The Bakken bubble has burst, production is now falling
The updated model in this study suggests 119 new producers/month are required for 2015 to maintain North Dakota YE 2015 production at 2014 levels i.e. 1.23M bopd – this is comparable to NDIC and other estimates
Assuming the number of new producers stays at 52/month (i.e. Jan/Feb levels) for the remainder of 2015 then, North Dakota 2015 YE production would decline by 27% to 0.90M BOPD
Some analysts suggest the LTO industry could enter a downward spiral by Q4 2015, sustained by weaker oil prices that will result in significantly reduced cash flows and for some, debt to EBITA ratios that violate credit covenants. This will in turn accentuate the decline of production and revenues. Some LTO plays (such as the Bakken) would then become a less attractive proposition as the cycle accentuates
Bakken economics are one of the most challenging of the LTO plays at sustained low oil prices due to the $7-10 discount between ND light sweet and WTI
Some companies are already diverting capital from the Bakken to other LTO plays with higher margins
Energy Equipment & Services: Industry Insights & HappeningsCapstone Headwaters
The latest issue of our monthly Energy Equipment & Services Report, highlighting trends in M&A, financing and capital markets for private and public companies in the energy market, is now available.
Highlights include:
Crude prices continue to dominate the industry’s outlook
1Q results in the OFS space were downbeat, but management teams expressed optimism that a recovery is in its early stages and may begin to be realized in 2017
On the M&A front, the big news in May was the termination of the planned Halliburton-Baker Hughes merger less than a month after the US DOJ sued to block the transaction.
Energy Equipment & Services: Industry Insights & HappeningsCapstone Headwaters
The latest issue of our monthly Energy Equipment & Services Report, highlighting trends in M&A, financing and capital markets for private and public companies in the energy market, is now available.
Energy equipment & services monthly report – september finalCapstone Headwaters
Crude prices have moderated somewhat after reaching the upper $40
range
–– Prices weakened by rising exports from Iran, elevated inventories, and
weak refinery demand
• US Rig counts continue to improve moderately
–– Since August 12, the US onshore market has added 25 rigs, bringing the
total rig count to 506
–– International rig counts rose slightly by 66 in August
• Refining utilization decreased mildly since last month, and more
substantial declines are expected going forward
–– 300k bbl/d capacity expected to be down for routine maintenance at
times during fourth quarter, excluding economic run cuts or unplanned
downtime
• In Q2 2016, overall solar system pricing fell by up to 7.5%. Utility fixedtilt
and tracking projects in Q2 2016 saw an average pricing of $1.17/Wdc
and $1.30/Wdc, respectively.
• Continued elevated temperatures led to record power demand across
the country, including an
- Enerplus is a North American energy producer focused on oil and gas assets that generates a 10-15% annual income growth and targets.
- It has diversified its asset base through acquisitions of growth assets in the Bakken crude oil and Marcellus shale gas plays while divesting non-core assets.
- Enerplus' capital investment plans for 2011-2012 focus on oil projects like the Bakken and waterfloods, with an expected production growth of 10-15% over the next two years.
July 2016 Energy Equipment & Services: Industry Insights & HappeningsCapstone Headwaters
The latest issue of our monthly Energy Equipment & Services Report, highlighting trends in M&A, financing and capital markets for private and public companies in the energy market, is now available.
The document provides an overview of Antero Resources Corporation and contains forward-looking statements regarding estimates, expectations, plans, strategies, objectives, anticipated financial and operating results, and assumptions. It cautions that forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from expectations. The company undertakes no obligation to update forward-looking statements, except as required by law.
The document provides an overview of Antero Resources Corporation, including:
- Antero has significant reserves of 37.5 Tcfe primarily in the Marcellus and Utica shale plays with strong production growth.
- The company has industry-leading capital efficiency and a top quartile return on productive capital, with low development costs and a high growth-adjusted recycle ratio.
- Antero has invested heavily in midstream infrastructure like processing plants and pipelines to support its production and has secured significant firm transportation contracts.
The document provides an overview of Antero Resources Corporation, including:
- Antero has significant reserves of 37.5 Tcfe primarily in the Marcellus and Utica shale plays with strong production growth.
- The company has industry-leading capital efficiency and a top quartile return on productive capital.
- Antero has significant midstream infrastructure and secured firm transportation for its gas and NGL production.
Energy Equipment & Services: Industry Insights & HappeningsCapstone Headwaters
The latest issue of our monthly Energy Equipment & Services Report, highlighting trends in M&A, financing and capital markets for private and public companies in the energy market, is now available.
Highlights include:
Crude prices continue to dominate the industry’s outlook
1Q results in the OFS space were downbeat, but management teams expressed optimism that a recovery is in its early stages and may begin to be realized in 2017
On the M&A front, the big news in May was the termination of the planned Halliburton-Baker Hughes merger less than a month after the US DOJ sued to block the transaction.
Energy Equipment & Services: Industry Insights & HappeningsCapstone Headwaters
The latest issue of our monthly Energy Equipment & Services Report, highlighting trends in M&A, financing and capital markets for private and public companies in the energy market, is now available.
Energy equipment & services monthly report – september finalCapstone Headwaters
Crude prices have moderated somewhat after reaching the upper $40
range
–– Prices weakened by rising exports from Iran, elevated inventories, and
weak refinery demand
• US Rig counts continue to improve moderately
–– Since August 12, the US onshore market has added 25 rigs, bringing the
total rig count to 506
–– International rig counts rose slightly by 66 in August
• Refining utilization decreased mildly since last month, and more
substantial declines are expected going forward
–– 300k bbl/d capacity expected to be down for routine maintenance at
times during fourth quarter, excluding economic run cuts or unplanned
downtime
• In Q2 2016, overall solar system pricing fell by up to 7.5%. Utility fixedtilt
and tracking projects in Q2 2016 saw an average pricing of $1.17/Wdc
and $1.30/Wdc, respectively.
• Continued elevated temperatures led to record power demand across
the country, including an
- Enerplus is a North American energy producer focused on oil and gas assets that generates a 10-15% annual income growth and targets.
- It has diversified its asset base through acquisitions of growth assets in the Bakken crude oil and Marcellus shale gas plays while divesting non-core assets.
- Enerplus' capital investment plans for 2011-2012 focus on oil projects like the Bakken and waterfloods, with an expected production growth of 10-15% over the next two years.
July 2016 Energy Equipment & Services: Industry Insights & HappeningsCapstone Headwaters
The latest issue of our monthly Energy Equipment & Services Report, highlighting trends in M&A, financing and capital markets for private and public companies in the energy market, is now available.
The document provides an overview of Antero Resources Corporation and contains forward-looking statements regarding estimates, expectations, plans, strategies, objectives, anticipated financial and operating results, and assumptions. It cautions that forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from expectations. The company undertakes no obligation to update forward-looking statements, except as required by law.
The document provides an overview of Antero Resources Corporation, including:
- Antero has significant reserves of 37.5 Tcfe primarily in the Marcellus and Utica shale plays with strong production growth.
- The company has industry-leading capital efficiency and a top quartile return on productive capital, with low development costs and a high growth-adjusted recycle ratio.
- Antero has invested heavily in midstream infrastructure like processing plants and pipelines to support its production and has secured significant firm transportation contracts.
The document provides an overview of Antero Resources Corporation, including:
- Antero has significant reserves of 37.5 Tcfe primarily in the Marcellus and Utica shale plays with strong production growth.
- The company has industry-leading capital efficiency and a top quartile return on productive capital.
- Antero has significant midstream infrastructure and secured firm transportation for its gas and NGL production.
The document is a company overview for Antero Resources Corporation from July 2016. It discusses Antero's acquisition of 68,000 net acres and 5.1 trillion cubic feet of reserves for $558 million. This significantly increases Antero's core drilling inventory and positions the company for long-term production growth. The acquisition also enhances Antero's dry gas optionality and increases dedication of acreage to Antero Midstream. The economics of wells on the acquired acreage are attractive, with estimated returns of 51% to 77% at current strip prices.
QEP Resources is an oil and gas exploration and production company with operations in the northern and southern United States. The company's profitability is highly dependent on oil and gas prices, which have declined significantly in recent years. A discounted cash flow model values the company at $17.76 per share, suggesting an 11% upside from the current stock price of $16.02. However, the recommendation is a hold due to uncertainty around future commodity prices as driven by supply and demand fundamentals. Key risks include unforeseen supply disruptions that could drive prices higher from current futures curve expectations.
Barclays conference presentation (website) september 2016 v5AnteroResources
This document provides guidance and forward-looking statements from Antero Resources Corporation regarding its operations and financial outlook. Some of the key points include:
- Revised 2016 total production guidance of 1.8 Bcfe/d, an increase from previous guidance of 1.75 Bcfe/d.
- Estimated net income range for 2016 of $205-225 million, an increase from the previous estimate of $165-190 million.
- Capital budget for 2016 remains at $1.4 billion to drill 110 wells while maintaining production growth of 20-25% annually through 2020.
- The company has significant liquidity and a large drilling inventory that positions it to capitalize on growing natural
Company website presentation (a) september 2016AnteroResources
The document provides an overview of Antero Resources Corporation. It begins with forward-looking statements and disclaimers about projections. It then notes that the company has updated its 2016 production and operating cost guidance, increasing projected growth to 20% and lowering costs. The acquisition of additional acreage from a third party is discussed, which adds over 66,000 net acres and over 5 trillion cubic feet of reserves. This significantly increases Antero's core drilling locations and provides growth for its midstream subsidiary, Antero Midstream. The economics of developing the acquired acreage are attractive, with projected returns of 51-77% depending on gas prices.
The document provides an overview of Antero Resources Corporation, including:
- Antero has significant reserves of 37.5 Tcfe primarily in the Marcellus and Utica shale plays with high potential for further reserve growth.
- Production has grown significantly from 566 MMcfe/d in 3Q 2013 to 891 MMcfe/d currently due to a focus on liquids-rich development across its acreage.
- Antero has leading capital efficiency with a low average development cost of $1.15/Mcfe and industry-leading recycle ratio of 4.8x, supporting high returns on productive capital.
This document provides an overview of Antero Midstream Partners LP and contains forward-looking statements regarding future plans and expectations. It discusses key risks and assumptions, including dependence on Antero Resources' development plans, commodity price volatility, and other operational risks. It also notes that future distributions are dependent on Antero Resources' annual capital budget and factors such as commodity prices and Antero Resources' financial resources and liquidity.
The document provides an overview of Antero Resources Corporation. It discusses forward-looking statements and risks associated with the estimates and projections. It also highlights key aspects of Antero's recent acquisition including the addition of 66,500 net acres and over 5 trillion cubic feet of reserves for $546 million. The acquisition significantly increases Antero's drilling inventory in the Marcellus shale play with attractive well economics.
The document summarizes an asset acquisition by Antero Resources Corporation of 55,000 net acres of core Marcellus and Utica shale assets for $450 million. The acquisition significantly increases Antero's acreage position and drilling inventory in the core of the Marcellus and Utica plays. Specifically, the acquisition adds over 4.1 trillion cubic feet of estimated reserves and over 1,000 new drilling locations. The acquired acreage will also be dedicated to Antero Midstream Partners for gathering and processing, providing additional growth opportunities. The acquisition enhances Antero's position in the top producing regions and improves the economic returns of its drilling program.
Dejour provides a corporate presentation summarizing its oil and gas assets and operations. The company holds over 45,000 net acres in the Piceance Basin and over 19,000 net acres in the Peace River Arch region. Dejour expects production to increase to over 1,200 BOE/d in Q3 2015 from existing wells at its Woodrush, Hunter, and Kokopelli projects. The presentation also highlights Dejour's other exploration prospects and provides a financial and corporate overview.
An annual report issued by the Federal Energy Regulatory Commission on the state of energy markets in the U.S. In this year's report, FERC says most places across the country have seen a bump up in pipelines over the past 10 years, relieving constrained natural gas transportation. Except for the Marcellus/Utica region. In the northeast, FERC expects the situation of oversupply and not enough pipelines to get resolved in 2019.
Company website presentation (a) january 2016AnteroResources
The document provides an overview of Antero Resources Corporation and contains forward-looking statements regarding estimates, plans, expectations and guidance. It notes that actual results could differ materially from forward-looking statements due to risks and uncertainties inherent in the oil and gas business. The document highlights Antero's large production base, declining costs, hedging position, and transportation agreements. It also summarizes Antero's reserves and production growth, operating performance, liquids-rich acreage position, and status as the most active driller in Appalachia.
1) The document provides an overview of Antero Resources Corporation, including forward-looking statements noting potential risks and uncertainties.
2) It outlines Antero's leadership position in the Appalachian Basin with large reserves, production, core acreage, and an inventory of undrilled locations.
3) Metrics provided include 2015 production growth guidance of over 40% and liquids production growth of over 60% for 2015.
Antero Resources is an E&P company focused on developing shale gas assets in the Appalachian region, including the Marcellus and Utica shales. It has over 429,000 net acres across its core positions. Antero has a proven track record of growth, increasing its proved reserves by 44% in the first half of 2013 to over 6 trillion cubic feet equivalent. It also grew production 115% year-over-year to 458 million cubic feet equivalent per day as of the second quarter of 2013. Antero has a large inventory of undrilled locations that can support further production growth from its sizable reserves and low-cost operating model.
Company website presentation (b) september 2016AnteroResources
The document provides an overview of a company acquisition that will significantly increase the company's core drilling inventory. Specifically:
- The acquisition adds 66,500 net acres and over 5 trillion cubic feet of reserves for $546 million, increasing the company's core inventory by over 1,000 drilling locations.
- The new acreage provides opportunities for improved well economics and type curves above 2 billion cubic feet per 1,000 feet, with estimated returns of 51-77% at current strip prices.
- The acquisition significantly increases the company's dry gas and condensate inventory, adding over 225 dry gas locations and enhancing over 300 condensate locations.
The document provides an overview of Antero Resources Corporation and contains forward-looking statements regarding estimates, plans, expectations and guidance. It notes that actual results may differ materially from forward-looking statements due to risks and uncertainties in the exploration and development of natural gas and oil. These risks include commodity price volatility, inflation, operational risks, regulatory changes, reserve estimation uncertainties, and other factors discussed in Antero's SEC filings.
The operational and financial updated issued by CONSOL Energy for first quarter 2014. The update shows CONSOL's rapid change from coal company to shale gas company. In May CONSOL's current CEO will retire and the current President will assume that role.
- Antero Resources is the largest producer and most active driller in the Appalachian Basin.
- In 2015, Antero is targeting 40% production growth, the highest among large cap E&P companies. This growth will be driven by completing 130 operated wells and maintaining an average of 14 operated drilling rigs.
- Antero has a large inventory of undrilled locations and substantial net acreage across the Marcellus Shale, Utica Shale, and Utica Dry Gas plays that will support long-term growth.
Mercer Capital's Value Focus: Energy Industry | Q1 2015 | Segment: Explorati...Mercer Capital
Mercer Capital's Energy Industry newsletter provides perspective on valuation issues. Each newsletter also typically includes a macroeconomic trends, industry trends, and guideline public company metrics.
O & G Panel - Maximizing under the ground value of fossil fuelsglobalenergysummit
Lower oil prices are causing oil companies to reevaluate their strategies and operations. Production costs for most oil and gas projects remain viable below $80 per barrel, but company cash flows are under threat as capex has increased significantly. In response, companies are reducing spending and delaying projects that are less economic at lower prices, such as those in oil sands and deepwater. A sustained period of lower prices will require operators to optimize their portfolios, lower costs, manage investments and balance sheets prudently.
State of the Canadian Oilfield Services Industry and 2015 Outlook WebinarMNP LLP
This presentation was part of an online webinar targeted toward Oilfield Services (OFS) businesses. It gives a clear picture of the current state of the OFS industry as well as a forecast for the future, including strategies for taking advantage of forthcoming opportunities and potential challenges OFS operators may face. It also provides an overview of MNP LLP's Oilfield Services team and the assistance we can provide.
Countdown to Natural Gas: In 2015 the Dynamics of the U.S. Natural Gas Market...PointLogicEnergy
Alan Lammey, PointLogic Energy's senior energy markets analysts, delivered this presentation, "Countdown to Natural Gas: In 2015 the Dynamics of the U.S. Natural Gas Market Will Change Forever" to the attendees of the Texas Society of CPAs Energy Conference on April 30, 2015.
The document is a company overview for Antero Resources Corporation from July 2016. It discusses Antero's acquisition of 68,000 net acres and 5.1 trillion cubic feet of reserves for $558 million. This significantly increases Antero's core drilling inventory and positions the company for long-term production growth. The acquisition also enhances Antero's dry gas optionality and increases dedication of acreage to Antero Midstream. The economics of wells on the acquired acreage are attractive, with estimated returns of 51% to 77% at current strip prices.
QEP Resources is an oil and gas exploration and production company with operations in the northern and southern United States. The company's profitability is highly dependent on oil and gas prices, which have declined significantly in recent years. A discounted cash flow model values the company at $17.76 per share, suggesting an 11% upside from the current stock price of $16.02. However, the recommendation is a hold due to uncertainty around future commodity prices as driven by supply and demand fundamentals. Key risks include unforeseen supply disruptions that could drive prices higher from current futures curve expectations.
Barclays conference presentation (website) september 2016 v5AnteroResources
This document provides guidance and forward-looking statements from Antero Resources Corporation regarding its operations and financial outlook. Some of the key points include:
- Revised 2016 total production guidance of 1.8 Bcfe/d, an increase from previous guidance of 1.75 Bcfe/d.
- Estimated net income range for 2016 of $205-225 million, an increase from the previous estimate of $165-190 million.
- Capital budget for 2016 remains at $1.4 billion to drill 110 wells while maintaining production growth of 20-25% annually through 2020.
- The company has significant liquidity and a large drilling inventory that positions it to capitalize on growing natural
Company website presentation (a) september 2016AnteroResources
The document provides an overview of Antero Resources Corporation. It begins with forward-looking statements and disclaimers about projections. It then notes that the company has updated its 2016 production and operating cost guidance, increasing projected growth to 20% and lowering costs. The acquisition of additional acreage from a third party is discussed, which adds over 66,000 net acres and over 5 trillion cubic feet of reserves. This significantly increases Antero's core drilling locations and provides growth for its midstream subsidiary, Antero Midstream. The economics of developing the acquired acreage are attractive, with projected returns of 51-77% depending on gas prices.
The document provides an overview of Antero Resources Corporation, including:
- Antero has significant reserves of 37.5 Tcfe primarily in the Marcellus and Utica shale plays with high potential for further reserve growth.
- Production has grown significantly from 566 MMcfe/d in 3Q 2013 to 891 MMcfe/d currently due to a focus on liquids-rich development across its acreage.
- Antero has leading capital efficiency with a low average development cost of $1.15/Mcfe and industry-leading recycle ratio of 4.8x, supporting high returns on productive capital.
This document provides an overview of Antero Midstream Partners LP and contains forward-looking statements regarding future plans and expectations. It discusses key risks and assumptions, including dependence on Antero Resources' development plans, commodity price volatility, and other operational risks. It also notes that future distributions are dependent on Antero Resources' annual capital budget and factors such as commodity prices and Antero Resources' financial resources and liquidity.
The document provides an overview of Antero Resources Corporation. It discusses forward-looking statements and risks associated with the estimates and projections. It also highlights key aspects of Antero's recent acquisition including the addition of 66,500 net acres and over 5 trillion cubic feet of reserves for $546 million. The acquisition significantly increases Antero's drilling inventory in the Marcellus shale play with attractive well economics.
The document summarizes an asset acquisition by Antero Resources Corporation of 55,000 net acres of core Marcellus and Utica shale assets for $450 million. The acquisition significantly increases Antero's acreage position and drilling inventory in the core of the Marcellus and Utica plays. Specifically, the acquisition adds over 4.1 trillion cubic feet of estimated reserves and over 1,000 new drilling locations. The acquired acreage will also be dedicated to Antero Midstream Partners for gathering and processing, providing additional growth opportunities. The acquisition enhances Antero's position in the top producing regions and improves the economic returns of its drilling program.
Dejour provides a corporate presentation summarizing its oil and gas assets and operations. The company holds over 45,000 net acres in the Piceance Basin and over 19,000 net acres in the Peace River Arch region. Dejour expects production to increase to over 1,200 BOE/d in Q3 2015 from existing wells at its Woodrush, Hunter, and Kokopelli projects. The presentation also highlights Dejour's other exploration prospects and provides a financial and corporate overview.
An annual report issued by the Federal Energy Regulatory Commission on the state of energy markets in the U.S. In this year's report, FERC says most places across the country have seen a bump up in pipelines over the past 10 years, relieving constrained natural gas transportation. Except for the Marcellus/Utica region. In the northeast, FERC expects the situation of oversupply and not enough pipelines to get resolved in 2019.
Company website presentation (a) january 2016AnteroResources
The document provides an overview of Antero Resources Corporation and contains forward-looking statements regarding estimates, plans, expectations and guidance. It notes that actual results could differ materially from forward-looking statements due to risks and uncertainties inherent in the oil and gas business. The document highlights Antero's large production base, declining costs, hedging position, and transportation agreements. It also summarizes Antero's reserves and production growth, operating performance, liquids-rich acreage position, and status as the most active driller in Appalachia.
1) The document provides an overview of Antero Resources Corporation, including forward-looking statements noting potential risks and uncertainties.
2) It outlines Antero's leadership position in the Appalachian Basin with large reserves, production, core acreage, and an inventory of undrilled locations.
3) Metrics provided include 2015 production growth guidance of over 40% and liquids production growth of over 60% for 2015.
Antero Resources is an E&P company focused on developing shale gas assets in the Appalachian region, including the Marcellus and Utica shales. It has over 429,000 net acres across its core positions. Antero has a proven track record of growth, increasing its proved reserves by 44% in the first half of 2013 to over 6 trillion cubic feet equivalent. It also grew production 115% year-over-year to 458 million cubic feet equivalent per day as of the second quarter of 2013. Antero has a large inventory of undrilled locations that can support further production growth from its sizable reserves and low-cost operating model.
Company website presentation (b) september 2016AnteroResources
The document provides an overview of a company acquisition that will significantly increase the company's core drilling inventory. Specifically:
- The acquisition adds 66,500 net acres and over 5 trillion cubic feet of reserves for $546 million, increasing the company's core inventory by over 1,000 drilling locations.
- The new acreage provides opportunities for improved well economics and type curves above 2 billion cubic feet per 1,000 feet, with estimated returns of 51-77% at current strip prices.
- The acquisition significantly increases the company's dry gas and condensate inventory, adding over 225 dry gas locations and enhancing over 300 condensate locations.
The document provides an overview of Antero Resources Corporation and contains forward-looking statements regarding estimates, plans, expectations and guidance. It notes that actual results may differ materially from forward-looking statements due to risks and uncertainties in the exploration and development of natural gas and oil. These risks include commodity price volatility, inflation, operational risks, regulatory changes, reserve estimation uncertainties, and other factors discussed in Antero's SEC filings.
The operational and financial updated issued by CONSOL Energy for first quarter 2014. The update shows CONSOL's rapid change from coal company to shale gas company. In May CONSOL's current CEO will retire and the current President will assume that role.
- Antero Resources is the largest producer and most active driller in the Appalachian Basin.
- In 2015, Antero is targeting 40% production growth, the highest among large cap E&P companies. This growth will be driven by completing 130 operated wells and maintaining an average of 14 operated drilling rigs.
- Antero has a large inventory of undrilled locations and substantial net acreage across the Marcellus Shale, Utica Shale, and Utica Dry Gas plays that will support long-term growth.
Mercer Capital's Value Focus: Energy Industry | Q1 2015 | Segment: Explorati...Mercer Capital
Mercer Capital's Energy Industry newsletter provides perspective on valuation issues. Each newsletter also typically includes a macroeconomic trends, industry trends, and guideline public company metrics.
O & G Panel - Maximizing under the ground value of fossil fuelsglobalenergysummit
Lower oil prices are causing oil companies to reevaluate their strategies and operations. Production costs for most oil and gas projects remain viable below $80 per barrel, but company cash flows are under threat as capex has increased significantly. In response, companies are reducing spending and delaying projects that are less economic at lower prices, such as those in oil sands and deepwater. A sustained period of lower prices will require operators to optimize their portfolios, lower costs, manage investments and balance sheets prudently.
State of the Canadian Oilfield Services Industry and 2015 Outlook WebinarMNP LLP
This presentation was part of an online webinar targeted toward Oilfield Services (OFS) businesses. It gives a clear picture of the current state of the OFS industry as well as a forecast for the future, including strategies for taking advantage of forthcoming opportunities and potential challenges OFS operators may face. It also provides an overview of MNP LLP's Oilfield Services team and the assistance we can provide.
Countdown to Natural Gas: In 2015 the Dynamics of the U.S. Natural Gas Market...PointLogicEnergy
Alan Lammey, PointLogic Energy's senior energy markets analysts, delivered this presentation, "Countdown to Natural Gas: In 2015 the Dynamics of the U.S. Natural Gas Market Will Change Forever" to the attendees of the Texas Society of CPAs Energy Conference on April 30, 2015.
For much of the last decade through 2014, the U.S. energy sector expe¬rienced a bull market sustained by debt-financed drilling programs in emerging unconventional plays and supported by elevated commodity prices. U.S. E&P players, particularly the emerging universe of indepen¬dent unconventional operators, required an array of capital-intensive services that led to a boom in the services industry as well: rigs to handle development drilling; engineering services to handle geological surveys; logistics/infrastructure services to gather, transport, and store various hydrocarbons; and refitting of refineries to process increasing volumes of light oil. This wave of capital spending led to innovation in drilling and fracking technology, taking US production from about 6 million b/d to over 9 million b/d and marking the reversal of a decades-long decline in U.S. domestic oil production.
What’s Inside:
- U.S. Crude Production Oil Outlook
- Sector Updates: Last 12 Months in Review
- Capital Spending Trends
- Current State of the Storage Market
Is unconventional oil and gas a sustainable game changer?Energy Intelligence
Energy Intelligence's Executive Director and Oil & Money Conference chairman, Herman Franssen chairs "Is Unconventional Oil and Gas a sustainable Game Changer?"
Videos of this session will be available shortly on www.oilandmoney.com.
Plg refc presentation 2015 v gb 16 9 aspect final 030115PLG Consulting
This document provides an overview of PLG Consulting, a logistics and supply chain consulting firm, and discusses the implications of the North American energy revolution for the rail industry. PLG Consulting has over a decade of experience in logistics, engineering, and supply chain consulting for over 200 clients in bulk logistics, freight rail, energy, chemicals, and private equity. The document summarizes the growth of unconventional oil and gas extraction from US shale and Canadian oil sands due to new technologies, leading to surging domestic production and declining imports to North America. This energy boom has significant implications for growing crude by rail transportation on the continent.
10 Things That May Affect the Future of Subsea ProductionHubie Fix
The oil and gas industry is facing challenges and dilemmas encountered in 2009 such as contract delays, furloughs and rig closures are resurfacing. As oil and gas prices continue to decline, oil companies are starting to consider rig stacking as an alternative to reducing overhead and operating costs. This presentation explored what the future might hold for the subsea market, current infrastructures and future deepwater project development.
This presentation was presented at the 2015 Deepwater Technical Symposium in New Orleans, Louisiana.
- Enerplus is a North American energy producer focused on oil and gas assets that generates a 10-15% annual income growth and targets.
- It has diversified its asset base through acquisitions of growth assets in the Bakken crude oil and Marcellus shale gas plays while divesting non-core assets.
- Enerplus' capital investment plans for 2011-2012 focus on oil projects like the Bakken and waterfloods, with an expected production growth of 10-15% over the next two years.
MLA_Impacts of low oil prices on American unconventional and offshore oil pro...Mohamed Lahjibi
The document summarizes the impacts of low oil prices on American unconventional and offshore oil projects. In the short term, low prices have stimulated oil demand in the US but jeopardized the bankability of shale oil projects. Tight oil producers have reduced rig counts and budgets. Long term impacts may include a stronger dollar threatening economic growth, adjustments by shale oil producers through cost cuts and technology improvements, and negative effects on the natural gas and LNG markets if low prices persist.
Steven Kopits presented an analysis of oil supply and demand forecasting models. Traditional models are demand-driven and assume that GDP growth determines oil demand growth. However, Kopits argues for a supply-constrained view where oil supply growth limits GDP growth. He shows that despite $4 trillion spent, legacy oil production has declined while unconventionals prevented larger drops. Non-OECD demand could be 60 mbpd by 2030 but forecast growth is just 0.8% due to constrained supply assumptions. Kopits concludes traditional models overestimate future supply.
Bassam Fattouh - The Adjustment in the Oil Market: Cyclical or Structural?UNU-WIDER
The document summarizes recent trends in the global oil market since prices fell sharply in 2014. It discusses the supply-demand imbalance that led to rising stockpiles. While lower prices were expected to induce production cuts from non-OPEC suppliers and demand increases, adjustments have occurred more slowly than anticipated. Capital expenditures have declined significantly but many major projects approved during high prices are still coming online. Decline rates are accelerating in some mature areas with less investment. The investment and production cycle for US shale is much different than conventional oil, with shorter timelines between investment and production/decline.
- The document recommends buying Exxon Mobil stock, implying a 12-20% return, with a current market cap of $375.74B.
- Exxon has weathered business cycles through revenue generation and diversification across upstream, downstream, and chemical operations. Chemical operations grew substantially in Q1 2014, offsetting declines elsewhere.
- Exxon has allocated capital intelligently to projects with high returns, positioning it well for future growth in areas like Asia and a stabilizing crude oil market.
Natural Resource Partners L.P. held investor meetings in May 2015 to provide an overview and update. The document discusses NRP's diversified natural resource portfolio including interests in coal, aggregates, soda ash, and oil and gas. It notes the current challenges facing the coal industry and NRP's focus on reducing debt and improving its balance sheet. NRP expects to reduce debt by $500 million by the end of 2017 through distribution cuts and using the savings to repay debt. The summary highlights NRP's various business segments and financial projections.
The document discusses trends in the US natural gas market, including:
- US natural gas demand is increasingly served by domestic shale gas production rather than imports.
- Natural gas use for electricity generation is expected to increase due to low prices and coal plant retirements.
- Exports of liquefied natural gas and pipeline exports are expected to grow as US production increases and prices remain low relative to global markets, making the US a net exporter of natural gas.
The document discusses key trends in the US natural gas market, including:
1) US natural gas demand is increasingly served by domestic shale gas production rather than imports as shale gas production has increased dramatically in recent years.
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13 Jun 24 ILC Retirement Income Summit - slides.pptxILC- UK
ILC's Retirement Income Summit was hosted by M&G and supported by Canada Life. The event brought together key policymakers, influencers and experts to help identify policy priorities for the next Government and ensure more of us have access to a decent income in retirement.
Contributors included:
Jo Blanden, Professor in Economics, University of Surrey
Clive Bolton, CEO, Life Insurance M&G Plc
Jim Boyd, CEO, Equity Release Council
Molly Broome, Economist, Resolution Foundation
Nida Broughton, Co-Director of Economic Policy, Behavioural Insights Team
Jonathan Cribb, Associate Director and Head of Retirement, Savings, and Ageing, Institute for Fiscal Studies
Joanna Elson CBE, Chief Executive Officer, Independent Age
Tom Evans, Managing Director of Retirement, Canada Life
Steve Groves, Chair, Key Retirement Group
Tish Hanifan, Founder and Joint Chair of the Society of Later life Advisers
Sue Lewis, ILC Trustee
Siobhan Lough, Senior Consultant, Hymans Robertson
Mick McAteer, Co-Director, The Financial Inclusion Centre
Stuart McDonald MBE, Head of Longevity and Democratic Insights, LCP
Anusha Mittal, Managing Director, Individual Life and Pensions, M&G Life
Shelley Morris, Senior Project Manager, Living Pension, Living Wage Foundation
Sarah O'Grady, Journalist
Will Sherlock, Head of External Relations, M&G Plc
Daniela Silcock, Head of Policy Research, Pensions Policy Institute
David Sinclair, Chief Executive, ILC
Jordi Skilbeck, Senior Policy Advisor, Pensions and Lifetime Savings Association
Rt Hon Sir Stephen Timms, former Chair, Work & Pensions Committee
Nigel Waterson, ILC Trustee
Jackie Wells, Strategy and Policy Consultant, ILC Strategic Advisory Board
2. The opinions and views expressed in this
presentation are solely those of the author and
not necessarily those of any organisation
2
Disclaimer
C.Nolan May. 2015
3. 1. Updated NDIC production data (Mar. 2014)
2. Production model corrected* and updated
3. Incorporated comments and corrections
4. Imported well production data into IHS Kingdom
5. Company production data interrogated
3
Updates from previous (Mar. 2014) version
C.Nolan May. 2015* With feedback from Rune Likvern and Enno Peters
4. Introduction
• Current US oil production stands at 9.3M bopd
with 4.5M of this coming from LTO plays. Bakken
oil production (North Dakota only) is currently
1.11M bopd
• The Bakken (orange in the chart on the left) has
recently been supplanted by the Eagle Ford as the
worlds most prolific light tight oil (LTO) play
• Some analysts* suggest the US LTO industry could
enter a downward spiral by Q4 2015. Sustained
low oil prices will result in significantly reduced
cash flow and for some, debt to EBITA ratios that
violate credit covenants. This will in turn
accentuate the decline in investment, production
and hence revenues.
• Bakken economics are one of the most
challenging of the LTO plays at sustained low oil
prices due to the $7-10 discount between ND
light sweet and WTI
• A number of companies have started to divert
capital away from the Bakken to other LTO plays
with higher margins
4
* See Slide 8
C.Nolan May. 2015
5. This study
• The author has no direct interest in any
Bakken Producers – the study is of
personal/academic interest only
• ‘Outsiders’ independent view of the Bakken
• Only public domain data has been used,
including production data from the
regulatory authority; North Dakota Industrial
Commission’s Department of Mineral
Resources (NDIC-DMC)
• Data used to build a Bakken monthly
production model since 2005
• Average initial production (IP) rates are
determined for each months new wells by
varying the IP rate to fit actual data
• Monthly decline curves are derived and
summed to create a total production model
• Bakken production modelled from 2015 to
2020 based on a variety of inputs and
scenarios
C.Nolan May. 2015 5
6. C.Nolan May. 2015
6
• Four ‘engines’ have propelled the
growth of US LTO over the last 10
years including the Bakken;
1. Advances in completion technology
Well bore reservoir contact area increased
100 times in 15 years
2. Better definition of sweet spots
Downspacing, increased well densities
allow better definition of sweet spots
3. High oil prices
Continuous rise in oil prices since late
2008 coincident with 1 and 2
4. Access to capital
Gross US LTO debt of $133bn.
The Four Engines of LTO Growth
Artist rendering of the RS-25 engines power the core stage of NASA's
Space Launch System (SLS) -- NASA's new heavy-lift launch vehicle
7. C.Nolan May. 2015 7
Fracklog and EOG’s Strategy
• By late May, the number of wells waiting to be fracked is expected to breach 1,000*
• Oil producers have up to a year to frack the wells before they must ask state officials
to label them “temporarily abandoned.”
• EOG said in February that it would pare back North Dakota production this year and
focus more on Texas, also partly born from efforts to force oilfield service companies
to cut their own costs.
• EOG will complete c. 25 net new wells in 2015 (v 59 in 2014) most uncompleted wells
in the highly productive Parshall Field
• “These are tremendously productive wells,” said the DMR’s Lynn Helms. EOG is “able
to drill a lot of wells and maintain production and still bank a lot of wells for future
price increases.”
• At the same time, EOG plans to make the Eagle Ford and Permian shale fields in Texas
a core focus this year, aiming to increase the number of Permian wells this year by 53
percent.
• EOG declined to comment beyond the information provided by Lynn Helms.
Ø EOG started to divert capital from the Bakken to other higher return LTO plays back
in Sept. 2014**. EOG is an early mover, first in and first out?
* ND DMR Director’s Cut April 2015 ** See slides 40-47
8. C.Nolan May. 2015 8
Davy Research – LTO Study March 2015
Sourcing capital is vital to meet drilling expenditures
The most important question may not be so much what the breakeven cost of unconventional producers in the US might be
(although this is clearly important, especially in the context of low prices) but rather what the impact on the provision of future
capital is. This question is all the more relevant because the negative free cash flow demonstrated by the aggregate group is based
on periods with far better oil prices ($100-plus) than are currently being realised. Current oil prices will make this situation far
worse, and the only option open to industry is to cut capital expenditure.
The danger for the LTO industry here is that a spiral may develop. Weaker oil prices will de facto reduce cash flow which may
affect debt provision. This will affect physical production and accentuate the decline in revenues. That in turn makes it less
attractive as a borrowing proposition and the cycle continues.
The presence of hedge contracts will shield oil producers from the worst effects of the reduction in prices for a short time. In
terms of the US unconventional industry, there are no hard data as to what the level of protection might be but we suspect it will
begin to peter out in the second half of the year.
Elsewhere in this report, we outline one of the challenges facing the industry at present as the financial funding of the process in
an environment that has not seen a single year of free cash flow from the industry even during periods of high oil prices. We think
this probably means that a higher price is demanded for longer to make investment returns more ostensibly attractive. This
guides our belief that while a wellhead netback* at $80 per barrel (the equivalent of $90 for international pricing), with
controlled operating costs and lower capital per barrel numbers produces returns well in excess of 15%, is probably required.
https://www.davy.ie/research/emailHtm/article.htm?id=oil20150302_27022015.htm&uid=94ec7946-a20e-4efa-8334-
304cf2a65b53&docRef=b0e79c86-f227-4ab0-b6f8-d41a2da83758&jobRef=fad21bd0-a771-40f6-bb34-e66f21f11c0b
*wellhead net back = what company receives (revenue) when realized price has been adjusted for all operational costs (transport, processing, financial
costs, G&A etc), royalties and taxes
9. North Dakota Production, Rig Count and Oil Prices*
ND production peaked in Dec. 2014
at 1.27M bopd and has since fallen
back to 1.11M bopd in Feb. 2015.
*NDIC reported monthly oil price
11. Bakken Geology
The Upper Devonian to Lower Mississippian Bakken
Formation in the Williston Basin is a world-class petroleum
system. Bakken and Three Forks pressures indicate an
inverted continuous system with pressure leaking off at top,
apart from the Parshall pressure cell. Three Forks shows
higher overpressure than Middle Bakken. Good correlation
between hydrocarbon generation, pore-overpressure, inferred
oil saturations and productivity. Sweet spots influenced by
migration and trapping mechanisms (e.g. Sanish/Parshall, Elm
Coulee). Low-productivity areas probably result of migration
(e.g. flanks of Nesson Anticline). Natural fractures play a
significant role for production, but do not define sweet spot
areas. Production increases with more sophisticated
completion technology but geological factors have a larger
impact on productivity than technological improvements*
* Theloy and Sonnenberg 2013 – Search and Discovery article #80332 11C.Nolan May. 2015
12. Current Bakken production is concentrated
in a discrete part of the Williston Basin
(within the purple polygon) mostly in the
sparsely populated state of North Dakota.
The ‘City’ of Dickinson has a population of
20,826 in 2013, and is currently one of the
fastest growing cities in the U.S.
C.Nolan May. 2015 12
13. This is a satellite photo of North Dakota in
2003 prior to the growth in Bakken
production. Note the lights of the main
‘Cities’ and towns in red.
C.Nolan May. 2015 13
14. This is a satellite photo of the same part of
North Dakota in 2013 and illustrates the
vast number of producing wells flaring gas.
Gas flaring restrictions are now being
implemented by the NDIC.
C.Nolan May. 2015 14
15. 30 day initial production
(IP) rates, hotter colours
= higher rates
Bakken – Initial production rates – Drilling Info.*
*From Drillinginfo (Aug. 2014) C.Nolan May. 2015 15
16. ND Bakken IP rates
gridded to create a ‘Heat
Map’* which illustrates
four sweet spots in terms
of counties;
1. Williams
2. Mountrail
3. McKenzie
4. Dunn
Bakken Production Heat Map - RBC
* From RBC capital markets presentation July 2014C.Nolan May. 2015
16
17. 17
Bakken Production Heat Map – this study
Gridded average ND well
production for first 12
months of full production
(post 2007 / pre 2014)
C.Nolan May. 2015
* Average 12 months full production (bbls) between Jan.
2007 and Jan. 2014. Contours are for Top Three Forks (feet)
Well production data from Enno Peters.
18. 18
Operated rigs by location with production heat map
* For May 11th 2015, total = 84
Rig locations colour coded
as per above chart.
Remainder coloured grey
C.Nolan May. 2015
* Average 12 months full production (bbls) between Jan.
2007 and Jan. 2014. Well production data from Enno Peters.
20. • Monthly North Dakota production statistics published by the State
Regulatory Body’s web site; The North Dakota Industrial Commission’s
Department of Mineral Resources: https://www.dmr.nd.gov
• Data exists from 1953, but this study focuses on unconventional production
since 2005 in North Dakota (95% of current production is from the Bakken)
• Currently 12,198 producing wells with more than 900 wells awaiting
completion (c. 7 months of new producers at 2014 rates)
North Dakota Industrial Commission (NDIC)
Department of Mineral Resources (DMR)
21. North Dakota Production*
ND production peaked in Dec. 2014 at 1.27M
bopd has fallen back to 1.11M bopd in Feb.
2015.
The blue line shows the monthly number of net
of new producers (12 month average)
*95% is from the Bakken and Three Forks. 5% (presently 63K bopd) from legacy conventional pools.
12 month moving average of new producers
C.Nolan May. 2015 21
22. North Dakota Production
and key completion milestones*
*from 2014 presentation by Torstein Hole SVP US Onshore, Statoil, United States C.Nolan May. 2015 22
4
5
6
24. C.Nolan May. 2015 24
ND - average yearly decline curves* (2007 – 2014)
Advances in completion technology have led to
a significant improvement in IP rates. Major
step between 2007 and 2008 when application
of lateral isolation using swell packers started
to be applied. Increase in EUR over first year
but minor recent changes thereafter.
*Calculated by the author and based on NDIC production
data supplied by Enno Peters, based on 11,474 wells
25. C.Nolan May. 2015 25
North Dakota – Average 12 month EUR/Well by year*
*Calculated by the author and based on NDIC production
data supplied by Enno Peters, based on 11,474 wells
Advances in completion technology
have led to a significant improvement
in EUR over 12 month period (50%
increase between 2008 and 2014)
26. C.Nolan May. 2015 26*Calculated by the author and based on NDIC production
data supplied by Enno Peters, based on 11,474 wells
North Dakota – Average 5 year EUR/Well by year*
Over a 5 year period increases
are more modest (23% increase
between 2008 and 2014)
27. C.Nolan May. 2015 27*Calculated by the author and based on NDIC production
data supplied by Enno Peters, based on 11,474 wells
North Dakota – Average 10 year EUR/Well by year*
Over a 10 year period increases
are very modest (9% increase
between 2008 and 2014)
28. Modelled ND Well Decline Curves
• Estimate made for missing/incomplete production data* for some of the months
(0-3). Estimate is based on decline curve (iterative process)
• Decline curves based on power equation fitted to actual production data for each
year (2007-2014) for 11,474 wells – see above
• Equations then used for modelled monthly production data (see slides 65-70)
*Calculated by the author and based on NDIC production
data supplied by Enno Peters, based on 11,474 wells
30. What Bakken Producers say about themselves
• Best position in the ‘sweet spots’
• Leading position in the Bakken
• Deep knowledge of the Williston Basin
• Double digit production growth
• Low cost operator
• Using technology to improve returns
• Reduce acquisition-to-value creation time
• Leading capital efficiency
• Using facts and data to optimize
completions
• Recognised as partner of choice
• Showcase their best performing wells
C.Nolan May. 2015 30
31. Top 10 Bakken Producers*
*Based on Q4 2014 production were available in the public domain. EOG, Exxon, Marathon and Conoco do not break out Bakken
Production and are estimates. Smaller company production <50K BOPD not listed. Total displayed = 793K BOPD, 389K BOPD not shown.
Hard to get an accurate picture. EOG,
Exxon, Marathon and Conoco do not break
out Bakken Production and these are
estimates. Some include gas production as
well and quote a boe number.
C.Nolan May. 2015 31
32. C.Nolan May. 2015 32
Bakken as a % of total production*
Oasis, Whiting, Continental and QEP have
the highest proportion of their total
production in the Bakken. Hess has the
largest proportion of the mid-sized
independents.
*Based on Q4 2014 production were available in the public domain. Includes Montana Bakken.
33. C.Nolan May. 2015 33
Dec. 2014 Operated Bakken Production*
*Total production from operated wells on a 100% basis. Estimate are based on well production data supplied by Enno Peters. Top 20
displayed. Most of the top producers have higher 100% operated production than actual working interest production.
A lot of smaller companies (producing <3000
bopd) that are often overlooked. Individually
they are small, but collectively producing
113,000 bopd. Harder to predict what the
‘others’ will do as a group going forward.
34. C.Nolan May. 2015 34
2013/2014 production growth for operated wells
*For operated wells on a 100% basis. Well production data supplied by Enno Peters. Top 10 displayed. Bakken all = average = 34%
35. C.Nolan May. 2015 35
North Dakota Rig Count by Operator*
* For May 11th 2015, total = 84
Exxon and Continental currently
have the most rigs operating. Are
Exxon maintaining/expanding
their rig count?
36. C.Nolan May. 2015
36
Operated rigs by location
* For May 11th 2015, total = 84
Rig locations colour coded
as per above chart.
Remainder coloured grey
37. 37
Operated rigs by location with production heat map
* For May 11th 2015, total = 84
Rig locations colour coded
as per above chart.
Remainder coloured grey
C.Nolan May. 2015
* Average 12 months full production (bbls) between Jan.
2007 and Jan. 2014. Well production data from Enno Peters.
38. C.Nolan May. 2015 38
Operated Bakken Production* 2007 - 2015
*Total production from operated wells on a 100% basis. Well production data supplied by Enno Peters. Top 20 displayed. Most of the top
producers have higher 100% operated production than actual working interest production.
EOG was an earlier mover in the Bakken and
had early significant growth in 2007 and 2008
and again in 2013. Since then it has begun to
focus on other LTO plays with further running
room and better margins.
39. C.Nolan May. 2015 39
Average Well Decline Curves by Company*
*For wells producing between 2007 and 2014 with 12 months of full production – hence staring in month 2. Production is for operated
wells on a 100% basis. Well production data supplied by Enno Peters. Top 10 displayed. Some production data e.g. Conoco missing for
months 2 and 3.
QEP, EOG and Conoco* appear to be in a
‘league of their own’ when it comes to
average production/well. Is this replicated
in IRR per well? Probably a combination of
geology and completion strategy.
41. C.Nolan May. 2015 41
EOG and the Bakken
• EOG discovered the Parshall
field / part of the Bakken in
2006
• Discovery well Parshall 1-36H
was one of the first horizontal
wells in the middle Bakken
• Pressures were so high that it
blew out once the lateral leg
reached 1,200 feet into the
middle member of the
Bakken.
• Flowed at 463 bopd (42OAPI
after simple ‘hail mary’ frac
• Subsequent appraisal wells at
IP rates of up to 2000 bopd
42. C.Nolan May. 2015 42
Parshall 1-36H – where it all started?
Average 12 months full
production (bbls) between Jan.
2007 and Jan. 2014. Well
production data from Enno
Peters. EOG wells only.
43. Parshall 1-36H
Parshall Field area
Average 12 months full production (bbls) between
Jan. 2007 and Jan. 2014. Well production data from
Enno Peters. EOG wells only.
Parshall 1-36H
44. Parshall v Sanish
Average 12 months full production (bbls) between
Jan. 2007 and Jan. 2014. Well production data from
Enno Peters. EOG wells only.
High 12 month rates within
EOG’s Parshall. Horizontals
mostly orientated NW-SE,
moderate (2000-3000’) well
spacing
Average 12 months full production (bbls) between
Jan. 2007 and Jan. 2014. Well production data from
Enno Peters. Whiting wells only.
Moderate 12 month rates within
Sanish area to the west of
Parshall field. Whiting operated
horizontals mostly orientated
ENE, close (1000’ well spacing)
45. C.Nolan May. 2015 45
Parshall is a stratigraphic trap at the edge of
the Basin and sits in a geologically favourable
position; in an area of intense present day oil
generation of the Upper and Lowe Bakken
Shales that result in high pressures. It also sit
in a good migration pathway.
* From New Insights into the Bakken Play: What Factors Control
Production? by Theloy and Sonnenberg, Search and Discovery Oct. 2013
46. C.Nolan May. 2015 46
Parshall Field Production
Produced 104 mmbls of oil since 2006, Significant
drop in production since September 2014 (75-40K
bopd) with BOPD/producers also dropping. Fewer
new wells + some producers shut-in > EOG
reducing investment since drop in oil price.
47. C.Nolan May. 2015 47
EOG’s Strategy
• EOG said in February that it would pare back North Dakota production this year
and focus more on Texas, also partly born from efforts to force oilfield service
companies to cut their own costs.
• EOG will complete c. 25 net new wells in 2015 (v 59 in 2014) most uncompleted
wells in the highly productive Parshall Field
• “These are tremendously productive wells,” said the DMR’s Lynn Helms. EOG is
“able to drill a lot of wells and maintain production and still bank a lot of wells
for future price increases.”
• At the same time, EOG plans to make the Eagle Ford and Permian shale fields in
Texas a core focus this year, aiming to increase the number of Permian wells this
year by 53 percent.
• EOG declined to comment beyond the information provided by Lynn Helms.
Ø EOG started to divert capital from the Bakken to other higher return LTO plays
back in Sept. 2014. EOG is an early mover, first in and first out?
* ND DMR Director’s Cut April 2015
49. North Dakota – Production by County*
Recent production growth
focused in McKenzie, Mountrail,
Dunn and Williams
*Data copied from NDIC monthly reports
which DOES include most recent tight wells
C.Nolan May. 2015 49
50. Mountrail, Dunn, Williams – Average Well Rates*
Average rates now declining/flat in
Mountrail, Dunn and Williams
*Data copied from NDIC monthly reports
which DOES include most recent tight wells
C.Nolan May. 2015 50
Aggressive appraisal drilling of Parshall
‘sweet spot’ in Mountrail in 2007-2009
results in high average producer rates
51. North Dakota – Average Well Rates*
Increases in McKenzie
are offsetting declines in other states
resulting in plateauing of overall ND
rates (black line) at 100bopd
*Data copied from NDIC monthly reports
which DOES include most recent tight wells
51C.Nolan Mar. 2015C.Nolan May. 2015
52. North Dakota Production v New Producers
The number of net new producers (blue
line) swings from month to month (for
reporting and statistical reasons) but the
general trend is increasing
53. North Dakota Production v New Producers
A 12 month moving average of net
new producers (blue line) better
illustrates the trend – up and up.
54. North Dakota – net new producers by County
McKenzie, has been a ‘league of it’s own’ in
terms of net new producers (mirroring
production growth) since 2012
* 6 month moving average of net new producers
*Data copied from NDIC monthly reports which DOES include most recent tight wells
C.Nolan May. 2015
54
56. 2008 Collapse in Oil Prices
The 2008 financial crisis and resulting drop
in oil price from $125 to $30 resulted in a
15% drop in production.
57. 2008 Collapse in Oil Prices
Typically companies have a ‘stock’ of wells
awaiting completion. Companies focused on
completing higher quality producers in their
inventory rather than drilling new wells in 2009.
C.Nolan May. 2015 57
58. 2014 ND v WTI Oil Prices
North Dakota Sweet Crude currently
trading at $17 discount to WTI
C.Nolan May. 2015
58
59. Cost & Capital - Bakken Study
http://www.costandcapital.com/news/107-new-report-bakken-stress-test.html
C.Nolan May. 2015
59
60. C.Nolan May. 2015
60
Whiting Petroleum was forced to offer 35 million shares of common stock It issued senior notes worth $750 million. The
issue was rated Ba2/BB and the coupon for the issue was set at 6.250%. The bonds will mature on April 1, 2023. WLL
plans to use the proceeds of the sales to refinance older debt.
62. Analysis by Cost & Capital Partners LLC
http://www.thebakken.com/articles/978/assessment-reveals-potential-risk-for-some-in-bakken
• Cost & Capital Partners LLC, a management consulting firm, analysed 5 Bakken
“pure play producers” that have more than 90% of their total production coming
out of the Bakken’ Continental Resources, Whiting Petroleum, Emerald Oil, Oasis
Petroleum and Northern Oil & Gas.
• WTI crude price must stay above $45 to $47 for Bakken producers to cover costs,
and growth can’t be sustained unless WTI is above $70 per barrel.
C.Nolan May. 2015 62
63. • On April 29th ND Governor Jack Dalrymple approved a
sweeping reorganization of its oil tax code, cutting the
overall rate and ending a tax break of more than $5 billion
poised to hit in June
• Reduces the oil extraction tax to 5 percent from 6.5
percent starting Jan. 1.
• The bill does not alter North Dakota's 5 percent gross
production tax, a type of property tax on the value of an
extracted mineral. The oil extraction tax is a levy on the
industry itself.
• Effectively, the North Dakota oil tax rate will fall to 10
percent, with the potential for it to hit 11 percent only if
oil prices average above that $90 per barrel for three
consecutive months.
• Many had expected the "large trigger" tax break to hit in
June, but given the recent rise in oil prices, it is no longer a
foregone conclusion. Even if it were to take effect, it would
offer mere months of tax savings to oil producers, several
of whom state the "large trigger" factors little into their
budgets.
Recent Bakken Tax Incentives for Oil Producers
C.Nolan May. 2015 63
64. C.Nolan May. 2015 64
Davy Research – LTO Study March 2015
Sourcing capital is vital to meet drilling expenditures
The most important question may not be so much what the breakeven cost of unconventional producers in the US might
be (although this is clearly important, especially in the context of low prices) but rather what the impact on the provision
of future capital is. This question is all the more relevant because the negative free cash flow demonstrated by the
aggregate group is based on periods with far better oil prices ($100-plus) than are currently being realised. Current oil
prices will make this situation far worse, and the only option open to industry is to cut capital expenditure.
The danger for the LTO industry here is that a spiral may develop. Weaker oil prices will de facto reduce cash flow which
may affect debt provision. This will affect physical production and accentuate the decline in revenues. That in turn
makes it less attractive as a borrowing proposition and the cycle continues.
The presence of hedge contracts will shield oil producers from the worst effects of the reduction in prices for a short
time. In terms of the US unconventional industry, there are no hard data as to what the level of protection might be but
we suspect it will begin to peter out in the second half of the year.
Elsewhere in this report, we outline one of the challenges facing the industry at present as the financial funding of the
process in an environment that has not seen a single year of free cash flow from the industry even during periods of high
oil prices. We think this probably means that a higher price is demanded for longer to make investment returns more
ostensibly attractive. This guides our belief that while a wellhead netback at $80 per barrel (the equivalent of $90 for
international pricing), with controlled operating costs and lower capital per barrel numbers produces returns well in
excess of 15%, this is probably required.
https://www.davy.ie/research/emailHtm/article.htm?id=oil20150302_27022015.htm&uid=94ec7946-a20e-4efa-8334-
304cf2a65b53&docRef=b0e79c86-f227-4ab0-b6f8-d41a2da83758&jobRef=fad21bd0-a771-40f6-bb34-e66f21f11c0b
66. North Dakota Production Model – this study
• ND production data since 2005
• Each months new production is modelled with a
decline curve based on a monthly average IP
value and a power law function (see slide 25)
• Future production modelled on the following;
inputs (shown in red on the table on the left);
1. Number of new producers per months
2. The change of the number of new producers
3. Average well IP rate
4. The change in the IP rate
5. Fraction of future production not shut-in
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67. North Dakota Production – possible outcomes in 2015
• The number of new completions in North Dakota
dropped to 63 in January and 43 in February
2015
• The updated model* in this study suggests 119
new producers/month are required for 2015 to
maintain North Dakota YE 2015 production at
2014 levels i.e. 1.23M bopd – this is comparable
to NDIC estimate (see slide 71)
• Assuming no new completions / producers for
the remainder of 2015 then North Dakota
production would decline by 43% by 2015 YE to
0.92M BOPD
• Assuming the number of new completions stays
at 52/month (i.e. Jan/Feb levels) for the
remainder of 2015 then, North Dakota 2015 YE
production would decline by 27% to 0.90M
BOPD
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C.Nolan May. 2015
* With feedback from Rube Likvern and Enno Peters. By
comparison Rune Likvern predicts a 16% decline in 2015 YE
Bakken/Three Forks production if 52/producers month are
added and 28% if no producers are added.
68. 68
March 2015 onwards - 52 new producers/month
This study suggests an average of 52
new producers/month from now on
(current levels) would result in a 27%
drop in North Dakota YE production.
69. 69
2015 – Average of 119 new producers/month
This study suggests an average of 119
new producers/month required to
maintain 2015 YE production at same
level as 2014 i.e. 33% less producers.
70. 70
March 2015 onwards - 0 new producers/month
This study suggests zero producers
from now on would result in a 43%
reduction in 2015 YE production.
71. The NDIC Director’s Cut – April 2015
From the Director’s Cut (Director of NDIC – Lynn Helms) on 14/04/15
Today’s rig count is 91 (lowest since January 2010)(all-time high was 218 on 5/29/2012)
The statewide rig count is down 58% from the high and in the five most active counties
The drilling rig count dropped 27 from January to February, 25 more from February to
March, and has since fallen 17 more from March to today. The number of well
completions dropped from 63(final) in January to 42(preliminary) in February. Oil price
is by far the biggest driver behind the slow-down, with operators reporting postponed
completion work to avoid high initial oil production at very low prices and to achieve
NDIC gas capture goals.
The total net number of net new producers increased by 1 in February. That means 62 wells have been
shut-in.
At the end of February there were an estimated 900 wells waiting on completion
Services1, an increase of 75. Comparing December, January, and February completions
and production increases results in a requirement of 110-120 completions per month to
maintain production near 1.2 million barrels per day.
C.Nolan May. 2015 71
72. Conclusions
• The Bakken bubble has burst, production is now falling
• The updated model in this study suggests 119 new producers/month are required
for 2015 to maintain North Dakota YE 2015 production at 2014 levels i.e. 1.23M
bopd – this is comparable to NDIC and other estimates
• Assuming the number of new producers stays at 52/month (i.e. Jan/Feb levels)
for the remainder of 2015 then, North Dakota 2015 YE production would decline
by 27% to 0.90M BOPD
• Some analysts suggest the LTO industry could enter a downward spiral by Q4
2015, sustained by weaker oil prices that will result in significantly reduced cash
flows and for some, debt to EBITA ratios that violate credit covenants. This will in
turn accentuate the decline of production and revenues. Some LTO plays (such as
the Bakken) would then become a less attractive proposition as the cycle
accentuates
• Bakken economics are one of the most challenging of the LTO plays at sustained
low oil prices due to the $7-10 discount between ND light sweet and WTI
• Some companies are already diverting capital from the Bakken to other LTO plays
with higher margins
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C.Nolan May. 2015