Devon Energy’s CEO Discusses Q1 2012 Results – Earnings Call Transcript

May 2, 2012 | about: DVN

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Executives

Vincent W. White – Senior Vice President of Investor Relations

John Richels – Chief Executive Officer, President and Director

David A. Hager – Executive Vice President of Exploration & Production

Jeffrey A. Agosta – Chief Financial Officer and Executive Vice President

Darryl G. Smette – Executive Vice President of Marketing & Midstream

Analysts

Jessica Chipman – Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

David W. Kistler – Simmons & Company International, Research Division

Brian Singer – Goldman Sachs Group Inc., Research Division

David R. Tameron – Wells Fargo Securities, LLC, Research Division

Douglas George Blyth Leggate – BofA Merrill Lynch, Research Division

Joseph Patrick Magner – Macquarie Research

Harry Mateer – Barclays Capital, Research Division

Devon Energy (DVN) Q1 2012 Earnings Call May 2, 2012 11:00 AM ET

Operator

Welcome to Devon Energy’s First Quarter 2012 Earnings Conference Call. [Operator Instructions] This call is being recorded. At this time, I’d like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

Vincent W. White

Thank you, operator, and welcome, everybody, to today’s first quarter 2012 earnings call and webcast. Today’s call will follow the usual format. I’ll start with a few preliminary items and then turn the call over to our President and CEO, John Richels for his overview. Then Dave Hager, Head of Exploration and Production, will provide the operations update. And following that, our Chief Financial Officer, Jeff Agosta, will finish up with a review of our financial results. We’ll conclude with a Q&A period, and as usual, we’ll ask you to keep your questions limited to one and one follow-up, and we’ll hold the call to about an hour. Also with us today is Larry Nichols, our Executive Chairman, as well as other members of Devon’s senior management team to help out with the Q&A session.

A replay of this call will be available today later on through a link on our homepage. As usual, our call will contain some forward-looking estimates. And we will be refining some of those in our call today, but we are not planning to issue a new 8-K. We will, however, post those changes to the guidance page of our website. To find that, just click on the Guidance link found in the Investor Relations portion of the Devon website.

Please note that all references today to our plans, forecast, expectations and estimates are forward-looking statements under U.S. securities law. And while we always strive to give you the very best information possible, there are many factors that could cause our actual results to differ from those estimates. We urge you to review the discussion of risk factors and uncertainties that we provide in our SEC Form 10-K filing, provided that is. Also in today’s call, we’ll reference certain non-GAAP performance measures. When we use these measures, we’re required to provide related disclosures. Those are also available on the Devon website.

The First Call mean estimate for Devon’s earnings for the first quarter was $1.43 per share. However, at the midpoint of the guidance we provided, you would’ve expected our first quarter earnings to come in at $1.35 a share or $0.08 below The Street estimates. However, our actual first quarter non-GAAP results came in at $1.05 per share or $0.30 below our guidance. This was most almost entirely due to unusually wide differentials on Canadian oil and U.S. NGLs. Jeff will cover both of these, as well as our expected future price differentials in detail later in the call. With those items out of the way, I’ll turn the call over to John.

John Richels

Thank you, Vince, and good morning, everyone. Although, as Vince mentioned, wide differentials had a significant negative impact on earnings, we delivered another very solid quarter from an operational perspective.

Our North American onshore production reached an all-time record, averaging 694,000 equivalent barrels per day in the first quarter. This represents a 10% increase over the year-ago quarter and that was led by a 26% growth in oil production. On a sequential quarter basis, a 7% increase in oil and NGLs production more than offset a 1% decrease in natural gas production.

We continue to bolster our future oil potential by assembling significant acreage positions in additional new oil plays, and we continue to do a very good job of controlling costs. Pretax costs — or pretax cash costs per unit of production increased only 1% from the last quarter of 2011. And even in an environment of weak commodity prices, we delivered net earnings of $393 million and cash flow of $1.4 billion.

Devon’s financial position remains rock solid. We ended the quarter with the $7.1 billion of cash on hand, and we continue to have one of the lowest debt-to-cap ratios in the industry. This financial strength is especially important given current natural gas prices. The economics of drilling dry gas wells are unattractive, and reduced cash flow from lower pricing makes sustaining investment and higher-margin oil- and liquids-rich gas more difficult for many. Our financial strength allows us to continue to fund a robust E&P capital program directed entirely towards oil- and liquids-rich opportunities. The economics of these projects are enhanced by low royalties, reasonable operating costs and by our midstream operations. In aggregate, our 2012 drilling activity will deliver oil production growth in excess of 20% and double-digit growth in NGLs. And more importantly, the projects driving this growth are delivering very attractive rates of return.

Even if the current pricing environment were to persist indefinitely, our existing base of oil- and liquids-rich projects provides us many years of profitable growth. To put this into perspective, roughly half of our 16.2 billion barrels of risked resource is oil and NGLs, with crude oil accounting for nearly 5 billion barrels of this total resource. So our resource base provides the ability to shift investment to the most lucrative opportunities depending on market conditions.

Our solid financial position is also allowing us to aggressively build up the light oil portion of our inventory. We’ve been very successful in adding significant oil-focused acreage positions at very attractive entry cost. Our biggest addition is our recently unveiled Cline Shale oil play to the 500,000 net acre position that we’ve assembled in the Permian Basin and that was assembled at very reasonable cost. We’re also building a large, concentrated position in another oil prospect that’s not yet ripe for disclosure. As of today, we have commitments for or have closed on 250,000 net acres in this undisclosed position, with an ultimate target of about 500,000 net acres. Our new ventures unit is well-staffed, and it’s adequately funded to continually evaluate greenfield opportunities across North America, as well as to identify untapped potential on our existing acreage base.

As 2012 progresses, you’ll see more of the fruits of these efforts. Due to the significant success that we’re enjoying in identifying and capturing resource potential, we are open to taking on partners to help us develop our new exploration plays. While we could easily pursue these opportunities on our own, bringing in a partner enhances our overall risk-reward profile. As evidenced by our $2.5 billion Sinopec transaction, joint ventures offer the opportunity to accelerate activity, improve capital efficiency and mitigate risk. And most importantly, this type of transaction supports our primary strategic objective of maximizing cash flow per debt adjusted share. The combination of our financial strength, our low-risk development inventory and our growing new ventures portfolio underpin our oil production growth. As a result, in our view, Devon provides a differentiated opportunity for investors in the E&P space. So with that, I’ll turn the call over to Dave Hager for a more detailed review of our operating highlights. Dave?

David A. Hager

Thanks, John, and good morning, everyone. Given the in-depth update we provided just a month ago at our Analyst Day, I’ll keep my comments fairly brief this morning. Let’s begin with a quick recap of first quarter capital expenditures. E&P capital for the first quarter was $1.6 billion, including undeveloped acreage acquisitions. Operationally, we’re off to an outstanding start this year with record production from each of our 4 cornerstone developed product areas: Jackfish, the Permian Basin, the Barnett and Cana. We also continue to move forward with evaluating and derisking the upside potential in our various emerging and new ventures plays.

Now let’s take a closer look at some of the first quarter highlights. Starting with our thermal oil projects in Eastern Alberta, aggregate production from our 2 producing Jackfish projects averaged a record 46,000 barrels per day, net of royalties, in the first quarter. Jackfish 1 accounted for 30,000 barrels per day as its total, and continued its trend of excellent plant reliability and efficiency. At Jackfish 2, production continues to ramp up, and we’re currently producing more than 21,000 barrels per day after royalties. We continue to expect to reach facility capacity at Jackfish 2 somewhere around year end. Jackfish 3 construction is also progressing well, with roughly 30% of the project complete, putting us on track for a late 2014 start-up.

At Pike, we wrapped-up our winter drilling program during the first quarter. We drilled 131 stratigraphic core wells and acquired some 50 square miles of 3D seismic. Although we’re still working with our partner to finalize the Pike 1 development plan, we expect to file an application for regulatory approval for the first phase of Pike late this summer for a project of up to 105,000 barrels per day of production. We operate Pike with a 50% working interest. Between Jackfish and Pike, we expect these projects to drive Devon’s net thermal oil production to more than 150,000 barrels per day by the end of the decade.

Moving now to Permian Basin. Our total net production averaged a record 56,300 barrels of oil equivalent per day in the first quarter, up 28% over the first quarter of 2011. Permian oil production grew 32% over the same period last year, and light oil now accounts for nearly 60% of our total volumes. Our Permian oil play is currently represents some of the highest return opportunities in our portfolio. Since year-end, we have continued to ramp up activity with the addition of 5 new rigs. We currently have a total of 21 operated rigs running in the basin, and expect to add additional rigs by year-end.

Looking at a couple of Permian plays in a bit more detail. First, in the Bone Spring play, we continue to see outstanding results from our Bone Spring horizontal program in both New Mexico and Texas. In the first quarter, we completed 16 Bone Spring wells with an average 30-day IP rates of 580 barrels of oil equivalent per day. Our actual results in this play continue to outperform our analog well model.

In the Wolfcamp Shale in the southern Midland Basin, we’re continuing to fine-tune our drilling and completion techniques. We brought 2 Wolfcamp horizontal wells online in the first quarter, with 30-day average IP rates of 440 barrels of oil equivalent per day. Perhaps even more exciting is the result of a Wolfcamp horizontal well we drilled on our Wolfberry acreage in Ector County. This well is located some 80 miles to the Northwest of the southern Midland Basin, where the Wolfcamp play has been heating up. After 20 days of production, the Everett [ph] 17H is producing about 400 barrels of oil equivalent per day. While additional mapping and drilling is needed to better characterize the resource potential, our well, combined with another recent industry well in the area, suggests the horizontal Wolfcamp Shale play could extend to the Northwest. This would significantly increase our resource potential in the play.

As we mentioned during our recent Analyst Day, there are many uncharacterized zones underlying our Permian acreage, and this is one example. We will keep you updated as we learn more. During our recent Analyst Day presentation, we also unveiled a large position that we have established in the Cline Shale on the Eastern flank of the Midland Basin. We are currently drilling a Cline well in Sterling County, the first of 15 wells we have planned for this year to assess our potential in the play. The depth and breadth of our existing Permian position is driving our Permian production growth rate at a rate of more than 20% per year. In addition, we are continuing to supplement this position by aggressively pursuing new opportunities in the Permian.

Moving now to the Cana-Woodford Shale in Western Oklahoma. In spite of a temporary third-party facility outage that reduced our first quarter production by about 4 million cubic feet equivalent per day, as well as a large increase in uncompleted wells due to pad drilling, Devon still achieved an all-time production record at Cana. First quarter 2012 production increased 67% over the year-ago quarter and 8% over the fourth quarter of 2012. First quarter Cana liquids production grew even more, up 80% over the year-ago quarter, to 3,500 barrels of oil and 9,500 barrels of natural gas liquids per day. Also of note at Cana, we recently finished drilling our first 10,000-foot lateral, and expect to begin a 20-stage completion on this well later this year. We are currently drilling a second long lateral well in Cana. These wells will cost on the order of 20% to 30% more than a typical Cana-Woodford well. However, we expect to see an increase in per-well recoveries in the 60% to 80% range, further enhancing our Cana economics.

Shifting to the Barnett Shale field in North Texas. In the first quarter, we continue to achieve excellent results with pad drilling. We brought 25 wells online from our Lake Benbrook pad, with 30-day average IP rates of 4.9 million equivalent feet of production per day, including 330 barrels per day of natural gas liquids. This helped drive first quarter net production from the Barnett to a record 1.37 Bcf equivalent per day. This included 52,500 barrels of liquids per day, up 23% from first quarter 2011.

Moving north to the Texas Panhandle. In the Granite Wash Play, we continue to see solid results from our Cherokee and Granite Wash wells. We brought 6 operated Granite Wash wells online during the first quarter. The 30-day IP rates from these wells averaged over 1,650 barrels of oil equivalent per day, including 220 barrels of oil and 470 barrels of natural gas liquids per day. On the exploration front, we recently closed a Sinopec JV and continue to move forward with the de-risking of the 5 plays involved. Given the recent in-depth update provided at our Analyst Day, we have very little today in the way of incremental information. However, I will briefly review the current status for each of these opportunities. In the Mississippian oil play, located in North Central Oklahoma where the partnership has assembled 230,000 net acres, we are encouraged with the results of our first well. The Matthews 1H had a 30-day IP rate of 590 oil equivalent barrels per day, and is among the best wells reported in the play to date. We currently have 2 rigs running and 2 wells completing. We expect to drill or participate in roughly 50 wells on this acreage by year-end. It including tests of additional formations.

In our Rockies oil exploration, as we previously indicated, we’re testing a number of objectives in the Powder River and DJ Basins. Our first well in the Turner formation had a 30-day IP rate of 433 barrels of oil equivalent per day. We’re currently drilling wells, testing 2 additional formations, the Mowry in the Powder River Basin, and the Codell in the DJ Basin. In the Tuscaloosa Marine Shale, we drilled our first 2 wells in the southern portion of our acreage position. As discussed during our recent update, results of the first 2 wells were somewhat disappointing. We have since moved our 2 operated rigs north and have 2 wells currently drilling and a third well that is roughly halfway through completion operations. These 3 wells will be the first to test our northern acreage position.

In Michigan, we are currently completing our first horizontal well in the A1 carbonate. We also just finished setting casing on our second well, the Wiley 1H, and we should begin completing that well in a couple of weeks. As we have previously indicated, the A1 is a highly pressurized zone with a significant fracture system, so understanding how these characteristics impact commerciality will be key going forward.

And finally, in Ohio, Utica, we just completed our first horizontal well, the Eichelberger 1H in Ashland County. We are now beginning to flow the well back. In addition, we drilled a second well that’s awaiting completion and are currently drilling our third well in the play. We should have all 3 wells online by the end of the second quarter.

So in summary, our 2012 capital program is off to a great start. With record production in each of our 4 cornerstone development areas, we are poised to deliver outstanding liquids growth. We have a more than 20% growth in oil. We continue to see encouraging results from a number of our exploration plays, as well as efficiently capture new acreage positions that will provide the next leg of oil and liquids growth in the years ahead. With that, I’ll turn the call over to Jeff Agosta for the financial review and outlook. Jeff?

Jeffrey A. Agosta

Thanks, Dave, and good morning, everyone. This morning, I will take you through a brief review of the key drivers that shaped our first quarter results. For today’s call, I will limit my comments to those items that require additional commentary that are outside our forecasted guidance range.

Starting with production. In the first quarter of 2012, our reported production totaled 63.1 million oil equivalent barrels or 694,000 BOE per day. This record result was at the high end of the forecasted range we provided in our fourth quarter call. As John said, this represented 10% growth rate over the first quarter of 2011, driven by a 26% increase in oil production. The Perm

USA TODAY REPORTS great news:

To capitalize on the boom in U.S. oil production, a Canadian company announced Monday that it will split a controversial pipeline rejected by President Obama and start building the Oklahoma-to-Texas portion.

Protesters hold signs opposing the Transcanada Keystone Pipeline on Feb. 17 in Paris, Texas.

Calgary-based TransCanada said the southern half of the $7 billion Keystone XL project will ensure that the glut of oil produced in the upper Midwest gets to Gulf Coast refineries. It said this portion, which won’t need a presidential permit because it does not cross a U.S. border, will cost about $2.3 billion and be completed next year.

“Gulf Coast refineries can then access lower-cost domestic production and avoid paying a premium to foreign oil producers,” Russ Girling, the company’s chief executive officer said in the announcement.

The initial 1,700-mile pipeline, intended to carry a heavy crude known as tar sands from Alberta across seven U.S. states, has become a political issue. Citing rising gas prices and the need to create U.S. jobs, Republicans have criticized Obama for denying a permit last month and siding with environmentalists who say the crude’s development would exacerbate climate change.

Obama said he denied a permit, because a GOP-imposed, 60-day deadline did not give him enough time to decide on the project given the uncertainty over its route through Nebraska. He suggested a route running south from Cushing, Okla., and welcomed TransCanada’s news.

“Moving oil from the Midwest to the world-class, state-of-the-art refineries on the Gulf Coast will modernize our infrastructure, create jobs, and encourage American energy production,” White House spokesman Jay Carney said Monday in a statement. He said Obama’s Jan. 18 decision “in no way prejudged future applications” by TransCanada for the full project.

TransCanada said it will seek a permit for a pipeline from Alberta to Nebraska once it has worked out a route with Nebraska’s legislators to avoid the state’s ecologically sensitive Sandhills region.

Martin Tallett of the EnSys Energy consulting firm, said the southern pipeline could slightly lower gasoline prices by allowing more crude oil onto the international market.

Environmentalists disagree. Susan Casey-Lefkowitz of the Natural Resources Defense Council argues the pipeline — as a whole or as a half — will cause more tar sands to be converted to diesel and exported overseas.

TransCanada spokesman Shawn Howard said the southern pipeline will carry a light crude produced in North Dakota, Montana, Kansas, Oklahoma and Texas. He said it still needs permits from local and state officials, as well as the U.S. Army Corps of Engineers.

Mississippian a Symphony, Not a Solo

By DAVID BROWN, EXPLORER Correspondent

In the mid-continent Mississippi Lime, it’s the same song and a totally new verse – with a challenging geological chorus.

Horizontal drilling has orchestrated a booming new oil and gas play in northern Oklahoma and southern Kansas, keyed to the presence of chert, tripolite, dolomite and vertical fractures.

Operators drilled oil wells in this area for decades, thousands of them, with hit-and-miss success.

Using a combination of horizontal drilling and hydraulic fracturing, they now bring in wells with hundreds of barrels of oil equivalent (Boe) production per day – and per-well estimated ultimate recovery up to 400,000 barrels.

And those wells can cost less than $2.5 million each.

This new play is a tune of rocks and water.

First Notes of Understanding

For a heavily drilled area, the Mid-Continent Mississippian was surprisingly little understood – or even misunderstood.

AAPG member Salvatore Mazzullo, a professor of geology at Wichita State University and a three-time winner of the A.I. Levorsen Award, started a project in 2009 to study the Mississippian Cowley Formation.

“We could figure out the Cowley – we had cores, but we couldn’t figure out where it fit in the Mississippian,” Mazzullo said.

“So we went to the outcrop. The first day, we realized these rocks are exactly like the cores we see in the subsurface. Not just similar, but exactly alike,” he said.

AAPG member Charles Wickstrom is managing member of Spyglass Energy Group in Tulsa, a player in the Mississippi Lime.

“You can take what we see in the outcrops in this tri-state area (of Missouri, Arkansas and Oklahoma) and just take it directly to the subsurface,” he said.

The Tulsa Geological Society sponsored a three-day field trip to study the outcrops in April. Saying industry interest in the Mississippian runs high would be an understatement.

“We had the field trip planned for one bus with 43 people. It sold out within an hour of the announcement,” Wickstrom said, which caused an expansion to accommodate more than 90 people.

In his studies, Mazzullo found that the accepted depositional model for the mid-continent Mississippian didn’t match up with the reality he was seeing.

“We realized these units weren’t doing what they were supposed to be doing in the model,” he said.

For instance, the model says the Mississippian rocks deepen to the south, but they actually shallow to the south because of tectonic activity, he noted.

Recognition and understanding of the unconformities in the Mississippian are essential, Mazzullo said. Some are eustatic, some tectonic.

“If it’s a tectonic unconformity and you’re looking updip for a reservoir, it’s not going to be there” he said.

In Missouri, the Mississippian outcrops can be found to about 40 miles east of Springfield. They extend south past Harrison in Arkansas and to Tahlequah in Oklahoma, Mazzullo said.

From there the characteristic Mid-Continent Mississippian rocks, up to 400 feet in total thickness, extend 300 miles to the west.

“These rocks have been there for a long time, but people haven’t been able to put it all together,” Mazzullo said.

When he looks at the Mississippian rocks, “they’re telling us, we’ve been looking at the wrong things,” he noted. “We’ve been looking at it in the wrong way.”

Complex Structure

Starting with knowledge of the subsurface was key, according to Mazzullo. That allowed close analysis of the outcrops.

He identified three distinct formations in the Osagian Mississippian, with different members and characteristics: the Burlington-Keokuk, Reeds Spring and Pierson.

The Pierson Formation contains reefs and has dolomite updip, presenting two reservoir objectives, Mazzullo said.

The Reeds Spring is a series of prograding wedges and has tripolite at the top, he noted. It also may contain multiple reservoir objectives. The Cowley is a facies of the Reeds Spring.

Care is needed because “it doesn’t suffice to say ‘Reeds Spring.’ You have to identify which wedge,” he observed.

“Our work on the outcrops has defined clear reservoir objectives within the Mississippian. It used to be you just drilled into the Mississippian,” Mazzullo said.

“Everybody went under the mistaken impression, it’s just the Miss. Well, it’s not just the Miss.

“You need to know which particular reservoir section you’re in. And you have to do sample work,” he added.

Going Out

In a series of papers, Mazzullo and co-author and AAPG member Brian Wilhite have tried to refine the nomenclature used for the Mid-Continent Mississippian, right down to the types of rocks present.

They distinguish among:

• Chert, which is SiO2, and readily identified by geologists.
• Tripolite, which is chert of any age that has been highly weathered by meteoric fluids, and is light-weight because of high microporosity formed during subaerial exposure.
• Spiculate, which is fine-grained rock composed of the siliceous spicules of invertebrates.
• Chat, which, according to the authors, is an informal, local term that does not denote any specific lithology. They suggest it not be used.

(Some mid-continent operators, however, refer to the new play as the “Mississippi chat play” and identify tripolitic or weathered chert as chat.)

Defining and identifying these rocks has helped Mazzullo identify the characteristics of different Mississippian formations. The Reeds Springs contains very cherty limestones in which spicules have not yet been found.

Wickstrom said the Mississippian often was logged without noting the distinctions among formations.

“Many well site geologists, when they got to the top of the Mississippian, may or may not have looked at the samples,” he said.

Closely defining those characteristics has helped to identify reservoir objectives, even beyond the most frequently targeted zones.

Mazzullo said the lowermost, Kinderhookian part of the Mississippian includes the Compton-Northview sections. The Compton Lime contains reefs that are locally oil-stained and deserves more study, he noted.

In the area being developed by Spyglass Energy, a productive weathered chert layer of lower porosity exists under the target Reeds Spring zone, Wickstrom said. Horizontal drilling also can open up the potential of that type of secondary target.

“I see this eventually being drilled with mutiple laterals in the Mississippian,” he said.

Unconventional Approach

Shane Matson, Spyglass Energy geologist in Tulsa, said he began searching for possibilities in the Mississippian tripolite chert in 2003.

“We weren’t paying too much attention to the other 250 feet of the formation, mostly because the logs were so confusing,” he said.

A breakthrough came in 2009, when the company obtained its first image logs in the formation, he recalled. Matson and Wickstrom were able to correlate what they saw with outcrops in the Ozarks, and now routinely run image logs on their wells.

This new Mississippian play has been called an application of horizontal drilling and fracking to a conventional reservoir. But Matson said he considers it an unconventional play because the geology is outside conventional boundaries.

“One of the challenges people have in this play is evaluating it on traditional neutron porosity logs. The porosity profile is complex,” he said.

Even the operators drilling successful wells don’t always understand the nature of the formations they’re drilling, Matson noted.

“There are multiple facies people are exploiting and much of the time, probably, they don’t don’t know which facies they are exploiting,” he said.

Wells in the Mississippian play typically produce a lot of water. And that’s something operators don’t mind in this play.

“The more water/fluids you’re getting, the more oil you’re producing,” Wickstrom observed.

Coping with the water does take planning, and Wickstrom said a development project starts with drilling an injection well to the bottom of the Arbuckle. That can handle the water from up to eight development wells, he said.

Today, the long-time Mississippian play in Kansas and Oklahoma is back big time. Exploration that was hit-and-miss is now hit-and-produce.

“The fractures were vertical and it just depended on whether you were lucky enough to get in the fractures,” Wickstrom said. “It’s ideal for a horizontal play.”

For Mid-Continent players, that’s music to their ears.

Peter Hristov reported on in Hot Stocks Jan 4, 2012

Superior Oil and Gas Co. (PINK:SIOR, SIOR message board) has been steaming in the last couple of days as both volume and price surged up on the chart. SIOR was moving in a trading range around $0.008 during most of December. However, at the end of the month and more specifically on Dec. 29 the stock broke the upper border of the range and spiked up in the high volume area. Since then the trading activity with SIOR stock significantly increased. Yesterday, the number of exchanged shares was near 7.3 million which is several times higher than the daily average. The stock price continued rising and at the end of the session SIOR had risen 32% to $0.0199. Trending technical indicators also turned positive after the break out. The MACD shot up and the short term moving averages  bolstered the up move with a bullish cross which was drown on Dec. 27. However, SIOR is a limited information pink sheet company and as such it is not obliged to publish current information. There has been no official publications in the public media to give a clue to the recent development of SIOR stock. In this train of thoughts investors in SIOR stock will have to rely on their intuition for guidance in their investment strategy.

By Tulsa World Staff and Wire Reports

Published: 12/29/2011 2:20 AM

International oil and gas players are diving into the growing Mississippian play of northern Oklahoma and southern Kansas.

Oklahoma City-based Sand Ridge Energy Inc. is selling drilling rights to 363,636 acres in the Mississippian to Spanish company Repsol YPF. SandRidge said it will receive $250 million in cash and $750 million obligated toward drilling development that the company hopes to satisfy in three years.

“We are excited to announce this joint venture with Repsol, a global energy leader, and we are pleased that they share our confidence in the development potential of this vast Mississippian oil play,” SandRidge CEO Tom Ward said in a statement. “We compare the scope of this play to the Bakken and believe it will be transformational for the Mid-Continent region of the United States.”

The joint venture excludes all wells and acreage in the covered area drilled before Jan. 1 and all wells and acreage associated with SandRidge Mississippian Trust I.

The transaction is expected to close in the first quarter, subject to closing conditions.

The Mississippian lime formation has attracted oil and gas explorers to once abandoned fields now made oil-rich properties through horizontal drilling. Sand Ridge helped lead the way, drilling 195 horizontal wells – nearly half of those drilled in the play so far, according to reports.

Tulsa-based Eagle Energy also has extensive holdings in the Mississippian, producing 4,000 barrels of oil equivalent per day as of September. Chesapeake Energy Corp. and Devon and Energy Corp., both based in Oklahoma City, also are investing in the Mississippian region.

“I think it’s probably the hottest play going in the country,” Eagle CEO Steve Antry told the Tulsa World in September.

RAM Resources Inc., a Tulsa-based producer, is exploring wells within a Mississippi chat formation in Osage County. Longtime Houston oilman Floyd Wilson, who is leading a $550 million recapitalization of RAM, wants to focus much of the company’s energies in that formation.

Wildcatters are drawn to the oil-rich mixture in the mature fields of the Mississippian. Some estimate production there at 50 percent to 52 percent oil.

SandRidge will sell Repsol an approximately 25 percent non-operated working interest in its Mississippian extension in western Kansas and a 16 percent non-operated working interest in its original play.

OKLAHOMA CITY, Dec. 22, 2011 /PRNewswire/ — SandRidge Energy, Inc. (“SandRidge”) (NYSE: SD) announced today that it has entered into a Joint Venture (“JV”) with a subsidiary of Repsol YPF, S.A., a leading international energy company based in Madrid, Spain. Under the agreement, SandRidge will sell an approximate 25% non-operated working interest, or 250,000 net acres, in the Extension Mississippian play located in Western Kansas and an approximate 16% non-operated working interest, or 113,636 net acres, in its Original Mississippian play.

The 363,636 net acres in total will be sold to Repsol for an aggregate transaction value of $1 Billion. Repsol will pay $250 million in cash at closing and the remainder in the form of a drilling carry. In addition to paying for its working interest share of development costs, Repsol will pay an amount equal to 200% of its working interest to fund a portion of SandRidge’s cost of development until the additional $750 million drilling carry obligation is satisfied. Based on current drilling expectations, SandRidge anticipates the drilling carry obligation to be satisfied within three years. The JV will exclude all wells and acreage within the associated spacing units spudded prior to January 1, 2012 and all wells and acreage associated with SandRidge Mississippian Trust I. The transaction is expected to close in the first quarter and is subject to certain closing conditions.

Tom Ward, Chairman and CEO, stated, “We are excited to announce this Joint Venture with Repsol, a global energy leader, and we are pleased that they share our confidence in the development potential of this vast Mississippian oil play. We compare the scope of this play to the Bakken and believe it will be transformational for the Mid-Continent region of the United States. SandRidge has led the way in developing the Mississippian Play and has now drilled more than 195 horizontal wells, representing nearly half of all the horizontal wells drilled in the play to date. As a result of the drilling carry and its lower working interest, SandRidge’s 2012 CapEx is expected to decline to $1.6 Billion from a previous budget of $1.8 Billion. This JV with Repsol puts us on a clear path to bridge the 2012 funding gap with non-debt capital and to execute our three year plan to triple EBITDA and double oil production while lowering our debt to EBITDA ratio.

By Wendy Koch, USA TODAY

Looking at your heating bills or gas prices, you may find it surprising that the United States is enjoying a mini oil boom. It’s producing more crude oil and, for the first time in decades, has become a net exporter of petroleum products such as jet fuel, heating oil and gasoline.

The U.S. exported more oil-based fuels than it imported in the first nine months of this year, making it likely that 2011 will be the first time since 1949 that the nation is a net exporter of such goods, primarily diesel.

That’s not all. The U.S. has reversed another decades-long trend. It began producing more crude oil in 2008 than the year before and accelerated that upswing 3% in the first nine months of this year compared with the same period in 2010. That production has helped reduce U.S. imports of crude oil by about 10% since 2006.

“It’s dramatic. It’s transformative,” Edward Morse, a former senior U.S. energy official who now directs global commodities research at Citigroup, says of the historic shifts. He says the U.S. is importing a smaller share — 49% in 2010, down from 60% in 2005 — of the oil it uses, adding: “We’re moving toward energy independence.”

He says the U.S. economy benefits, because its low natural gas prices help make its steel and other manufacturing industries more competitive. He says U.S. consumers benefit with more jobs and gasoline prices that are lower and less volatile than in many countries.

Not all are cheering. The changes are exacting a brutal toll on the nation’s health and environment, says Susan Casey-Lefkowitz of the Natural Resources Defense Council (NRDC), citing the greenhouse gas emissions of producing and refining fossil fuels.

The U.S., the world’s second-largest greenhouse gas emitter after China, produced 4% more carbon dioxide last year than in 2009, when emissions dipped because of the recession, according to the Global Carbon Project, an international group of scientists.

American consumers benefit little from the U.S. oil boomlet, because their fuel prices depend heavily on a global oil market that remains tight and has probably already peaked in production, says Jeremy Rifkin, author of The Third Industrial Revolution: How Lateral Power is Transforming Energy, the Economy and the World.

Perhaps the bigger impact is on American foreign policy. The U.S. oil boomlet has amplified concurrent shifts in the global oil market. Today, half of net U.S. petroleum imports come from the Western Hemisphere, and half of that (or a quarter of the total) comes from Canada. Only 12% came from Saudi Arabia last year, down from nearly 19% in 1993.

“What’s occurring is a rebalancing of the world oil supply,” says Daniel Yergin, energy historian and author of The Quest: Energy, Security, and the Remaking of the Modern World. He says Brazil’s newly produced offshore oil, which he calls “presalt” because it’s beneath a thick layer of salt, will further tip the scales.

“The importance of the Middle East has decreased for us,” says Michael Klare, author of the forthcoming The Race for What’s Left: The Global Scramble for the World’s Last Resources. “That’s a dramatic change in the geopolitical equation.”

Why the U.S. shifts?

What’s driving the boomlet is increased production of two resources that previously weren’t considered economically viable to develop.

“It’s a double-barreled development, pardon the pun,” says Martin Tallett, president of EnSys Energy, a Massachusetts-based oil industry consulting firm. He did a study for the Department of Energy on the proposed $7 billion Keystone pipeline, which would carry oil or tar sands from Canada through six U.S. states to the Gulf Coast.

This heavy crude — a mixture of sand, water, clay and a viscous oil known as bitumen — is found primarily in Canada’s Alberta province. It’s increasingly being exported to the U.S., where it’s refined into petroleum products, many for export. Its production surpassed 1.1 million barrels per day in 2005 and is expected to nearly triple by 2015, according to Canada’s National Energy Board.

The other resource is sometimes called “shale oil” but more accurately “tight oil,” because it comes from shale and other rock formations. (It’s different from “oil shale,” which contains the oil precursor kerogen but remains costly to develop.)

Tight oil, produced mostly from the Bakken shale formation in North Dakota and Montana and the Eagle Ford one in Texas, is extracted in much the same way as natural gas — pumping pressurized water, sand and chemicals underground to fracture the rock and break loose the oil so it can flow to the surface. This process is often called “fracking.”

“It’s the new, new thing,” Yergin, the energy historian, says of tight oil. He says its U.S. production could skyrocket to 2.9 million barrels per day by 2020. North Dakota, which accounts for the vast majority of this oil, produced 488,066 barrels per day in October 2011, up from 90,196 in January 2005, according to the state’s Department of Mineral Resources.

“When shale gas worked, people said, ‘Maybe this works for oil, too,’ ” Yergin says, noting that oil brings a higher return than natural gas. The result? A surge in production within the last two years. Yergin says this has produced needed jobs in an overall weak U.S. economy and, by expanding the global oil supply, has helped prevent or offset price spikes.

Tallett says the U.S. has been able to capitalize on that production because it has a flexible and efficient refinery network.

“We have some of the better refineries in the world — certainly the most complex,” he says, adding they can handle different types of crude oil and shift their product line quickly to meet demand. He says they’ve upped production of diesel fuel, which is in great demand worldwide, and reduced that for gasoline, now in surplus.

Other factors contributing to the U.S. net export of petroleum products is the federally mandated use of ethanol, which has boosted its production and reduced demand for regular gasoline.

Gasoline demand is also down because Americans are driving less. They’ve been driving fewer miles every month since March, according to a USA TODAY analysis of data from the Federal Highway Administration.

Simply put, “The U.S. has been using less and producing more,” says James Hamilton, an economics professor at the University of California-San Diego.

Environmentalists are concerned that the higher production of these unconventional, harder-to-reach oil resources carries increased dangers for air and water quality.

The NRDC’s Casey-Lefkowitz says the development of tar sands produces more greenhouse gas emissions than that of regular crude oil, and if spilled, the heavy crude can be more difficult to clean up because of its viscosity. She says its production has taken off without regard to safety.

“My fear is that the same is happening with tight oil deposits,” she says. “Whenever you fracture shale to get at oil,” she says, “you’re flaring off methane.” The process wastes natural gas and uses huge volumes of water.

On Dec. 8, the U.S. Environmental Protection Agency said fracking might cause groundwater pollution. It said compounds likely associated with fracking chemicals had been detected in the groundwater beneath Pavillion, in central Wyoming.

A temporary boost?

Rifkin says the production of unconventional oil resources may provide a temporary boost, but it won’t last — in the U.S. or worldwide. Citing a 2010 report by the International Energy Agency, a Paris-based organization, he says global peak production of crude oil probably occurred in 2006.

“We’re now in the early stages of a volatile end game,” he says, especially as China and India continue to develop and increase their energy consumption. “There’s no easy way to drill our way out of this.”

Rifkin, author and policy advocate, says the U.S. should move quickly to what he calls the “third industrial revolution,” based on renewable energy, micro power plants and electric vehicles. He says he’s discussed this approach with German Chancellor Angela Merkel, who he says supports it.

Yergin argues there’s no clear limit to the world’s oil resources as innovation has found ways to develop what once was considered undevelopable. Still, with global energy demand increasing and the climate warming, he sees benefits in energy efficiency and renewable energy.

Hamilton, the economics professor, says that the U.S. oil boomlet has reversed a historic decline in production, but that the nation won’t ever go back to producing as much oil as in the 1970s or consuming as little as it did then.

“We’re still importing a huge amount of crude oil,” Hamilton says, and neither he nor the U.S. government expects that will change anytime soon.

“North Dakota’s production, though growing, is still small compared to what we got out of Alaska,” he says. “It doesn’t change the long-term challenges or end the overall U.S. petroleum trade deficit.”

By ROD WALTON World Staff Writer
Published: 12/2/2011 1:41 AM
Last Modified: 12/2/2011 5:23 AM

Steve Antry is chairman and CEO of Tulsa-based Eagle Energy Co. of Oklahoma LLC. Before founding Eagle in 2009, he was founder, chairman and CEO of Beta Oil & Gas Inc. In 2004, Antry helped merge Beta with Houston-based PetroHawk Energy LLC. He holds an MBA with an emphasis in finance from Texas Christian University.

1. Eagle is already one of the bigger players in the Mississippian formation of northern Oklahoma, with more than 75,000 acres in leases. What was so attractive that prompted you to bet big on a relatively new horizontal play in only two years?

I minimized our risk by buying a solid property that was steadily producing from another productive zone. We gradually risked about $5 million in capital to test our thesis in the Mississippian, with the blessing of Riverstone Holdings, our New York-based private equity backers. It was an attractive bet, considering the risk-reward ratio.

We were also able to quickly increase our acreage position by another 50 percent before the word really got out on the magnitude of the Mississippi. We knew exactly what kind of deal we were making on those last 25,000 acres. There was no material risk to bet on those.

2. Tell us a little more about Eagle’s other production efforts. Do you handle drilling operations or contract that out?

We’re the named operator of virtually 100 percent of the properties that we drill and produce oil and gas from. However, we do use subcontractors for related services such as conventional drilling, directional drilling, fracking and well-servicing.

3. Some have called this new domestic drilling effort a “revolution.” Oil and gas history shows plenty of manias that tapped out after a while. How long can the limestone and shale plays hold potential for strong production?

Still early stage, the Mississippi trend is now well established with over 500 horizontal-well data points. Ultimately there will be thousands of additional wells drilled. Eagle alone has 500 more locations already identified. Thus, the potential for strong production for a long time in the Mississippi is undisputable. Everyone that has significant acreage in the core Mississippi trend is in a heavy growth phase right now.

On a grander scale, horizontal drilling and large multistage fracking has clearly opened up a lot of new production around the country in the shales.

In the Mississippi trend, we’re just applying that same technology to carbonate reservoirs (limestones) that have much more permeability (several hundred times more permeability than in a shale). Now that the technology is working so well in Oklahoma, the same technology is being tested in other carbonate reservoirs in other states to potentially open up those areas.

4. Before starting Eagle, you founded and led Beta Oil and Gas, selling that to PetroHawk several years ago. What long-term plans do you have for Eagle?

I’ve mentioned our 500 additional identified locations. They alone would provide for five to 10 years of heavy drilling activity for us. And our well performance continues to improve.

Our backers, Riverstone Holdings, are very supportive of management just continuing to increase the value of the company through the drill bit. And I love our current team. I enjoy going to work every day.

That said, the numbers are attracting large potential buyers.

5. U.S. oil seems to be everywhere again, like it’s 1900 all over again. What are the pitfalls or challenges to new companies wanting to strike it rich?

Oil and gas will always be risky to a certain extent. The risk and reward will always be tied, to a certain degree, to timing and commodity prices and all the other well-known industry risks.

Specific to 2011, I would say the biggest obstacle to new entrants that hasn’t always been present is that for even those with a positive track record, it has become increasingly difficult to attract small amounts of capital.

What’s attracting the big money are the bigger resource plays. There are good smaller quality plays out there, but they’re having a hard time attracting capital.

By ROD WALTON World Staff Writer

In their Q3 2011 conference call, SandRidge Energy’s CEO discusses the Mississippi play, below are some quotes:

“We believe the Mississippian is the most capital-efficient play in the U.S.”

“At the same time, our Mississippian production has performed above our expectations”

“The Mississippian oil production is in line with our type curve, and our natural gas production is better than we anticipated”

You can read the entire transcript to Sandridge Energy’s 3rd Quarter 2011 conference call Here