Thursday, 31 July 2014

Quantum Awarded follow on $1.0 Million Contract for Natural Gas Storage and Fuel System Development - 31/07/2014


Quantum Awarded follow on $1.0 Million Contract for Natural Gas Storage and Fuel System Development



Development work continues to move ZHRO's Heavy Duty after-market engine conversion program closer to commercialization with use of Quantum's innovative natural gas storage module, delivery system and control software 

LAKE FOREST, Calif., July 30, 2014 /PRNewswire/ -- Quantum Fuel Systems Technologies Worldwide, Inc. (NASDAQ:  QTWW), a global leader in natural gas storage systems, integration and vehicle system technologies, today announced that it recently was awarded a follow on $1.0 million software development contract by ZHRO™ Solutions LLC, based in Chandler, Arizona under a strategic development program.  The new contract, which is in addition to the $6.0 million in development contracts previously awarded to Quantum by ZHRO, is for Quantum to advance the fuel system control software and oversee the development and integration of the engine control software system.

Under the development program, Quantum and ZHRO will develop a cost-effective, complete natural gas aftermarket system solution for the nation's estimated 4 million medium and heavy duty trucks currently running on more expensive diesel fuel.  Quantum is developing fully-integrated compressed natural gas storage and fuel delivery systems for cost-effective aftermarket conversion of heavy duty diesel fleets to run on natural gas.

The fuel system module being developed by Quantum includes its industry-leading high capacity ultra-lightweight Q-Lite® natural gas fuel storage tank and system, the integration of all the fuel delivery components, and the control software to operate the fuel system.  As part of the contract with ZHRO, Quantum is overseeing the development of the engine control software in order to operate the engine efficiently with ZHRO's innovative fuel injection system.

ZHRO has developed an operating and marketing model to accelerate the commercial launch of their breakthrough technology and has already contracted with a significant number of North American distributors for sales and installation of ZHRO's fuel injector/engine conversion system.

"We not only continue to advance our relationship with ZHRO solutions but also the development and commercialization of the complete system solution," said Brian Olson, President and CEO of Quantum. "These advancements are leveraging Quantum's extensive experience and successes in providing vehicle level integration, validation and production of advanced natural gas fuel system and storage solutions."

"Our continued focus is to provide a unique conversion solution to our end users and we are pleased that the relationship with Quantum continues to provide us movement toward successful implementation of that strategy," said John Madrigal, COO of ZHRO. 

http://www.qtww.com/

TGS continues to build backlog with three new multi-client surveys - 31/07/2014

TGS continues to build backlog with three new multi-client surveys

AKSER (31 July 2014) - TGS announces three new multi-client surveys; a 3D survey offshore Australia, a 2D survey offshore New Zealand and a 3D survey in the West of Shetland region.
Nerites Season 2 is the largest 3D survey TGS has acquired to date in the Asia Pacific region and will cover 13,000 km2 in the Great Australian Bight. The project represents the second season of the Nerites 3D seismic program commitment over blocks EPP44 and EPP45, which are mainly located in the Bight's deep water Ceduna Sub-basin.  Upon completion of this survey, the TGS total portfolio of 3D multi-client coverage offshore Australia will exceed 43,000 km2. Data acquisition is expected to commence in Q4 2014 or Q1 2015 and will be acquired by Dolphin Geophysical.  Data processing will be performed by TGS using its proven proprietary broadband technology, Clari-FiTM, and final data will be available to clients in Q2 2016.
In the same Asia Pacific region, TGS has commenced the regulatory approval process to undertake a 17,000 km 2D multi-client survey within the Reinga, Northland and Taranaki basins, offshore Northwest New Zealand. Subject to regulatory approvals, the survey is proposed to commence Q4 2014 and run to Q2 2015. Data will be acquired by the M/V Aquila Explorer and data processing will be performed by TGS. 
TGS will finalize the 2014 European acquisition season with a new 3D survey West of Shetland covering 900 km2. This survey will tie into TGS' existing 3D library in the region, bringing the total volume of recent TGS 3D data in the area to more than 18,400 km2.  The seismic data will be acquired by the M/V Naila towing 12 streamers at 6,000 m cable length. Data processing will be performed by TGS using its proven proprietary broadband technology, Clari-FiTM, and final data will be available to clients in Q2 2015.
"Our backlog continues to be near an all-time high level and we are pleased to see customer commitments supporting our continued growth. The new surveys announced today confirm our strong position among key clients in hydrocarbon-rich regions with great future potential"  TGS' CEO Robert Hobbs stated.
http://www.tgs.com/

Rosneft and North Atlantic Drilling expand offshore partnership - 31/07/2014

Rosneft and North Atlantic Drilling expand offshore partnership

Rosneft and North Atlantic Drilling Ltd. have entered into long-term offshore drilling contracts. The transaction contemplates employment of six offshore drilling rigs until 2022 with the purpose of carrying out Rosneft offshore projects, including harsh environment.
After the signing, Igor Sechin stated: "Entering into long-term offshore drilling agreements will allow Rosneft to ensure implementation of exploration and development of its harsh environment offshore license areas."
Alf Ragnar Lovdal, Chief Executive Officer of NADL says in a comment, "We are very pleased with the execution of these contracts, which is in line with the timetable agreed earlier this year. Our partner Rosneft has shown remarkable cooperation at every stage throughout this process. This milestone is testament to the ability of both NADL and Rosneft’s employees and we hope that further transactions can be concluded in a similar manner.”
http://www.rosneft.com/

Tangiers Petroleum Limited TRADING HALT

Tangiers Petroleum LimitedTRADING HALT

The securities of Tangiers Petroleum Limited (the “Company”) will be placed in Trading Halt Session State at the request of the Company, pending the release of an announcement by the Company. Unless ASX decides otherwise, the securities will remain in Trading Halt Session State until the earlier of the commencement of normal trading on Monday, 4 August 2014 or when the announcement is released to the market.
Security Code: TPT
Jill Hewitt
Senior Adviser, Listings Compliance (Perth)

Dear Deanna
REQUEST FOR TRADING HALT
Tangiers Petroleum Limited (the “Company”) requests that the securities of the Company be 
placed in a trading halt as follows:
1. The trading halt has been requested pending an announcement by the Company in 
relation to the results from the TAO-1 exploration well;
2. The trading halt should be until the release of the announcement by the Company, 
expected to be no later than market open Monday 4 August 2014; and 
3. The Company is not aware of any reason why the trading halt should not be granted.
Yours faithfully
Robert Dalton
Company Secretary

Tangiers Petroleum Ltd

http://www.tangierspetroleum.com.au/

Year-over-year oil production up more than 30% and averages nearly 50,000 BOPD in 2Q14 - 31/07/2014

Year-over-year oil production up more than 30% and averages nearly 50,000 BOPD in 2Q14

THE WOODLANDS, Texas, July 29, 2014 /PRNewswire/ -- Newfield Exploration Company (NYSE: NFX) today reported its unaudited second quarter 2014 financial results and provided an update on its operations. Recent operational highlights are detailed in the Company's @NFX publication, located on its website. Newfield will host a conference call at 10 a.m. CDT, July 30, 2014. To listen to the call, visit Newfield's website at http://www.newfield.com. To participate in the call, dial 913-312-1462.

With the recent sale of Newfield's Malaysia business and the process underway to divest its China business, the financial and operating results for the Company's international businesses are reported as "discontinued operations."

For the second quarter of 2014, Newfield reported a consolidated net loss of $22 million, or $0.16 per share. Net income would have been $59 million, or $0.43 per share, excluding an unrealized loss on commodity derivatives of $127 million ($82 million after-tax), or $0.59 per share.

Second quarter consolidated net cash provided by operating activities before changes in operating assets and liabilities was $336 million. See "Explanation and Reconciliation of Non-GAAP Financial Measures" found after the financial statements in this release.

Newfield's net production from continuing operations in the second quarter of 2014 was 12.1 MMBOE, exceeding the mid-point of quarterly guidance by approximately 1.1 MMBOE. Net liftings from discontinued operations totaled approximately 0.04 MMBOE. Domestic liquids production in the second quarter was up 13% compared to the first quarter of 2014 and 40% over the comparable period in 2013. Liquids comprised approximately 55% of total second quarter domestic production.

Operational Highlights
For complete highlights and a summary of wells completed in the second quarter of 2014, see the Company's @NFX publication located on its website. Newfield published a detailed update on its Uinta Basin oil developments, including results from recent SXL wells in the Central Basin.

Uinta Basin
Uinta Basin second quarter net production averaged 26,100 BOEPD, up 5% from an average of 24,900 BOEPD in the first quarter of 2014. Based on strong well performance, primarily from the Central Basin, Newfield nearly doubled its beginning of the year guidance for the basin and now expects Uinta production to grow about 10% year-over-year.

Planned 2014 capital investments of $400 million are focused on two areas – the waterflood development of the Greater Monument Butte Unit (GMBU) and recent drilling in high-potential, horizontal plays in the adjacent Central Basin.

Newfield released results on its five most recent SXL wells completed in the Central Basin's Uteland Butte and Wasatch plays. The table below details the highlights. Complete well data is available in today's @NFX publication. 
Well Type
# Wells
Avg. BOEPD
Gross IP
(24-Hours)
Avg. BOEPD
Gross
30-Day Rate
Avg. BOEPD
Gross
60-Day Rate
Avg. BOEPD
Gross
90-Day Rate
Uteland Butte SXL (1)
3
2,157
1,532
1,323
1,154
Wasatch SXL (2)
2
2,068
1,428
1,479
1,583
Central Basin Avg. SXL (3) (4)
5
2,122
1,480
1,401
1,297
(1) 30-day, 60-day and 90-day rates include 2 wells
(2) 60-day and 90-day rates include 1 well
(3) 30-day rate includes 4 wells
(4) 60-day and 90-day rates include 3 wells

Early production data from recent SXL wells is supportive of the Company's original average type curves for the Uteland Butte and Wasatch plays. Oil cuts for the new wells are averaging about 90% after the first 90 days of production. Newfield expects to drill 15 – 20 SXLs in the Central Basin in 2014.

Consistent with the Company's other SXL programs (Eagle Ford, Williston, Anadarko Basin), Newfield is demonstrating the economic benefits of drilling and completing longer laterals. A recent "best-in-class" Uteland Butte SXL well was drilled and completed for approximately $11.6 million gross.

Anadarko Basin
The Company's second quarter 2014 production from the Anadarko Basin increased more than 30% over the first quarter of 2014 and is expected to more than double year-over-year. Newfield's second quarter net production in the Anadarko Basin averaged 39,000 BOEPD compared to 29,500 BOEPD in first quarter of 2014. The Anadarko Basin is Newfield's largest investment region in 2014 (more than $750 million), constituting approximately 45% of planned total investments.

The Company is planning to drill about 70 wells in the SCOOP and STACK plays and exit 2014 with net production of nearly 50,000 BOEPD.

The SCOOP and STACK plays offer multiple "stacked" geologic horizons for exploitation. The Company continues to add to its acreage position in the Anadarko Basin and has leased an additional 25,000 net acres year-to-date. Newfield today has more than 250,000 net acres in the Anadarko Basin.

The "Yandell" development, located in SCOOP Wet Gas, recently commenced production from five XL wells (lateral length 4,950').  The wells had an individual average 24-hour initial production of approximately 1,300 BOEPD gross, of which 41% was oil.  

Newfield's 2014 production estimate for the Anadarko Basin is now 14.8 MMBOE, up from its beginning of the year guidance of 14.3 MMBOE. Through the end of the second quarter of 2014, the Company "made up" for its beginning of the year shortfall in sales related to mid-stream infrastructure expansions and has increased its second half 2014 guidance.

Williston Basin
Williston Basin net production in the second quarter of 2014 averaged 18,100 BOEPD, up 21% over its first quarter 2014 average of 14,900 BOEPD. Year-over-year production in the Williston Basin has increased more than 50%. Based on the strength of well performance and field-level execution, Newfield increased its 2014 Williston Basin growth outlook by an additional 4%. The Company expects its 2014 volumes in the Williston Basin to increase 41% over 2013 levels.

Newfield continues to see drilling efficiencies through execution of its SXL development campaign in the Williston. Year-to-date, SXL well (10,000' lateral lengths) costs are averaging $7.9 million, including about $0.8 million in artificial lift and facilities. Recent wells are being drilled in under 20 days and the Company expects these efficiencies will allow for the drilling of about eight additional wells in 2014. With its continued four-rig program, Newfield now expects to drill more than 55 wells in 2014.

Eagle Ford
Eagle Ford net production in the second quarter of 2014 averaged 12,300 BOEPD, up approximately 12% from its first quarter 2014 average. The Company is running a single-rig program to develop its West Asherton field and Fashing area. Production is expected to grow approximately 39% year-over-year. Newfield expects to drill about 20 wells during 2014.

http://www.newfield.com/

Tullow Oil plc 2014 Half-yearly results - 31/07/2014

2014 Half-yearly results

Strong revenues and cashflow; results in line with market expectations
Balance sheet strengthened through bond issue and re-financing
Exploration successes in Kenya, Gabon and Norway
Major developments in West and East Africa progressing well
Tullow Oil plc (Tullow), the independent oil and gas exploration and production group, announces its half-yearly results for the six months ended 30 June 2014.

2014 Half-yearly Results Highlights

  • Revenues and gross profit for the period in line with expectations; exploration write-offs and a loss relating to the Uganda farm-down result in a loss after tax; interim dividend remains unchanged at 4p
  • Balance sheet well funded following second $650 million bond offer and $750 million re-financing of corporate revolving credit facility; net debt and unutilised debt capacity at period end of $2.8 billion and $2.3 billion respectively
  • West African oil production averaged 63,900 boepd in the first half; strong underlying performance from core assets offset by non-booking of c.3,000 boepd due to ongoing licence negotiations in Gabon. Full year guidance for the region remains 64-68,000 boepd. In Ghana, the Jubilee field is on target to average full year gross production of 100,000 bopd
  • European gas production averaged 14,500 boepd in the first half, below expectations due to underperformance at Schooner-11. Full year guidance for the region revised to 13-14,000 boepd. Sale agreed for Schooner and Ketch in the UK Southern North Sea to Faroe Petroleum (U.K.) Limited for a total consideration of $75.6 million
  • Good progress in major West and East Africa developments; TEN project in Ghana 30% complete, on budget and on track for First Oil in mid-2016; important MoU signed with Government of Uganda; Government of Kenya and the Partners are aligned in their ambition to reach project FID for development by the end of 2015/early 2016
  • Exploration in Kenya continues with wildcat successes at Amosing-1 and Ewoi-1 supporting the Pmean discovered resource estimate of 600 mmbo; E&A campaign continues in the second half and into 2015 with basin and play testing campaigns in Kenya, Norway, Suriname and Gabon

Commenting today, Aidan Heavey, Chief Executive, said

“In the first half of 2014, Tullow made further important discoveries in Kenya and Norway and we have a concentrated exploration campaign planned for the next 18 months. We have also made good progress with the TEN project in Ghana, with our discussions with host governments on our developments in East Africa and with our financing. With strong revenues and cash-flow from our existing production and a well funded and diverse balance sheet, Tullow is well placed for the remainder of this year and into 2015.”
http://www.tullowoil.com/

Wednesday, 30 July 2014

Frost & Sullivan: High Equipment Prices Drive Energy Firms to Adopt Onshore Oilfield Equipment Rental Services in Australia - 30/07/2014

Frost & Sullivan: High Equipment Prices Drive Energy Firms to Adopt Onshore Oilfield Equipment Rental Services in Australia

Sydney, - 30 July, 2014 - The coal seam gas (CSG) boom and the construction of three liquefied natural gas (LNG) pipelines in the vicinity of Queensland, New South Wales and South Australia are spurring the demand for onshore oilfield equipment such as rigs and tools in Australia. Since the cost of purchasing and maintaining such equipment is extremely high, energy companies are turning to rental equipment providers that deliver end-to-end services.
New analysis from Frost & Sullivan, Oil and Gas Onshore Oilfield Equipment Rental Market—Australia, finds that the market earned revenues of $48.7 million in 2013 and estimates this to reach $79.1 million in 2020.
"Queensland and Western Australia will be key markets in the long term, driven by the growing need to ramp up CSG-LNG production capacity," said Frost & Sullivan Energy and Environment, Research Analyst Izwan Rasul. "With Western Australia estimated to hold 280 trillion cubic feet of shale and natural gas in the Canning and Perth Basins, the future for oilfield equipment rental providers remains bright."
While potential is immense, strict standards to decrease the environmental and the social impact of fracking are slowing down the pace of equipment adoption. The risk of water contamination while drilling CSG reservoirs too has raised significant environment and health concerns in the country. In addition, the increased construction cost for LNG expansion may result in project delays or cancellations, affecting oilfield equipment rentals.
To sustain business in an increasingly competitive market, where drilling services companies are also expanding into the equipment rental business, rental firms must ensure reliable services. Oilfield equipment rental enterprises must further improve their logistics advantage to cater to customers that expect immediate equipment ship-out to remote areas with minimal lead time.
"Providing a one-stop solution that includes service and repair facilities will help deliver a strong proposition to prospective customers preference in  sourcing from suppliers with a wide range of equipment types and services," suggested Izwan . "Offering additional engineering services, such as the structural analysis of wells as well of  torque  and drag analysis for downhole tools, will add to rental companie’s competitive advantage in the Australian market."
http://www.frost.com/

Saipem awarded new drilling contracts worth $850 million - 30/07/2014

Saipem awarded new drilling contracts worth $850 million

San Donato Milanese (Milan), 29 July 2014 – Saipem has been awarded new drilling contracts in Indonesia, Nigeria, the Arabian Gulf and Latin America worth approximately $850 million of which $540 million are related to offshore activity and refer to four different units of Saipem’s fleet.

Saipem has signed with Eni Muara Bakau B.V. a contract for the utilization of the Scarabeo 7 which will be operating offshore Indonesia drilling a minimum of 12 wells; the project is estimated to be completed in first quarter 2017. The vessel will remain under contract with Eni until February 2018. Scarabeo 7 is a fifth generation semi-submersible drilling rig, capable of operating in water depths of up to 5,000 feet.

Furthermore, in West Africa the contract for the Scarabeo 3 has been extended to March 2015. Scarabeo 3 is a second generation semi-submersible drilling rig, with capacity to operate in water depths of up to 1,500 feet.

In addition, NDC has extended the contract for the jack-up rig Perro Negro 2 for 24 months, starting from January 2015, for activities in the Arabian Gulf. In Ecuador, EP Petroamazonas has extended by 10 months the charter of the jack-up rig Ocean Spur, operated (not owned) by Saipem until the end of the first quarter of 2015. Both these jack-up are rigs capable to operate in water depths of up to 300 feet.

In relation to onshore drilling, Saipem has been awarded by different clients new contracts worth approximately $310 million, relating to 31 drilling rigs in South America: 21 in Venezuela, 7 in Peru, 2 in Colombia and one in Ecuador. The contracts have been signed under different terms, varying from three months to two years, and starting at different times during 2014.

http://www.saipem.com/

SAIPEM: Board of Directors approves Six-Month Report at June 30, 2014 - 30/07/2014

SAIPEM: Board of Directors approves Six-Month Report at June 30, 2014


San Donato Milanese, July 29, 2014 - The Board of Directors of Saipem S.p.A. today reviewed Saipem’s consolidated Six-Month Report at June 30, 2014, which has been prepared in compliance with the International Accounting Standard IAS 34 “Interim Financial Reporting” and is subject to a limited audit (near completion). The report is subject to review by the Company’s Statutory Auditors and Independent Auditors.

Second quarter 2014 [1]
  • Revenues: €3,075 million
  • EBIT: €166 million
  • Net profit: €75 million 
First half 2014 [1]
  • Revenues: €5,966  million
  • EBIT: €293 million
  • Net profit: €136 million 
  • Investments: €329 million (€490 million in the first half 2013)
  • Net debt: €5,104 million (€4,760 million at December 31, 2013)
  • New contracts: €13,132 million (€6,704 million in the first half 2013)
  • Backlog: €24,215 million at June 30, 2014 (€17,065 million at December 31, 2013 [2]) 
Guidance 2014
  • Revenues: approximately €13 billion
  • EBIT between €600 and €700 million
  • Net profit between €280 and €330 million
  • Capex: approximately €750 million
  • Net debt between €4.2 and €4.5 billion
Umberto Vergine, Saipem CEO, commented:
“The strong start we made in the first quarter, in terms of winning new business in line with our strict commercial criteria, accelerated even further with a record €9.2 billion of new awards during the second quarter.
Saipem continues to be committed and is making progress in the execution and negotiation of legacy contracts. This remains our highest priority, as we work to strengthen our balance sheet and reduce our debt levels. The task of restoring Saipem to full health is not yet complete, but the components for a recovery are in place as we work towards realizing the Company’s potential in the medium term”.

[1] Following the introduction of the IFRS10 and IFRS11 accounting principles, the rules for consolidating investments within the shareholdings of the Saipem Group have been redefined. In particular, IFRS11 requires that investments in Joint Venture with effect from January 1, 2014 are accounted for using the Net Equity method; previously these shareholdings were consolidated using the proportional method. The Group's operating data are presented according to the new consolidation rules, while data pertaining to previous periods have been restated for comparison purposes.  For details, please refer to the section “Effects of the application of IFRS 11and IAS 8.42: Financial Statements”.
[2] The €449 million variation versus the previously announced €17,514 million at December 31, 2013 pertains to the deconsolidation of joint-venture contracts:  €127 million in the Offshore E&C sector and €322 million in the Onshore E&C sector.

http://www.saipem.com/

Rosneft and PDVSA Signed a Range of Agreements on Offshore Projects and Drilling Technologies - 30/07/2014

Rosneft and PDVSA Signed a Range of Agreements on Offshore Projects and Drilling Technologies

Rosneft President and Chairman of the Management Board Igor Sechin and Venezuelan Minister of Petroleum and Mining and PDVSA President Rafael Ramirez signed a Cooperation Agreement to implement offshore projects in Rio-Caribe and Mejillones blocks (Phase II of the Mariscal Sucre Project).
As part of the document, the parties express their interest to continue negotiations with the goal of reaching an agreement on key technical requirements, commercial and legal terms for the potential establishing of joint ventures to develop Rio-Caribe and Mejillones blocks in accordance with legislation of Venezuela. The parties also held negotiations on LNG plant construction.
The parties also agreed to set up a joint venture to engage in the activities in relation to well drilling, re-completion and well infrastructure development, as well as to provide any services related to the procurement of equipment, devices, materials and services within Rosneft / PDVSA joint projects.
In the course of their negotiations, Rosneft and PDVSA agreed to extend the Petrovictoria JV Establishment and Operation Agreement with the purpose of prolonging the Carabobo-2 project entry bonus agreement.
Igor Sechin said at the document signing ceremony: “Today we signed a series of agreements. I am pleased to note that our collaboration continues. To highlight, today we reached an agreement on setting up a service company for servicing production projects and promoting advanced technologies. Our agreement to set up a construction JV is equally important. Our cooperation is substantial and natural. The 8 million barrels a day we produce is a material production level. This underpins the energy security of several countries. We are set to develop our cooperation. We are now working on a number of new agreements and I am confident we will come to terms. The bonus agreement will allow us to pay $440 million which will serve to strengthen the Venezuelan economy”.
http://www.rosneft.com/

API publishes new industry standard for subsea capping stacks - 30/07/2014

API publishes new industry standard for subsea capping stacks

The American Petroleum Institute today published new guidelines for the design, manufacture and use of subsea capping stacks, equipment designed as part of industry’s emergency preparedness in the event of a spill at a wellhead on the ocean floor. 

“Enhanced industry standards are an essential piece of our collaboration with regulators to make offshore oil and gas development safer than ever before,” said API Director of Standards David Miller. “These guidelines will further strengthen subsea spill response capabilities as part of industry’s commitment to continuous improvement in safety.”

API’s Recommended Practice for Subsea Capping Stacks, known as RP 17W, applies to the installation of new subsea capping stacks and can serve as a guide to improving existing equipment. It can aid during the design and manufacturing process and in developing instructions for preservation, transportation, maintenance, testing and operations. 

The document also provides guidelines for the deployment, well shut-in and recovery of a subsea capping stack. 

RP 17W is an industry response to the post-Macondo joint industry task force (JITF) recommendations to enhance subsea well control and containment. This JITF and others focused on equipment, operating practices and spill response were essential elements of industry’s comprehensive effort to examine every aspect of its offshore safety systems. 

Other new or revised API standards responding to the recommendations of the JITFs include: 

  • Standard 65-2, Isolating Potential Flow Zones During Well Construction
  • Standard 53, Blowout Prevention Equipment Systems for Drilling Wells
  • Recommended Practice 96, Deepwater Well Design and Construction
  • Recommended Practice 98, Selection of Personal Protective Equipment
  • Recommended Practice 17H, Remotely Operated Tools and Interfaces on Subsea Production Systems
  • Bulletin 97, Well Construction Interface Document Guidelines
API first began publishing standards in 1924 and currently has over 650 standards and technical publications. Over 100 of them have been incorporated into U.S. regulations, and they are the most widely-cited industry standards by international regulators. The program is accredited by the American National Standards Institute (ANSI), the same body that accredits programs at several national laboratories.

API represents all segments of America’s oil and natural gas industry. Its more than 600 members produce, process, and distribute most of the nation’s energy. The industry also supports 9.8 million U.S. jobs and 8 percent of the U.S. economy.
http://www.api.org/

Dejour’s Roan Creek Recoverable Resource Estimate Pegged at 67.5 BCFe Gas P-50 Contingent and Prospective Resources - 30/07/2014

Dejour’s Roan Creek Recoverable Resource Estimate Pegged at 67.5 BCFe Gas P-50 Contingent and Prospective Resources

VANCOUVER BC, July 29 2014 - Dejour Energy Inc. (NYSE MKT: DEJ / TSX: DEJ) (“Dejour” or the “Company”), an independent oil and natural gas exploration and production company operating in North America’s Piceance Basin and Peace River Arch regions, today announces receipt of an assessment of contingent and prospective recoverable resources effective July 1, 2014 for the Company’s 100% WI resource project covering 1960 net acres at Roan Creek in the SW Piceance Basin. The Company commissioned Gustavson Associates, LLC of Boulder, Colorado to complete the independent contingent/prospective recoverable resource assessment prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101").













For both Table 1-1 and Table 1-2, the Low Estimate column represents the P90 values from the probabilistic analysis (in other words, the value is greater than or equal to the P90 value 90% of the time), while the Best Estimate represents the P50 and the High Estimate represents the P103.
1 Society of Petroleum Evaluation Engineers, (Calgary Chapter): Canadian Oil and Gas Evaluation Handbook, First Edition, Volume I, June 30, 2002, 5-6.
2 Society of Petroleum Evaluation Engineers, (Calgary Chapter): Canadian Oil and Gas Evaluation Handbook, First Edition, Volume I, June 30, 2002, 5-7.
3 Society of Petroleum Evaluation Engineers, (Calgary Chapter): Canadian Oil and Gas Evaluation Handbook, First Edition, Volume I, June 30, 2002, 5-7.

Logistically Roan Creek is easily accessed, being central among 28 new Mancos vertical and horizontal producers in the SW Piceance. Dejour has proceeded with an application for drilling as part of its expected 2015-16 development campaign. The Company is encouraged by production profiles of these recently drilled Mancos/Niobrara wells that show expected recoveries as much as 6 BCF per Hz well in the Mancos alone at depths to 8500’.

“Receipt of the Gustavson report of estimated recoverable resources at Roan Creek is very timely for Dejour as it provides both a detailed analysis of the production potential associated with our leasehold and validates our belief in the long-term value of the Mancos/ Niobrara. Given favorable commodity pricing, and, when coupled with our current Kokopelli JV activity, the Company is well positioned to exploit the prolific Mancos/ Niobrara to further enhance to its Colorado reserve base,” states Robert L. Hodgkinson, CEO.

http://www.dejour.com/

SM Energy Reports Results for the Second Quarter of 2014 - 30/07/2014

SM Energy Reports Results for the Second Quarter of 2014; Announces Significant Bakken/Three Forks Acquisition
  • Record quarterly average daily production of 147 MBOE per day, compared to guidance range of 136 - 143 MBOE per day; quarterly production mix of 53% liquids/47% natural gas.
  • Quarterly GAAP net income of $59.8 million, or $0.88 per diluted share; adjusted quarterly net income of $106.5 million, or $1.56 per diluted share.
  • Record quarterly adjusted EBITDAX of $423.4 million; quarterly GAAP cash provided by operating activities of $415.4 million.
  • Announces agreement for acquisition of approximately 61,000 net acres adjacent to Company's Gooseneck prospect for$330 million.
  • Tests of alternative completion designs in operated Eagle Ford and Three Forks show significant improvement to program economics.
DENVER--(BUSINESS WIRE)--Jul. 29, 2014-- SM Energy Company (NYSE: SM) announces its financial results for the second quarter of 2014 and provides an operations update. In addition, a new presentation concerning the Company's second quarter earnings and operations update will be posted on the Company's website at www.sm-energy.com. This presentation will be referenced during the conference call scheduled for 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) on July 30, 2014. Information for the call can be found below.
SECOND QUARTER 2014 RESULTS
SM Energy reported net income for the second quarter of 2014 of $59.8 million, or $0.88 per diluted share. This compares to net income of $76.5 million, or $1.13 per diluted share, for the same period of 2013.
Adjusted net income for the second quarter of 2014 was $106.5 million, or $1.56 per diluted share, compared to adjusted net income of $51.8 million, or $0.76 per diluted share, for the same period of 2013. Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and are generally items whose timing and/or amount cannot be reasonably estimated.
Earnings before interest, taxes, depreciation, depletion, amortization, accretion, and exploration expense ("adjusted EBITDAX") set a new quarterly record of $423.4 million in the second quarter of 2014, an increase of 24% from $342.5 million for the same period of 2013.
Adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the Financial Highlights section at the end of this release for additional information about these measures.
Total operating revenues for the second quarter of 2014 were $675.0 million compared to $559.4 million for the same period of 2013, a 21% increase from period to period. The table below provides the average realized prices received by product, as well as the adjusted prices received after taking into account cash settlements for derivative transactions:
 
Average Realized Commodity Prices for the Three Months Ended June 30, 2014
 
Before the effect of
derivative cash
settlements
     
After the effect
of derivative cash
settlements
 
Oil ($/Bbl)$ 91.78$ 86.60
Gas ($/Mcf)$4.87$4.51
Natural gas liquids ($/Bbl)$35.61$35.59
Equivalent ($/BOE)$48.93$46.41
 
The table below presents key performance measures and metrics, as well as previously provided guidance for the second quarter of 2014:
      
ProductionReported2Q14 Guidance
 
Average daily production (MBOE/d)147.0136 - 143
Total production (MMBOE)13.3812.4 - 13.0
 
Costs
LOE ($/BOE)$4.69$4.80 - $5.05
Transportation ($/BOE)$6.20
$6.10 - $6.50
Production taxes (% of pre-derivative oil, gas, and NGL revenue)4.9%4.5% - 5.0%
 
G&A - Cash ($/BOE)$2.24$2.25 - $2.45
G&A - Cash NPP ($/BOE)$0.15$0.25 - $0.40
G&A - Non-cash ($/BOE)$0.46$0.40 - $0.60
Total G&A ($/BOE)$2.85$2.90 - $3.45
 
DD&A ($/BOE)$14.03$14.00 - $14.75
 
Reported average daily production increased by 6% from production of 138.6 MBOE per day in the first quarter of 2014. In the second quarter of 2014, SM Energy's reported production mix was 29% oil/condensate, 24% NGLs, and 47% natural gas.
In the second quarter, the Company reported per unit costs in-line or slightly below its previously announced guidance range.
OPERATIONS UPDATE
Eagle Ford Shale
The Company's operated net production in the Eagle Ford shale averaged 83.2 MBOE per day in the second quarter of 2014, a 9% sequential increase from the prior quarter and a 26% increase over the second quarter of 2013. During the second quarter,SM Energy made 23 flowing completions in its operated Eagle Ford Shale program.
The Company has been shifting its Eagle Ford drilling and completion program toward longer lateral wells and completions with higher sand loading. Although the Company's longer lateral testing is ongoing, sufficient data on the Company's increased sand loading tests is now available from wells in Area 2 of its operated Eagle Ford shale position to conclude that wells completed with higher sand loadings are more productive, have improved initial condensate yields, and have significantly improved economics. Additional details regarding this testing program are included in the Company's presentation and will be discussed on the Company’s earnings call.
In the non-operated portion of the Company's Eagle Ford shale program, net production for the second quarter of 2014 averaged 23.8 MBOE per day, a 2% sequential increase over the first quarter of 2014 production of 23.4 MBOE per day and a 37% increase over the second quarter of 2013. The operator made approximately 95 flowing completions during the second quarter. Consistent with previous expectations, the drilling and completion carry provided under the Company's Acquisition and Development Agreement with Mitsui was completed in the second quarter of 2014. With the completion of the carry, the Company is now responsible for funding its proportionate share of drilling and completion costs.
Bakken / Three Forks
In the second quarter of 2014, SM Energy's average daily production for its Bakken/Three Forks program was 16.5 MBOE per day. Average daily production for the quarter increased by 3% over the prior quarter and increased 21% from the second quarter of 2013. During the second quarter, the Company made 12 gross flowing completions in its operated Bakken/Three Forks program.
Earlier today, the Company entered into an agreement to acquire approximately 61,000 net acres in Divide and WilliamsCounties, North Dakota directly adjacent to its Gooseneck area for $330 million. Highlights of the transaction, which is expected to add significant drilling inventory, include:
  • Associated net production of approximately 3,200 BOE/d (91% oil, 1,500 BTU rich gas)
  • Properties are 90% operated and approximately 70% held by production
  • Interests in 126 drilling spacing units, 81 of which will be operated by SM Energy
  • Working interest for operated spacing units is expected to range between 37.5% – 50.0%
The transaction has an effective date of July 1, 2014, is expected to close by the end of the third quarter of 2014, and is subject to customary closing conditions and adjustments. The Company expects to fund the acquisition with cash on hand and borrowings under its existing credit facility.
Directly adjacent to the acquisition area, SM Energy has seen improvements in its Three Forks program recently due to faster drilling times and improved completions, where results to date indicate that recent wells have higher sustained production rates than older wells. Additional details regarding Gooseneck Three Forks well optimization are included in the Company's presentation and will be discussed on the Company's earnings call.
Powder River Basin
SM Energy completed one well in its Powder River Basin acreage in the second quarter of 2014. The Rush State 4277-36-1FH (SM 100% WI) with a 3,788 foot effective lateral length had a peak 30-day initial production rate of 737 BOE per day (2-stream, 85% oil). During 2014, the Company has acquired or entered into transactions to acquire approximately 33,000 net acres, resulting in a total of approximately 166,000 net acres in the basin. SM Energy added a third rig to its program during the second quarter and has contracted a fourth rig for delivery in the third quarter of 2014.
Permian Basin
During the second quarter of 2014, the Company made 4 flowing completions in its Sweetie Peck property. During the quarter, the Company completed two of its most productive wells to date in this program on a peak initial production per lateral foot basis. The Dorcus 4236H (SM 100% WI) had a peak 30-day initial production rate of 1,093 BOE per day on a two-stream basis and the Dorcus 3036H (SM 100% WI), the Company's first long lateral well in Sweetie Peck with an approximately 7,650 foot effective lateral, had a peak 30-day initial production rate of 1,559 BOE per day on a two-stream basis. In its Buffalo prospect in the northern Midland Basin, the Company spud its first Wolfcamp D test at the end of the second quarter.
FINANCIAL POSITION AND LIQUIDITY
As of the end of the second quarter, the Company had $163.8 million of cash on hand and outstanding borrowings of $1.6 billion, which were comprised entirely of long term notes. As of the end of the second quarter, SM Energy had an undrawn credit facility with $1.3 billion in lender commitments. As of June 30, 2014, the Company's debt to twelve month trailing adjusted EBITDAX remained at 1.0 times and its debt-to-book capitalization ratio was 48%.
CAPITAL, PRODUCTION, AND PERFORMANCE GUIDANCE
SM Energy is reviewing its capital budget for 2014 in light of its recent Bakken/Three Forks acquisition and expects to provide updated capital, production, and performance guidance in mid-August 2014.
EARNINGS CALL INFORMATION
The Company has scheduled a teleconference to discuss these results and other operational matters for July 30, 2014, at 8:00 a.m. Mountain time (10:00 a.m. Eastern time). Conference dial-in information is included below. A telephonic replay of the call will be available approximately two hours after the call through August 13, 2014.
         
Call Type   Phone Number   Conference ID
Domestic Participant   877-303-1292   72768736
Domestic Replay   855-859-2056   72768736
International Participant   315-625-3086   72768736
International Replay   404-537-3406   72768736
      
This call is being webcast live and can be accessed at SM Energy Company's website at www.sm-energy.com. An audio recording of the conference call will be available at that site through August 13, 2014.
INFORMATION ABOUT FORWARD-LOOKING STATEMENTS
This release contains forward-looking statements within the meaning of securities laws, including forecasts and projections. The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward-looking statements. These risks include factors such as the availability, proximity and capacity of gathering, processing and transportation facilities; the uncertainty of negotiations to result in an agreement or a completed transaction; the uncertain nature of announced acquisition, divestiture, joint venture, farm down or similar efforts and the ability to complete any such transactions; the uncertain nature of expected benefits from the actual or expected acquisition, divestiture, joint venture, farm down or similar efforts; the volatility and level of oil, natural gas, and natural gas liquids prices; uncertainties inherent in projecting future rates of production from drilling activities and acquisitions; the imprecise nature of estimating oil and gas reserves; the availability of additional economically attractive exploration, development, and acquisition opportunities for future growth and any necessary financings; unexpected drilling conditions and results; unsuccessful exploration and development drilling results; the availability of drilling, completion, and operating equipment and services; the risks associated with the Company's commodity price risk management strategy; uncertainty regarding the ultimate impact of potentially dilutive securities; and other such matters discussed in the “Risk Factors” section of SM Energy's 2013 Annual Report on Form 10-K. The forward-looking statements contained herein speak as of the date of this announcement. Although SM Energy may from time to time voluntarily update its prior forward-looking statements, it disclaims any commitment to do so except as required by securities laws.
ABOUT THE COMPANY
SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids in onshore North America. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at www.sm-energy.com.
         
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2014
         
Production Data
For the Three Months Ended
June 30,
For the Six Months Ended
June 30,
20142013
Percent
Change
20142013
Percent
Change
 
Average realized sales price, before the effects of
derivative cash settlements:
Oil (per Bbl)$91.78$90.002%$90.41$90.82%
Gas (per Mcf)4.874.2814%5.043.9627%
NGL (per Bbl)35.61 34.09 4%37.13 35.24 5%
Equivalent (per BOE)$48.93$44.5710%$49.43$44.9510%
 
Average realized sales price, including the effects of
derivative cash settlements:
Oil (per Bbl)$86.60$89.64(3)%$86.85$90.45(4)%
Gas (per Mcf)4.514.237%4.674.0814%
NGL (per Bbl)35.59 36.00 (1)%35.67 36.81 (3)%
Equivalent (per BOE)$46.41$44.664%$47.00$45.523%
 
Production:
Oil (MMBbls)3.893.2321%7.556.3619%
Gas (Bcf)37.9639.15(3)%73.5071.393%
NGL (MMBbls)3.16 2.24 41%6.05 4.08 48%
MMBOE13.3811.9912%25.8522.3416%
 
Average daily production:
Oil (MBbls per day)42.835.521%41.735.119%
Gas (MMcf per day)417.2430.2(3)%406.1394.43%
NGL (MBbls per day)34.7 24.6 41%33.4 22.5 48%
MBOE147.0131.812%142.8123.416%
 
Per BOE Data:
Realized price before the effects of derivative cash settlements$48.93$44.5710%$49.43$44.9510%
Lease operating expense4.694.69%4.644.96(6)%
Transportation costs6.205.5911%6.275.1222%
Production taxes2.382.218%2.292.242%
General and administrative2.85 2.95 (3)%2.83 3.03 (7)%
Operating profit, before the effects of derivative cash settlements$32.81$29.1313%$33.40$29.6013%
Derivative cash settlements(2.52)0.09 (2,900)%(2.43)0.57 (526)%
Operating profit, including the effects of derivative cash settlements$30.29 $29.22 4%$30.97 $30.17 3%
Depletion, depreciation, amortization, and
asset retirement obligation liability accretion$14.03$18.82(25)%$14.12$19.00(26)%
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2014
            
Condensed Consolidated Statements of Operations
(in thousands, except per share amounts)
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2014201320142013
Operating revenues:
Oil, gas, and NGL production revenue$654,661$534,520$1,277,770$1,004,095
Other operating revenues20,319 24,840 29,930 39,445 
Total operating revenues674,980 559,360 1,307,700 1,043,540 
 
Operating expenses:
Oil, gas, and NGL production expense177,598149,737341,307275,370
Depletion, depreciation, amortization, and asset retirement
obligation liability accretion
187,781225,731364,996424,440
Exploration24,27020,65745,60536,055
Impairment of proved properties34,55255,771
Abandonment and impairment of unproved properties1644,3392,9654,641
General and administrative38,11535,37473,16667,654
Change in Net Profits Plan liability(7,105)(5,438)(8,881)(7,363)
Derivative loss (gain)126,469(85,190)224,131(54,618)
Other operating expenses5,972 35,314 14,061 51,108 
Total operating expenses553,264 415,076 1,057,350 853,058 
 
Income from operations121,716144,284250,350190,482
 
Non-operating income (expense):
Interest expense(24,040)(21,581)(48,230)(40,682)
Other, net(1,847)24 (1,821)36 
 
Income before income taxes95,829122,727200,299149,836
Income tax expense(36,049)(46,205)(74,912)(56,587)
 
Net income$59,780 $76,522 $125,387 $93,249 
 
Basic weighted-average common shares outstanding67,069 66,295 67,063 66,254 
 
Diluted weighted-average common shares outstanding68,239 67,893 68,180 67,711 
 
Basic net income per common share$0.89 $1.15 $1.87 $1.41 
 
Diluted net income per common share$0.88 $1.13 $1.84 $1.38 
 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2014
      
Condensed Consolidated Balance Sheets
(in thousands, except share amounts)June 30,December 31,
ASSETS20142013
Current assets:
Cash and cash equivalents$163,794$282,248
Accounts receivable312,415318,371
Derivative asset3,61321,559
Deferred income taxes12,08610,749
Prepaid expenses and other15,007 14,574 
Total current assets506,915 647,501 
 
Property and equipment (successful efforts method):
Proved oil and gas properties6,151,7655,637,462
Less - accumulated depletion, depreciation, and amortization(2,883,506)(2,583,698)
Unproved oil and gas properties388,336271,100
Wells in progress495,052279,654
Oil and gas properties held for sale net of accumulated depletion, depreciation and amortization of $23,697 and $7,390, respectively
23,93519,072
Other property and equipment, net of accumulated depreciation of $33,529 and $28,775, respectively258,619 236,202 
Total property and equipment, net4,434,201 3,859,792 
 
Noncurrent assets:
Derivative asset1,30030,951
Restricted cash5,49996,713
Other noncurrent assets56,120 70,208 
Total other noncurrent assets62,919 197,872 
Total Assets$5,004,035 $4,705,165 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses$592,493$606,751
Derivative liability92,08826,380
Other current liabilities 6,000 
Total current liabilities684,581 639,131 
 
Noncurrent liabilities:
Revolving credit facility
Senior Notes1,600,0001,600,000
Asset retirement obligation117,916115,659
Asset retirement obligation associated with oil and gas properties held for sale2,7603,033
Net Profits Plan liability48,10456,985
Deferred income taxes725,408650,125
Derivative liability52,8474,640
Other noncurrent liabilities26,467 28,771 
Total noncurrent liabilities2,573,502 2,459,213 
 
Stockholders’ equity:
Common stock, $0.01 par value - authorized: 200,000,000 shares; issued: 67,116,732 and 67,078,853
shares outstanding, respectively; net of treasury shares: 67,116,732 and 67,056,441, respectively
671671
Additional paid-in capital273,664257,720
Treasury stock, at cost: zero and 22,412 shares, respectively(823)
Retained earnings1,476,7031,354,669
Accumulated other comprehensive loss(5,086)(5,416)
Total stockholders’ equity1,745,952 1,606,821 
Total Liabilities and Stockholders’ Equity$5,004,035 $4,705,165 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2014
            
Condensed Consolidated Statements of Cash Flows
(in thousands)
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2014201320142013
Cash flows from operating activities:
Net income$59,780$76,522$125,387$93,249
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on divestiture activity(2,526)(6,280)(5,484)(5,706)
Depletion, depreciation, amortization, and asset retirement obligation liability accretion187,781225,731364,996424,440
Exploratory dry hole expense6,4595,7276,4595,886
Impairment of proved properties34,55255,771
Abandonment and impairment of unproved properties1644,3392,9654,641
Stock-based compensation expense7,9979,95514,34118,068
Change in Net Profits Plan liability(7,105)(5,438)(8,881)(7,363)
Derivative loss (gain)126,469(85,190)224,131(54,618)
Derivative cash settlement (loss) gain(33,680)2,211(62,620)14,003
Amortization of deferred financing costs1,4771,3632,9542,440
Deferred income taxes35,53745,95973,91156,239
Plugging and abandonment(1,894)(2,368)(3,219)(3,746)
Other, net(1,724)3,933(4,827)5,769
Changes in current assets and liabilities:
Accounts receivable(11,905)(37,120)(2,558)(59,284)
Prepaid expenses and other417(637)1,302(32)
Accounts payable and accrued expenses48,178 40,804 (13,704)46,598 
Net cash provided by operating activities415,425 314,063 715,153 596,355 
 
Cash flows from investing activities:
Net proceeds from sale of oil and gas properties44,84216,03646,82120,343
Capital expenditures(426,841)(352,852)(778,580)(733,992)
Acquisition of proved and unproved oil and gas properties(98,619)(59,156)(98,619)(59,201)
Other, net(6,484)(2,915)(2,257)(4,940)
Net cash used in investing activities(487,102)(398,887)(832,635)(777,790)
 
Cash flows from financing activities:
Proceeds from credit facility293,000516,500
Repayment of credit facility(695,000)(828,500)
Deferred financing costs related to credit facility(3,444)(3,444)
Net proceeds from 2024 Notes490,820490,820
Proceeds from sale of common stock2,4902,8802,4903,652
Dividends paid(3,353)(3,314)(3,353)(3,314)
Other, net(101)(29)(109)(29)
Net cash provided by (used in) financing activities(964)84,913 (972)175,685 
 
Net change in cash and cash equivalents(72,641)89(118,454)(5,750)
Cash and cash equivalents at beginning of period236,435  87 282,248 5,926 
Cash and cash equivalents at end of period$163,794 $176 $163,794 $176 
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2014
            
Adjusted Net Income
(in thousands, except per share data)
 
Reconciliation of net income (GAAP)
to adjusted net income (Non-GAAP):
For the Three Months
Ended June 30,
For the Six Months
Ended June 30,
2014201320142013
 
Reported net income (GAAP)$59,780$76,522$125,387$93,249
 
Adjustments net of tax: (1)
Change in Net Profits Plan liability(4,462)(3,393)(5,577)(4,580)
Derivative loss (gain)79,423(53,159)140,754(33,973)
Derivative cash settlement (loss) gain(21,151)1,380(39,325)8,710
Gain on divestiture activity(1,586)(3,919)(3,444)(3,549)
Impairment of proved properties21,56134,690
Abandonment and impairment of unproved properties1032,7081,8622,887
Other (2)(5,558)10,107(5,558)10,075
        
Adjusted net income (Non-GAAP) (3)$106,549 $51,807 $214,099 $107,509 
 
Diluted weighted-average common shares outstanding:68,239 67,893 68,180 67,711 
 
Adjusted net income per diluted common share:$1.56 $0.76 $3.14 $1.59 
 
(1) For the three and six-month period ended June 30, 2014, adjustments are shown net of tax and are calculated using a tax rate of 37.2%, which approximates the Company's statutory tax rate for that period, as adjusted for ordinary permanent differences. For the three and six-month period ended June 30, 2013, adjustments are shown net of tax using the Company's effective rate as calculated by dividing income tax expense by income before income taxes on the condensed consolidated statement of operations.
(2) For the three and six-month period ended June 30, 2014, adjustments include items related to settlements from the previously disclosed litigation against Endeavour Operating Corporation. These items are included as a portion of other operating revenues and non-operating expense, other, net, on the Company's condensed consolidated statement of operations. For the three and six-month period ended June 30, 2013, adjustments include items related to an agreed clarification concerning royalty payment provisions of various leases on certain South Texas & Gulf Coast acreage. These items are included as a portion of other operating expense on the Company's condensed consolidated statement of operations.
(3) Adjusted net income excludes certain items that the Company believes affect the comparability of operating results and generally are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash adjustments and impairments such as the change in the Net Profits Plan liability, derivative loss, derivative cash settlement (loss) gain, impairment of properties, and (gain) loss on divestiture activity. The non-GAAP measure of adjusted net income is presented because management believes it provides useful additional information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted net income should not be considered in isolation or as a substitute for net income, income from operations, cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income excludes some, but not all, items that affect net income and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies.
 
SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS (unaudited)
June 30, 2014
Adjusted EBITDAX (3)            
(in thousands)
 
Reconciliation of net income (GAAP) to adjusted EBITDAX (Non-
GAAP) to net cash provided by operating activities (GAAP)
For the Three Months
Ended June 30,
 
20142013 20142013
Net income (GAAP)$59,780$76,522$125,387$93,249
Interest expense24,04021,58148,23040,682
Other non-operating (income) expense, net1,847(24)1,821(36)
Income tax expense36,04946,20574,91256,587
Depreciation, depletion, amortization, and asset retirement
obligation liability accretion
187,781225,731364,996424,440
Exploration (1)22,60318,38342,54131,607
Impairment of proved properties34,55255,771
Abandonment and impairment of unproved properties1644,3392,9654,641
Stock-based compensation expense7,9979,95514,34118,068
Derivative loss (gain)126,469(85,190)224,131(54,618)
Derivative cash settlement gain (loss)(33,680)2,211(62,620)14,003
Change in Net Profits Plan liability(7,105)(5,438)(8,881)(7,363)
Gain on divestiture activity (2)(2,526)(6,280)(5,484)(5,706)
Adjusted EBITDAX (Non-GAAP)423,419 342,547 822,339 671,325 
Interest expense(24,040)(21,581)(48,230)(40,682)
Other non-operating income (expense), net(1,847)24(1,821)36
Income tax expense(36,049)(46,205)(74,912)(56,587)
Exploration (1)(22,603)(18,383)(42,541)(31,607)
Exploratory dry hole expense6,4595,7276,4595,886
Amortization of deferred financing costs1,4771,3632,9542,440
Deferred income taxes35,53745,95973,91156,239
Plugging and abandonment(1,894)(2,368)(3,219)(3,746)
Other, net(1,724)3,933(4,827)5,769
Changes in current assets and liabilities36,690 3,047 (14,960)(12,718)
Net cash provided by operating activities (GAAP)$415,425 $314,063 $715,153 $596,355 
 
(1) Stock-based compensation expense is a component of exploration expense and general and administrative expense on the accompanying condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying condensed consolidated statements of operations because of the component of stock-based compensation expense recorded to exploration.
(2) Gain on divestiture activity is included within the other operating revenues line item of the accompanying condensed consolidated statements of operations.
(3) Adjusted EBITDAX represents income before interest expense, other non-operating (income) expense, income taxes, depreciation, depletion, amortization, and accretion, exploration expense, property impairments, non-cash stock compensation expense, derivative gains and losses net of cash settlements, change in the Net Profits Plan liability, and gains and losses on divestitures. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally one-time in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that is presented because the Company believes that it provides useful additional information to investors and analysts, as a performance measure, for analysis of the Company's ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to a financial covenant under its credit facility based on its debt to adjusted EBITDAX ratio. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities, or profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies

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