&A expense and increased administrative expense.
Production in the first quarter increased 25 to 27.2 Bcf equivalent a 10% increase in the Permian Basin reflected our Fuhrman-Mascho acquisition of last June as well as a new water flood development in the North Westbrook unit. Production increased slightly in the San Juan Basin largely due to the impact and new well development and better-than-expected performance from some wells in the over-pressured Fruitland Coal, partially offset by delays from adverse weather conditions.
Production growth in the first quarter of 2010 was constrained due to these weather-related delays and by completion delays in the Permian Basin; I will do not believe however that these early timing issues will negatively affect our 2010 annual production estimate of approximately 114 Bcfe.
Energen Resources First Quarter LOE declined slightly to $1.98 per Mcf equivalent. Base LOE and marketing and transportation expenses fell 6% in response to decreased repairs and maintenance, decreased workover expenses, lower ad valorem taxes, and lower expenses for non-operated properties. Commodity price-driven production taxes, however, rose approximately 28% on a per-unit basis.
DD&A expense in the first quarter increased 14% over the same period a year ago to $1.76 per Mcf equivalent largely due to higher development costs and price-related reserve revisions at year-end 2009.
Per-unit G&A expense increased $0.56 cents per Mcf equivalent largely due to labor and benefit-related expenses and certain legal expenses.
Alagasco’s utility operations generated net income of $44.2 million in the first quarter of 2010 as compared with $47.5 million in the first quarter of 2009. And this decrease largely reflects the timing of rate recovery and revenue reductions under our rate-setting mechanism.
That’s a quick look at the quarter. So now I will change ends back over to you James.
Our usual hedge detailed for the remainder of 2010, 2011 and for 2012 including our new natural gas liquids hedges is included in our news release. So I won’t go over all of it here. I do want to note that because of our amount of oil and liquids production our 2011 hedges combined with an average NYMEX combined to form a average NYMEX-equivalent price of $8.79 per Mcf equivalent.
So that concludes our formal remarks and this time I would turn the phone over to Mason to get our Q&A session underway.
(Operator Instructions). Your first question comes from the line of Kristal Choy from Raymond James. Your line is now open.
Kristal Choy - Raymond James
Is there any detail on what you’ve seen from the logs in the [Chat Well], and can you tell us how much you think this well will cost?
Kristal I’m going to tell you that from a long information what we got replaces about 90 feet of Chattanooga pay, which is what we expected to have and is consistent with what we have in the Cain well as you know this well is about 5 or 6 miles away from the Cain well. And let me turn it to Johnny Richardson to talk about the cost of this particular well. Johnny?
Thanks Kristal, we are targeting this well to be a little over $20 million to $3 million to $3.5 million. But it includes a good bit of learning process and [science]. We don’t think that’s really indicative of going forward, of going forward costs for this particular exercise.
Kristal Choy - Raymond James
Fair enough. And I asked this recently, but I’ll ask again since I was invited. Can you tell us what you’re seeing while drilling the Bone Springs wells, and is there any well data you’re willing to give us at this point?
Kristal I am giving it to Johnny to add a little color to that. We are in process with (Inaudible) I believe. So Johnny go ahead.
Kristal we are currently drilling our third well. Of course, our learning curve is pretty steep. We have participated in many horizontal Bone Springs wells, but we are encouraged by what we are seeing there. And we are improving our drilling times and our drilling process.
Johnny if you would add a little color about well cost and reserves and think that these wells are going to be in the range?
Well what we are targeting now James is currently we are in the range of about $8 million but we believe well we are currently drilling will probably come in about $7 million and we continue to want to drive that cost down. And we are targeting in the area we are drilling now as a rule of thumb about 400,000 barrel equivalent per well.
Kristal when production comes down fairly rapidly so the rates are returning and those costs and reserve recoveries are quite high.
(Operator Instructions). There are no further questions at this time. I’ll turn the call back over to James McManus for any further remarks.
Thank you Mason. With more than 72% of our total estimated 2010 production hedge was above market prices. Energen is well positioned to generate double-digit earnings growth and significant discretionary cash flows. And based on first quarter results things are off to a very good start. Most importantly, our strong balance sheet and those substantial discretionary cash flows are going to give us a lot of flexibility as we move forward to implement our plan and to look at the opportunities that we have to invest this cash flow. Thank you and have a great day.
This concludes today’s conference call you may now disconnect.
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