FormCap acquiring Cowley County prospect in Kansas

FormCap Corp. (OTCQB: FRMC) is making payments to Keta Oil & Gas and Kerr Energy toward the purchase of oil and gas exploration and development leases in Cowley County, Kansas. Formcap will pay Kerr and Keta $200 per acre for up to 2,400 acres of leases, at a cost not to exceed $480,000 (the purchase price) unless agreed otherwise by the company.

Formcap is evaluating a specific block of 875 acres (from the 2,400 acre total) of prospective oil leases to acquire from Kerr and Keta. The company will own 100% of the leases (80% net revenue to FormCap; 20% freehold royalty), and will be operator. FormCap will also have the option to purchase additional leases in Cowley County from Kerr and Keta under an Area of Mutual Interest, the terms of which are set forth in the agreement.

Per the agreement, FormCap is required to drill one well in each of the first two years of the lease term to maintain its interest in the leases, and will have the option to participate in the drilling of up to six exploration or development wells on lands currently owned by Keta and Kerr.

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Mexico hydrocarbon undersecretary vows careful energy regulation, contract transparency

Mexico’s government realizes it’s crucial to establish competitive contract terms and effective, transparent regulations to attract international investors as Mexico implements its pending energy reforms, panelists told a Houston gathering on Feb. 7.

Lourdes Melgar, the new undersecretary of hydrocarbons for the Mexican Ministry of Energy, spoke to a seminar hosted by the University of Texas at Austin and the Atlantic Council in Houston on the day after she was named to her current post. Previously, she was undersecretary of electricity.

On Dec. 21, 2013, Mexico’s sweeping energy reform became law, representing a major overhaul of Mexico’s oil, gas, and electric industries.

Secondary legislation will stipulate contract logistics and tax reforms as Mexico ends the state-owned monopolies of oil company Petroleos Mexicanos (Pemex) and electric company Comision Federal de Electricidad (CFE). Secondary legislation is being drafted and discussed now.

Reforms pending

Having worked on the Mexican government’s energy reform team, Melgar noted that energy reform has been discussed for years in her country. She has held various positions in Mexico’s Foreign Service, including design work on international oil market strategy.

“It’s important to Mexico’s people to make sure we have financial transparency in every contract and bidding round,” Melgar said. Secondary legislation will outline the basics for the types of oil and gas exploration and production contracts, which will be flexible, she said.

Companies outside Pemex are to be allowed to participate in exploration and production activities, breaking the decades-old Pemex monopoly. The reforms also will allow direct private investment in Mexico’s midstream and downstream.

Melgar said Mexico expects to keep service contracts and to add profit-sharing contracts, production-sharing contracts, licenses, as well as enable a combination of various types of contracts. She told OGJ that it’s too early to know any contract specifics, and that contracts will vary widely.

“All hydrocarbons in the subsoil belong to Mexico,” Melgar said, confirming that energy reforms will enable companies outside Pemex to report oil and gas reserves on their accounting statements. “We want secondary laws that support the model the government has developed.”

Deadlines established

Mexico’s Congress has a deadline to approve these secondary laws by the end of April, she said, and the schedule calls for oil and gas bidding rounds to start around June 2015. Contract terms will be drafted carefully “to really attract the type of companies that we need,” in Mexico, she said.

Another speaker on the Feb. 7 Houston panel said Mexico could become a major oil supplier by 2022 if implementation of its energy reforms prove successful.

David Goldwyn, president of Goldwyn Global Strategies LLC and a former US State Department coordinator for international energy affairs, called Mexico’s energy reform “good timing for the rest of the world.”

Long-term opportunities for outside oil and gas companies in Mexico will involve the development of deepwater and unconventional gas plays, he said. For the near term, enhanced oil recovery technology and seismic analysis will be needed, he added.

Peter Schechter, Atlantic Council director of the Adrienne Latin American Center, said Latin America abounds with energy news although he noted, “No energy story in Latin America is more important than the Mexico story.”

US lawmakers in Washington, DC, closely are watching Mexico’s unfolding energy reform, he noted.

“Mexico is going to strengthen a North American energy market,” which means less reliance on Middle Eastern crude oil supplies, Schechter said. He noted that security concerns remain for outside investors.

Melgar acknowledged the security concerns, saying that her government is working to resolve these issues and also working to reassure potential international investors. “Security is an issue in some specific parts of the country,” she said.

"We expect these reforms to result in an increase of 1% to GDP by 2018,” Melgar told reporters in a news conference after the panel discussion. She said she was reluctant to discuss specific amounts yet, adding that Mexico’s economy is not equivalent to the US economy, making comparisons difficult.

Melgar said renewable energy will also be a priority for Mexico in the future.

Mexico seeks to reduce carbon emissions by 20% by 2020 and by 30% by 2050. Mexico also set a goal to reduce its reliance on fossil fuels to 65% by 2024, down from about 85% currently. Melgar noted that Mexico last year established a regime for trading carbon credits.

Separately from the panel discussion, Fitch Ratings issued a statement calling Mexico's energy reform “a long-term positive” for Mexico and Pemex credit quality.

“Fitch does not expect Pemex’s ratings to change due to the energy reform, but the company will benefit from the ability to find partners to share exploration risks and budgetary independence,” said Lucas Aristizabal of Fitch.

Contact Paula Dittrick at paulad@ogjonline.com.

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Itsa Energy acquired by Flow Data ownership group

Itsa Energy has been acquired by the ownership group of Flow Data, strategically positioning Itsa and Flow Data to support expansion of upstream and midstream service and solutions capabilities in the Texas oil and gas market. The alliance enhances both companies' existing abilities to drive service and automation technology as a total solution. 

Itsa Energy supports upstream and midstream automation, corporate systems, and enterprise solutions for oil and gas production and related operations.

Flow Data services and installs its product for upstream automation and control throughout North America. The company currently has operational facilities and field service teams in the Rockies, Williston Basin, Midcontinent, and Appalachian Basin regions. 

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Murphy Oil makes new executive appointments

Murphy Oil Corp. (NYSE:MUR) has made a series of executive appointments, all effective immediately. Walter K. Compton has been promoted to executive vice president and general counsel. Kelli M. Hammock has been promoted to senior vice president of administration. John W. Dumas has been promoted to vice president of corporate insurance. Allan J. Misner has been promoted to vice president of internal audit. K. Todd Montgomery has been elected vice president of corporate planning and services, replacing Tom Mireles who has been promoted within Murphy Exploration & Production Co.

Compton joined the company’s law department in 1988 and was promoted to manager of law and corporate secretary in 1996. He was named vice president of law in 2009. In 2011, he was promoted to senior vice president and took on the role of general counsel. 

Hammock joined Murphy in 1993 as an associate accountant and subsequently received various promotions within the controller's department. In 2004, she was promoted to manager of purchasing and services in the administration department. Hammock was named general manager of administration in 2006 and was promoted to vice president of administration in 2009.

Dumas joined the company in 1988 as manager of corporate insurance. He was promoted to director of corporate insurance in 2005.

Misner joined Murphy in 2007 with over 22 years of experience in internal auditing. He is a certified public accountant, certified internal auditor, and certified information systems auditor.

Montgomery joined Murphy earlier this year and will oversee all corporate strategic planning, procurement, corporate reserves, and oil and gas marketing. He comes to Murphy with 25 years of experience from another major oil company. His experience includes global production and reservoir engineering, with management experience in development and strategic planning.  

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Consol Energy natural gas production up 44 percent in 2013

Consol Energy announced it produced an increase of 1.63 trillion cubic feet of gas equivalent (Tcfe) of reserves to reach 5.731 Tcfe by the end of 2013, up 44 percent year-over-year.

Consol Energy said it invested $679.7 million in extensions and discoveries in 2013. The company claims its drill bit finding and development cost of $0.42 per million cubic feet of gas equivalent (Mcfe) is one of the lowest in the industry. This is the fifth year Consol reported drill bit finding and development costs were lower than $0.50 per Mcfe.

"Much of the increase in reserves, through the category extensions and discoveries, was due to the company's highly successful Marcellus Shale program," Consol Energy said in a statement. "As of December 31, 2013, the Marcellus Shale consisted of 3,373 Bcfe of proved reserves."

Consol Energy said it will invest $1.5 billion in natural gas production in 2014 to meet its growth target of 30 percent and produce between 215 and 235 Bcfe. The company plans to focus these investments in Marcellus and Utica shale projects.

More information on the Marcellus shale and gas shale market can be found on PennEnergy's research area.

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Halliburton announces unconventional resource development partnership

Halliburton (NYSE: HAL) announces the signing of a partnership agreement with Gubkin Russian State University of Oil and Gas for the development of unconventional resources in Russia, including the Bazhenov shale. A signing ceremony took place on January 30 at the university.

As part of the agreement, Halliburton will provide senior technical and management staff to serve on Gubkin's Industry Advisory Boards, as well as provide the foundation material for Gubkin's unconventional curriculum that will become the basis for student and industry training. In addition, Halliburton will work with Gubkin to explore basic applied research opportunities in conventional and unconventional resource development, provide assistance with student projects, and pursue R&D opportunities with Russian industry partners.

According to Brady Murphy, Halliburton’s Senior Vice President of Business Development, “Halliburton is positioned to provide the most recent ideas in unconventional development as well as state-of-the-art research and development solutions for the Bazhenov in Russia.” Speaking at the signing ceremony, university Rector Viktor Martynov noted that "by collaborating with Halliburton, Gubkin will be able to offer students and industry personnel real-world experience in unconventional resource development.”

According to published reports Russia may hold as many as 680 trillion cubic meters of unconventional resources, which include gas from shale, sandstones and coal beds. Konstantin Schilin, Halliburton’s Vice President for Russia, noted that Halliburton, as well as local companies, will require new graduates with the requisite knowledge and training to tackle the challenges of the Bazhenov and other unconventional resources.

Professor Mikhail Silin, university Vice Rector in charge of innovation activity and commercialization of new developments, noted that "by partnering with Halliburton, Gubkin is now in a position to create a collaborative framework to strengthen our educational curriculum and learning environment and to prepare students to contribute more to their employers upon graduation.”

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The Academy Sells Hollywood City Block to Kilroy Realty Corporation

In an off-market transaction, Kilroy Realty Corporation has purchased a four-acre Hollywood parcel from the Academy of Motion Picture Arts and Sciences for $48 million.  Located immediately north of the Academy’s Pickford Center for Motion Picture Study, the full city-block site was originally intended to house the future Academy Museum of Motion Pictures when it was acquired by AMPAS in 2005 for $50 million.

STORY: Bloomberg Philanthropies Commits $53 Million to Save the Oceans

However, in October 2011, the Academy and the Los Angeles Country Museum of Art announced a partnership through which the movie museum would be housed in the Wilshire May Co. building on the LACMA campus.

With the purchase now complete, Kilroy Realty Corporation has announced plans to seek approval and entitlements to develop a creative media mixed-use campus on the site. Plans include more than 450,000 square feet of office space, apartments and retail space with Shimoda Design Group spearheading the design.

STORY: Academy Selling Hollywood Property Once Intended for Museum 

The deal marks another major Hollywood project for Kilroy Realty Corporation, and another move towards the area's ongoing revitalization, which has faced recent setbacks with a newly released California Geological Survey that could indefinitely stall mega projects, such as the Millennium Hollywood towers.

But all of Kilroy Realty's large-scale developments -- including the Columbia Square project as well as the renovation of Sunset Media Center, a 22-story, 322,000-square-foot office complex on Sunset Boulevard just east of Vine -- are far from the earthquake fault lines, says KRC's executive vice president David Simon. "We’re not near any of the study zones. We’re in the area where development can and will happen," he says.

"The Academy site will be different from Columbia Square," says Simon, referencing the 675,000 square-foot mixed use campus located on the former site of CBS Los Angeles' television and radio operation, which began construction last year. "This is going to be more about housing smaller production and post-production companies, whereas Columbia will be more focused on larger headquarter users, entertainment and media technology companies. The Academy site will have very stylish rental units, but at a more accessible price point."

Simon added that KRC will continue AMPAS' "Oscars Outdoors" open-air summer movie screening series until construction begins: "We're currently talking to the Academy about a multitude of ideas to continue the summer film shows, and beyond."

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Baytex to acquire Aurora for $2.6 billion

Baytex Energy Corp., Calgary, has agreed to acquire Aurora Oil & Gas Ltd., Subiaco, Western Australia, for $2.6 billion, providing Baytex with 22,200 net contiguous acres in the Sugarkane field in the Eagle Ford shale of South Texas.

Aurora’s fourth-quarter 2013 gross production was 24,678 boe/d (82% liquids) of predominantly light, high-quality crude oil. The company forecasted this year’s average gross production at 29,000-32,000 boe/d, about a 43% increase from 2013.

Baytex said Sugarkane field has been largely delineated with infrastructure in place, facilitating low-risk future annual production growth. The company added that the assets have future reserves upside potential from well downspacing, improving completion techniques, and new development targets in additional zones.

Following the purchase, Baytex’s 2014 production is expected to reach 85,000 boe/d, comprised of 53% heavy oil, 34% light oil and liquids, and 13% natural gas.

The deal gives Baytex additional proved reserves of 106.7 million boe and proved plus probable reserves of 166.6 million boe.

Baytex in 2012 purchased 100% working interest in 46 sections of undeveloped oil sands leases in the Cold Lake region of northeastern Alberta for $120 million (OGJ Online, Oct. 4, 2012). Provincial authorities had conditionally approved the company’s 1,200 steam-assisted gravity drainage (SAGD) pilot and a 10,000-b/d development that was expected to launch in 2013.

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Baytex to acquire Aurora Oil & Gas, strategic Eagle Ford acreage

Baytex Energy Corp., an oil and gas corporation based in Calgary, Alberta, Canada, has agreed to acquire Aurora Oil & Gas Ltd. for $2.6 billion, providing Baytex with 22,200 net contiguous acres in the Sugarkane field of the Eagle Ford shale play in South Texas. The total consideration to be paid by Baytex is $1.8 billion, plus assumed debt of $744 million, for a total transaction value of $2.6 billion. All amounts are in Canadian dollars.

Aurora’s fourth-quarter 2013 gross production was 24,678 boe/d (82% liquids) of predominantly light, high-quality crude oil. The company forecasted this year’s average gross production at 29,000–32,000 boe/d, about a 43% increase from 2013.

The Sugarkane field has been largely delineated with infrastructure in place, facilitating low-risk future annual production growth. The company noted that the assets have future reserves upside potential from well downspacing, improving completion techniques, and new development targets in additional zones.

Following the purchase, Baytex’s 2014 production is expected to reach 85,000 boe/d, comprising 53% heavy oil, 34% light oil and liquids, and 13% natural gas. The deal gives Baytex additional proved reserves of 106.7 million boe and proved plus probable reserves of 166.6 million boe.

Regarding the acquisition, Baytex President and CEO James Bowzer said, “Baytex will acquire premier acreage in the core of the Eagle Ford, one of the leading shale oil plays in the US. The acquisition will provide our shareholders with exposure to low-risk, repeatable, high-return projects with leading capital efficiencies. This is a highly accretive transaction on a per share basis to reserves, production, and funds from operations. The Eagle Ford play provides not only exposure to light oil, but also to Gulf Coast crude oil markets with established transportation systems. A portion of the produced crude oil benefits from Louisiana Light Sweet based pricing, which currently trades at a premium to WTI.”

In 2012, Baytex purchased 100% working interest in 46 sections of undeveloped oil sands leases in the Cold Lake region of northeastern Alberta, Canada, for $120 million. Provincial authorities had conditionally approved the company’s 1,200 steam-assisted gravity drainage (SAGD) pilot and a 10,000-b/d development that was expected to launch in 2013.

Baytex is engaged in the acquisition, development, and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Williston Basin in the US.

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Woodside closes in on entry to deepwater Leviathan gas project offshore Israel

Offshore staff

PERTH, Australia – Woodside has moved a step close to taking an interest in the giant Leviathan gas field offshore Israel.

The company has agreed to a non-binding memorandum of understanding with operator Noble Energy Mediterranean and partners Delek Drilling, Avner Oil Exploration, and Ratio Oil Exploration (1992).

This could lead to Woodside acquiring 25% of the petroleum licenses containing Leviathan, 349/Rachel, and 350/Amit. Negotiations are expected to be completed by March 27.

Noble estimates the field’s 2C contingent resource at 18.9 tcf (535 bcm) of natural gas and 34.1 MMbbl of condensate. Water depth is around 5,500 ft (1,676 m).

Woodside would operate any LNG development of the field, while Noble Energy would remain upstream operator.

The MoU contemplates supplying gas for Israel’s domestic needs, LNG exports, and supply to neighboring countries. It could involve the following conditional payments:

$850 million upon completion of the transaction under a fully termed agreement$350 million on a final investment decision for an LNG development or payments of up to $350 million on predetermined export project milestones5.75% of Woodside’s wellhead export gas revenue, taking effect after at least 2 tcf (56 bcm) have been exported from the Leviathan field, and capped at $1.3 billionA royalty payment of 2.5% on commercial oil production from the deep prospect in the Mesozoic, following payback of development costs.

These transactions remain subject to execution of a fully termed agreement and regulatory approvals from the Israeli government.

Charles D. Davidson, Noble Energy’s chairman and CEO, said “Woodside…brings extensive global expertise in LNG operations and marketing to the partnership. Their addition to the project will result in substantial added value while also bringing us much closer to when we will be able to sanction Leviathan for development.”

02/07/2014

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Continental Resources announces 2013 record proved oil and gas reserves

Continental Resources, Inc. (NYSE: CLR) (the "Company") today announced record proved reserves and production for 2013, as well as key fourth-quarter 2013 cost metrics and capital expenditures.

"Our teams delivered another excellent year, achieving production and capital expenditure guidance as promised," said Harold G. Hamm, Chairman and Chief Executive Officer. "We accomplished our key 2013 goals across the board – to generate top-tier organic oil production growth; to improve efficiency while reducing drilling and completion costs; and to delineate the lower benches of the Bakken and southern portions of the South Central Oklahoma Oil Province, or SCOOP.

"In spite of abnormal winter weather in December and January that delayed some completions and deliveries, we still achieved our 2013 targets, and our annual guidance is intact for strong growth in 2014, with production increasing in a range of 26% to 32%," Mr. Hamm said.

Proved Reserves Increase 38% Year over Year
The Company reported proved reserves of 1.08 billion barrels of oil equivalent (Boe) at December 31, 2013, an increase of 299 million barrels of oil equivalent (MMBoe) or 38% compared with year-end 2012.[1] Year-end 2013 proved reserves were 87% operated by the Company, 37% proved developed producing (PDP), and 68% crude oil. Continental has grown its proved reserves at a compound annual growth rate of 47% per year since year-end 2008.

In 2013, Continental's PDP reserves for the first time exceeded 400 MMBoe. PDP reserves increased 31% from year-end 2012 to 405 MMBoe at December 31, 2013. The Company had 2,330 gross (1,302 net) proved undeveloped (PUD) locations at year-end 2013. The Bakken accounted for 84% of PUD locations at year end.

Continental's year-end 2013 proved reserves had a net present value discounted at 10% (PV-10) of $20.2 billion, a 52% increase over the PV-10 of $13.3 billion for year-end 2012 proved reserves.

The strong increase in 2013 proved reserves reflected significant production growth in the Bakken play of North Dakota and Montana. Continental pioneered development of the upper Three Forks in 2008, and in the past year has led in the exploration of the lower benches of the Three Forks, in addition to leading the way with pilot down-space testing across the basin. The Bakken accounted for 741 MMBoe of Continental's 2013 proved reserves, with a PV-10 value of $14.5 billion.

Continental's 2013 proved reserves were also augmented by accelerated production in the SCOOP, an oil- and liquids-rich play in Oklahoma. SCOOP accounted for 215 MMBoe of 2013 proved reserves, a 241% increase over proved reserves of 63 MMBoe at year-end 2012. The PV-10 value of the Company's SCOOP proved reserves was $3.3 billion as of December 31, 2013.

"We ramped up our SCOOP rig count early in 2013 and delivered strong results in a capital-efficient manner within our budget for the year," said W. F. "Rick" Bott, President and Chief Operating Officer.

Continental holds the dominant leasehold positions in the Bakken and SCOOP, with 1.2 million net acres in the Bakken and 403,000 net acres in SCOOP as of December 31, 2013. The Company also has the industry's most active drilling program in each play.

Production Grows 39% Year-Over-Year Within Capital Budget
Estimated total production was 49.6 MMBoe for 2013, an increase of 39% compared to 2012. Crude oil accounted for 71% of total production, or 35.0 MMBo, in 2013. Estimated natural gas production for the year was 87.7 billion cubic feet.

Capital expenditures excluding acquisitions for 2013 were just under the budget of $3.6 billion, which included $3.1 billion for drilling and completion operations. Acquisition capital expenditures were $270 million for 2013.

Fourth Quarter Production and Expenses
The Company announced production of 13.3 MMBoe for the fourth quarter of 2013, a year-over-year increase of 35% compared with the fourth quarter of 2012. Fourth quarter 2013 average production was 144,250 Boe per day, representing a 2% increase over the third quarter of 2013. The Company reached a new production milestone of 150,000 Boe per day during November, prior to experiencing winter weather delays. Continental has recently regained the 150,000 Boe per day production level.

"We had a great 2013," Mr. Bott said. "Weather affected the fourth quarter, but the timing of production gains also reflects our continued shift to large, multi-well drilling pads. This is a key driver of future efficiency gains and production growth.

"Such strong execution continues to underpin our confidence in achieving Continental's five-year plan to triple production and proved reserves," he said.

Continental began 2014 with an inventory of more than 100 gross wells that have been drilled, but are not yet producing, almost all of which are associated with multi-well pads.

Fourth quarter 2013 oil differential (discount to WTI crude and inclusive of all transportation) is expected to be approximately $13 per barrel, about twice as high as the average for the first nine months of the year. Full-year 2013 differential is expected to be approximately $8.25 per barrel, compared with annual guidance range of $6 to $8 per barrel.

Lower volumes due to winter weather delays and the Company's mix of wells in the fourth quarter of 2013 also impacted production expense per Boe and depreciation, depletion and amortization (DD&A) per Boe. Production expense for the fourth quarter of 2013 is expected to be approximately $0.90 above the third quarter 2013 level of $5.17 per Boe. DD&A for the fourth quarter of 2013 is expected to be approximately $1.50 above the third quarter 2013 level of $18.87 per Boe. For 2013 as a whole, the Company expects both production expense per Boe and DD&A per Boe to be within annual guidance.

The Company reaffirmed its 2014 guidance as announced in its third quarter earnings release on November 6, 2013.

Fourth Quarter and Full-Year Earnings Announcement and Conference Call
Continental plans to announce fourth quarter and full-year 2013 earnings on Wednesday, February 26, 2014, following the close of trading on the New York Stock Exchange. The company plans to host a conference call to discuss earnings results on Thursday, February 27, 2014, at 11 a.m. ET (10 a.m. CT). Those wishing to listen to the conference call may do so via the Company's website at www.CLR.com or by phone:
Time and date: 11 a.m. ET, Thursday, February 27, 2014
Dial in: 800 708 4539
Intl. dial in: 847 619 6396
Pass code: 36590660

A replay of the call will be available for 30 days on the Company's website or by dialing:
Replay number: 888 843 7419
Intl. replay 630 652 3042
Pass code: 36590660

Continental plans to publish a fourth quarter and full-year 2013 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on February 27, 2014.

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