The document discusses forward-looking statements and cautions that actual results may differ substantially from estimates. It provides an overview of Arena Energy, including its enterprise value, asset base in the Midland Basin with over 1 billion barrels of estimated resource potential, and capital program focused on flexibility and returns. Arena has a low-risk, oil-rich asset base and a strong financial and liquidity position to withstand commodity price volatility.
- The document provides financial and operational highlights for Arex Energy's fourth quarter and full-year 2014 results.
- Key highlights include record revenues and net income for the full year, strong production and reserve growth, capital expenditures below budget, and a flexible capital program for 2015 focused on financial discipline and returns.
- Operational results demonstrated continued strong well performance and recoveries from the Wolfcamp shale play, Arex's core asset.
Approach Resources Inc. presented at the Goldman Sachs Global Energy Conference in January 2014. The presentation provided an overview of Approach Resources' asset base in the Permian Basin, which includes 166,000 gross acres and over 1 billion barrels of estimated oil and gas resources. The company discussed its track record of reserve and production growth through horizontal drilling in the Wolfcamp shale play. Approach Resources outlined its 2014 capital program, which includes drilling 75% more horizontal Wolfcamp wells compared to 2013 with the goal of 40% production growth. The company also highlighted ongoing efforts to reduce well costs and increase drilling efficiencies through pad development and infrastructure investments.
- The company reported its first quarter 2014 results, with key highlights including a 42% year-over-year increase in production to 11.9 million barrels of oil equivalent per day and record quarterly EBITDAX of $42.7 million, up 75% from the previous year.
- In the quarter the company drilled 16 horizontal wells and completed 19 wells in its Wolfcamp shale play, with an average initial production of 743 barrels of oil equivalent per day across wells completed.
- The financial position of the company remains strong with $354 million in liquidity as of the end of the quarter and an undrawn borrowing base of $350 million.
This document discusses an energy conference presentation by AREX, an oil and gas company. Key points:
- AREX has 163,000 acres in the Permian Basin with an estimated 1 billion barrels of oil equivalent of unrisked resource potential from the Wolfcamp shale play.
- AREX is running 3 horizontal drilling rigs and plans to drill 70 wells in 2014 to develop the Wolfcamp shale, with a goal of 40% production growth.
- Well results have tracked or exceeded AREX's 450 Mboe type curve, with a recent Wolfcamp C well averaging 970 boe/d. Infrastructure investments aim to reduce costs and enable large-scale development.
- The company reported results for the second quarter of 2015, with production increasing 8% year-over-year to 15.3 MBoe/d and cash operating costs decreasing 26% to $11.02/Boe.
- The company drilled 9 and completed 10 Wolfcamp wells in the quarter and continued reducing well costs, with an average of $4.5 million per well compared to $5.5 million in 2014.
- Financial highlights included $32.6 million in EBITDAX, capital expenditures of $56.9 million (mostly for drilling and completions), and liquidity of $193 million as of June 30th.
- Third Quarter 2014 Results presentation by AREX discussing financial and operational results
- Produced 14.2 MBoe/d in 3Q14, a 61% increase from the prior year, maintaining low well costs of $5.5 million per well
- Drilled 18 horizontal wells in the Wolfcamp shale play and completed 16 wells, achieving a type curve IP rate of 746 Boe/d
- Achieved record quarterly EBITDAX of $50.7 million and revenues of $68.1 million, maintaining a strong financial position with $362 million in liquidity
The document discusses oil prices and activity in the Southern Midland Basin. It notes that AREX has 134,000 net acres in the basin with an estimated 1 billion barrels of oil equivalent of unrisked resource potential from the Wolfcamp shale. AREX has implemented water recycling facilities to reduce drilling and completion costs by $450,000 per well and lower operating expenses. At their current drilling and completion cost of $7 million per well, AREX wells in the Wolfcamp have a type curve estimated ultimate recovery of 510 thousand barrels of oil equivalent and an internal rate of return above 40% at $60 oil.
EOG Resources 4Q 2015 Quarterly Presentation Investor RelationsMichelle Smith
EOG Resources provides key information about its operations and financial results. It has over 3,200 premium well locations with over 2 billion barrels of oil equivalent of resource potential. EOG reduced capital spending 44% year-over-year while maintaining flat US oil production in 2015. It aims to generate at least 30% returns on investment at $40/barrel oil from its shifting focus to premium locations with over 10 years of sustainable inventory growth.
- The document provides financial and operational highlights for Arex Energy's fourth quarter and full-year 2014 results.
- Key highlights include record revenues and net income for the full year, strong production and reserve growth, capital expenditures below budget, and a flexible capital program for 2015 focused on financial discipline and returns.
- Operational results demonstrated continued strong well performance and recoveries from the Wolfcamp shale play, Arex's core asset.
Approach Resources Inc. presented at the Goldman Sachs Global Energy Conference in January 2014. The presentation provided an overview of Approach Resources' asset base in the Permian Basin, which includes 166,000 gross acres and over 1 billion barrels of estimated oil and gas resources. The company discussed its track record of reserve and production growth through horizontal drilling in the Wolfcamp shale play. Approach Resources outlined its 2014 capital program, which includes drilling 75% more horizontal Wolfcamp wells compared to 2013 with the goal of 40% production growth. The company also highlighted ongoing efforts to reduce well costs and increase drilling efficiencies through pad development and infrastructure investments.
- The company reported its first quarter 2014 results, with key highlights including a 42% year-over-year increase in production to 11.9 million barrels of oil equivalent per day and record quarterly EBITDAX of $42.7 million, up 75% from the previous year.
- In the quarter the company drilled 16 horizontal wells and completed 19 wells in its Wolfcamp shale play, with an average initial production of 743 barrels of oil equivalent per day across wells completed.
- The financial position of the company remains strong with $354 million in liquidity as of the end of the quarter and an undrawn borrowing base of $350 million.
This document discusses an energy conference presentation by AREX, an oil and gas company. Key points:
- AREX has 163,000 acres in the Permian Basin with an estimated 1 billion barrels of oil equivalent of unrisked resource potential from the Wolfcamp shale play.
- AREX is running 3 horizontal drilling rigs and plans to drill 70 wells in 2014 to develop the Wolfcamp shale, with a goal of 40% production growth.
- Well results have tracked or exceeded AREX's 450 Mboe type curve, with a recent Wolfcamp C well averaging 970 boe/d. Infrastructure investments aim to reduce costs and enable large-scale development.
- The company reported results for the second quarter of 2015, with production increasing 8% year-over-year to 15.3 MBoe/d and cash operating costs decreasing 26% to $11.02/Boe.
- The company drilled 9 and completed 10 Wolfcamp wells in the quarter and continued reducing well costs, with an average of $4.5 million per well compared to $5.5 million in 2014.
- Financial highlights included $32.6 million in EBITDAX, capital expenditures of $56.9 million (mostly for drilling and completions), and liquidity of $193 million as of June 30th.
- Third Quarter 2014 Results presentation by AREX discussing financial and operational results
- Produced 14.2 MBoe/d in 3Q14, a 61% increase from the prior year, maintaining low well costs of $5.5 million per well
- Drilled 18 horizontal wells in the Wolfcamp shale play and completed 16 wells, achieving a type curve IP rate of 746 Boe/d
- Achieved record quarterly EBITDAX of $50.7 million and revenues of $68.1 million, maintaining a strong financial position with $362 million in liquidity
The document discusses oil prices and activity in the Southern Midland Basin. It notes that AREX has 134,000 net acres in the basin with an estimated 1 billion barrels of oil equivalent of unrisked resource potential from the Wolfcamp shale. AREX has implemented water recycling facilities to reduce drilling and completion costs by $450,000 per well and lower operating expenses. At their current drilling and completion cost of $7 million per well, AREX wells in the Wolfcamp have a type curve estimated ultimate recovery of 510 thousand barrels of oil equivalent and an internal rate of return above 40% at $60 oil.
EOG Resources 4Q 2015 Quarterly Presentation Investor RelationsMichelle Smith
EOG Resources provides key information about its operations and financial results. It has over 3,200 premium well locations with over 2 billion barrels of oil equivalent of resource potential. EOG reduced capital spending 44% year-over-year while maintaining flat US oil production in 2015. It aims to generate at least 30% returns on investment at $40/barrel oil from its shifting focus to premium locations with over 10 years of sustainable inventory growth.
1) The company reported first quarter 2015 results with production of 14.3 MBoe/d, a 21% increase over the previous year. Operating costs continued to improve with cash operating costs of $12.32/Boe, down 27% from the previous year.
2) The company drilled 8 and completed 13 horizontal wells in the Wolfcamp B and C zones, with average initial production of 723 Boe/d.
3) The company's water recycling facility became fully operational in March 2015 and is expected to reduce drilling and completion costs by $450k per well and lower operating expenses.
- The company has a high-quality asset base in the Permian Basin with over 115 million barrels of oil equivalent in proved reserves and over 1 billion barrels of oil equivalent in estimated resource potential from over 1,000 identified drilling locations.
- Production has grown significantly in recent years through horizontal drilling in the Wolfcamp shale, with a 19% increase in 2013 and a target of 40% growth in 2014.
- Oil reserves and production have increased substantially, with oil reserves up over 10 times since 2009 and oil production up nearly 50% in 2013 alone, driven by successful horizontal Wolfcamp development.
The presentation discusses an investor presentation by an oil and gas company. It contains forward-looking statements about future plans and estimates. The company has 162,000 gross acres in the Permian Basin with an estimated 1 billion barrels of oil equivalent of unrisked resource potential. It plans to drill 70 wells in 2014 with a $400 million capital budget as part of developing its Wolfcamp shale oil resource play.
The document discusses AREX's 2014 development plan for its Wolfcamp shale oil resource play in the Permian Basin. Key points include:
- 2014 capital budget of $400 million, 95% directed to horizontal Wolfcamp drilling with 3 rigs
- Targeting the Wolfcamp A, B, and C zones with pad drilling and stacked laterals
- Expecting 45% production growth in 2014 to 4.95 MMBoe with a 70% liquids mix
- Horizontal Wolfcamp well costs estimated at $5.5 million
The plan focuses on developing AREX's large Wolfcamp shale oil resource potential through horizontal drilling and pad development while maintaining flexibility given commodity price uncertainty
The document provides an overview of the company's fourth quarter and full-year 2015 results. Some key points:
- Production for Q4 was 1.33 MMBoe and 5.53 MMBoe for the full year, in line with guidance. No capital expenditures were incurred in Q4 due to low commodity prices.
- Proved reserves increased 14% year-over-year to 166.6 MMBoe with a PV-10 of $504 million. Drilling replaced 603% of production at a drill-bit F&D cost of $4.32/Boe.
- The company has $177 million in liquidity and reduced total debt from $515.6 million to $
The document discusses AREX's fourth quarter and full-year 2013 results. Key points include:
- Production for 4Q13 exceeded guidance at 11.3 MBoe/d and was 46% oil.
- Proved reserves increased 20% year-over-year to 114.7 MMBoe, with growth driven by the Wolfcamp shale play.
- The company plans to drill approximately 70 horizontal Wolfcamp wells in 2014 with a 3-rig program, targeting 40% production growth.
The document provides an operational and financial summary for the 4th quarter of 2013. It discusses the company's asset base which includes over 163,000 gross acres and over 1 billion barrels of estimated oil and gas resources. The company is accelerating development through running 3 horizontal drilling rigs and plans to drill 70 wells in 2014. It highlights the company's track record of reserve and production growth, driven by drilling in the Wolfcamp shale play. Charts show proved reserves increasing 20% in 2013 to over 114 million barrels of oil equivalent and oil production up 49% from 2012. The company aims to grow production 40% in 2014 through increased horizontal drilling in the Wolfcamp.
This document provides contact information for Devon Energy's investor relations team. It also contains standard legal disclaimers about forward-looking statements and the use of non-GAAP financial measures in company presentations. The rest of the document summarizes Devon's operations, highlighting its high-quality asset portfolio, strong financial position, and focus on capital discipline and returns. It provides details on key growth opportunities in the STACK and Delaware Basin plays.
The document summarizes Arex Energy's second quarter 2016 results. It discusses:
- Low operating costs of $4.56 per barrel of oil equivalent and record low drilling and completion costs of $3.7 million per well.
- Average production of 12.6 thousand barrels of oil equivalent per day, exceeding guidance. New wells are outperforming type curves.
- Revenues of $22.4 million and EBITDAX of $13.7 million. Capital expenditures were $6.9 million, aligned with cash flow. The company has $51 million in liquidity.
- The company reported third quarter 2015 results with record production of 16.6 MBoe/d, up 17% year-over-year.
- Operating costs continued to decrease, with lease operating expenses of $5.04/Boe, a 14% reduction from the prior year.
- The company drilled 4 wells and completed 5 wells in the Wolfcamp B-C zones, with initial production averaging 931 Boe/d.
AREX 2016 Wells Fargo West Coast Energy PresentationApproachResources
The document discusses AREX's operations in the Permian Basin, including its 167 million barrels of oil equivalent proved reserves, low cost structure, extensive drilling inventory, and significant resource potential from the Wolfcamp shale play. AREX has implemented enhanced completion designs that outperform type curves and reduced its lease operating expenses through the use of a centralized water recycling facility that lowers drilling and completion costs by reusing flowback and produced water.
- The company reported its second quarter 2014 results, with production increasing 58% year-over-year to 14.1 thousand barrels of oil equivalent per day. Revenues increased 74% to $73.4 million.
- In the quarter the company drilled and completed 16 horizontal wells in the Wolfcamp shale formation, with an average initial production of 556 barrels of oil equivalent per day.
- The company maintained its production and expense guidance for 2014, expecting total production of 4.95 million barrels of oil equivalent with operating expenses between $5-6 per barrel of oil equivalent.
- AREX reported strong third quarter 2014 results, with production up 61% year-over-year to 14.2 million barrels of oil equivalent per day and EBITDAX reaching a record high of $50.7 million, up 60% year-over-year.
- In the third quarter, AREX drilled 18 and completed 16 horizontal wells in the Wolfcamp shale play, maintaining best-in-class well costs of $5.5 million per well on average.
- Initial production from recent wells continues to track at or above AREX's 450 thousand barrels of oil equivalent type curve, and an Elliott C bench well expanded the potential of the Wolfcamp development to the east.
This document contains forward-looking statements regarding activities, events, developments, and financial results that could differ from actual results. It discusses the company's Wolfcamp shale resource play, estimated resource potential, drilling locations, capital expenditures, well results, and guidance. The document cautions that estimates of unproved reserves and resource potential could change significantly as additional data becomes available. It provides an overview of the company, including its asset base, reserve growth history, second quarter 2015 highlights showing production and cost improvements, and discussion of its low-cost structure enabled by infrastructure like its water recycling facility.
NYSE:DNR is an oil and gas company focused on CO2 enhanced oil recovery. It owns over 1,100 miles of CO2 pipelines and has significant CO2 reserves. Its core assets have long lives and large estimated original oil in place that could potentially be recovered through CO2 flooding. The company is reducing costs and debt in response to low oil prices while continuing to optimize its operations and preserve liquidity. It provided 2016 capital and production guidance focused on its low decline, oil-weighted assets.
PVA is an E&P company focused on growing its oil and NGL production and reserves. It has successfully transitioned to focus on oil-rich plays like the Eagle Ford shale through acquisitions and drilling. This strategy has increased revenues and cash flows as oil and NGL production rose 192% from 2010 to 2011. PVA will continue developing the Eagle Ford and testing new oil prospects while retaining gas assets for potential future price increases to further optimize its portfolio.
- PVA is a small-cap E&P company focused on oil and liquids-rich plays like the Eagle Ford Shale with excellent drilling results to date. PVA has been executing a strategy to transition from natural gas to growing oil and NGL production and reserves.
- PVA appears undervalued relative to peers based on trading at a discount to peer multiples of 2012 estimated cash flow per share and EBITDAX, and its enterprise value is only modestly above its year-end 2011 proved reserve value.
- PVA has options to build financial liquidity in 2012 including potential asset sales, reducing capital expenditures given its focus on oil and liquids plays, and continuing its active hedging program.
- EOG Resources Inc. acquired Yates Petroleum Corporation, adding 1.6 million net acres across multiple regions for $2.5 billion.
- The acquisition significantly increases EOG's core positions in the Delaware Basin, Powder River Basin, and Northwest Shelf, providing over 1,700 additional premium drilling locations.
- The high quality acreage acquired from Yates is estimated to contain over 1.6 billion barrels of oil equivalent in net resource potential, and will enable expanded development and exploration across EOG's portfolio.
This presentation discusses an oil and gas company's Wolfcamp shale resource play in the Permian Basin. Key points include:
- The company has 160,000 gross acres and estimates over 1 billion barrels of unrisked oil resource potential from the multi-bench Wolfcamp shale.
- The 2014 capital budget of $400 million will fund a 3-rig horizontal drilling program targeting the Wolfcamp A, B and C zones, with an aim to drill around 70 wells.
- The development plan focuses on pad drilling, stacked laterals, and infrastructure to reduce costs and drive projected 45% production growth in 2014 to nearly 5 million barrels of oil-equivalent.
This document provides an investor presentation for Devon Energy Corporation (DVN). It summarizes DVN's operations in the STACK and Delaware Basins, where it has over 30,000 potential locations across the two plays. DVN is focused on expanding high-margin production from these core areas to drive rapid cash flow growth. The presentation outlines DVN's strategic vision to optimize its portfolio and balance sheet through 2020 to improve returns and deliver top-tier value to shareholders.
The document provides an operational and financial summary for the 4th quarter of 2013. It discusses the company's asset base which includes over 163,000 gross acres and over 1 billion barrels of estimated oil and gas resources. The company is accelerating development through running 3 horizontal drilling rigs and plans to drill 70 wells in 2014. It highlights the company's track record of reserve and production growth, driven by drilling in the Wolfcamp shale play. Charts show proved reserves increasing 20% in 2013 to over 114 million barrels of oil equivalent and oil production up 49% from the prior year. The company aims to grow production 40% in 2014 through increased horizontal drilling in the Wolfcamp.
- The company reported its second quarter 2014 results with increased production and revenue.
- Production for the quarter averaged 14.1 MBoe/d, a 58% increase year-over-year.
- The company drilled and completed 16 horizontal wells in the Wolfcamp shale play and realized an average IP rate of 556 Boe/d.
- Guidance for 2014 was increased with expected production of 4,950 MBoe and capital expenditures of $400 million to drill 70 horizontal wells.
1) The company reported first quarter 2015 results with production of 14.3 MBoe/d, a 21% increase over the previous year. Operating costs continued to improve with cash operating costs of $12.32/Boe, down 27% from the previous year.
2) The company drilled 8 and completed 13 horizontal wells in the Wolfcamp B and C zones, with average initial production of 723 Boe/d.
3) The company's water recycling facility became fully operational in March 2015 and is expected to reduce drilling and completion costs by $450k per well and lower operating expenses.
- The company has a high-quality asset base in the Permian Basin with over 115 million barrels of oil equivalent in proved reserves and over 1 billion barrels of oil equivalent in estimated resource potential from over 1,000 identified drilling locations.
- Production has grown significantly in recent years through horizontal drilling in the Wolfcamp shale, with a 19% increase in 2013 and a target of 40% growth in 2014.
- Oil reserves and production have increased substantially, with oil reserves up over 10 times since 2009 and oil production up nearly 50% in 2013 alone, driven by successful horizontal Wolfcamp development.
The presentation discusses an investor presentation by an oil and gas company. It contains forward-looking statements about future plans and estimates. The company has 162,000 gross acres in the Permian Basin with an estimated 1 billion barrels of oil equivalent of unrisked resource potential. It plans to drill 70 wells in 2014 with a $400 million capital budget as part of developing its Wolfcamp shale oil resource play.
The document discusses AREX's 2014 development plan for its Wolfcamp shale oil resource play in the Permian Basin. Key points include:
- 2014 capital budget of $400 million, 95% directed to horizontal Wolfcamp drilling with 3 rigs
- Targeting the Wolfcamp A, B, and C zones with pad drilling and stacked laterals
- Expecting 45% production growth in 2014 to 4.95 MMBoe with a 70% liquids mix
- Horizontal Wolfcamp well costs estimated at $5.5 million
The plan focuses on developing AREX's large Wolfcamp shale oil resource potential through horizontal drilling and pad development while maintaining flexibility given commodity price uncertainty
The document provides an overview of the company's fourth quarter and full-year 2015 results. Some key points:
- Production for Q4 was 1.33 MMBoe and 5.53 MMBoe for the full year, in line with guidance. No capital expenditures were incurred in Q4 due to low commodity prices.
- Proved reserves increased 14% year-over-year to 166.6 MMBoe with a PV-10 of $504 million. Drilling replaced 603% of production at a drill-bit F&D cost of $4.32/Boe.
- The company has $177 million in liquidity and reduced total debt from $515.6 million to $
The document discusses AREX's fourth quarter and full-year 2013 results. Key points include:
- Production for 4Q13 exceeded guidance at 11.3 MBoe/d and was 46% oil.
- Proved reserves increased 20% year-over-year to 114.7 MMBoe, with growth driven by the Wolfcamp shale play.
- The company plans to drill approximately 70 horizontal Wolfcamp wells in 2014 with a 3-rig program, targeting 40% production growth.
The document provides an operational and financial summary for the 4th quarter of 2013. It discusses the company's asset base which includes over 163,000 gross acres and over 1 billion barrels of estimated oil and gas resources. The company is accelerating development through running 3 horizontal drilling rigs and plans to drill 70 wells in 2014. It highlights the company's track record of reserve and production growth, driven by drilling in the Wolfcamp shale play. Charts show proved reserves increasing 20% in 2013 to over 114 million barrels of oil equivalent and oil production up 49% from 2012. The company aims to grow production 40% in 2014 through increased horizontal drilling in the Wolfcamp.
This document provides contact information for Devon Energy's investor relations team. It also contains standard legal disclaimers about forward-looking statements and the use of non-GAAP financial measures in company presentations. The rest of the document summarizes Devon's operations, highlighting its high-quality asset portfolio, strong financial position, and focus on capital discipline and returns. It provides details on key growth opportunities in the STACK and Delaware Basin plays.
The document summarizes Arex Energy's second quarter 2016 results. It discusses:
- Low operating costs of $4.56 per barrel of oil equivalent and record low drilling and completion costs of $3.7 million per well.
- Average production of 12.6 thousand barrels of oil equivalent per day, exceeding guidance. New wells are outperforming type curves.
- Revenues of $22.4 million and EBITDAX of $13.7 million. Capital expenditures were $6.9 million, aligned with cash flow. The company has $51 million in liquidity.
- The company reported third quarter 2015 results with record production of 16.6 MBoe/d, up 17% year-over-year.
- Operating costs continued to decrease, with lease operating expenses of $5.04/Boe, a 14% reduction from the prior year.
- The company drilled 4 wells and completed 5 wells in the Wolfcamp B-C zones, with initial production averaging 931 Boe/d.
AREX 2016 Wells Fargo West Coast Energy PresentationApproachResources
The document discusses AREX's operations in the Permian Basin, including its 167 million barrels of oil equivalent proved reserves, low cost structure, extensive drilling inventory, and significant resource potential from the Wolfcamp shale play. AREX has implemented enhanced completion designs that outperform type curves and reduced its lease operating expenses through the use of a centralized water recycling facility that lowers drilling and completion costs by reusing flowback and produced water.
- The company reported its second quarter 2014 results, with production increasing 58% year-over-year to 14.1 thousand barrels of oil equivalent per day. Revenues increased 74% to $73.4 million.
- In the quarter the company drilled and completed 16 horizontal wells in the Wolfcamp shale formation, with an average initial production of 556 barrels of oil equivalent per day.
- The company maintained its production and expense guidance for 2014, expecting total production of 4.95 million barrels of oil equivalent with operating expenses between $5-6 per barrel of oil equivalent.
- AREX reported strong third quarter 2014 results, with production up 61% year-over-year to 14.2 million barrels of oil equivalent per day and EBITDAX reaching a record high of $50.7 million, up 60% year-over-year.
- In the third quarter, AREX drilled 18 and completed 16 horizontal wells in the Wolfcamp shale play, maintaining best-in-class well costs of $5.5 million per well on average.
- Initial production from recent wells continues to track at or above AREX's 450 thousand barrels of oil equivalent type curve, and an Elliott C bench well expanded the potential of the Wolfcamp development to the east.
This document contains forward-looking statements regarding activities, events, developments, and financial results that could differ from actual results. It discusses the company's Wolfcamp shale resource play, estimated resource potential, drilling locations, capital expenditures, well results, and guidance. The document cautions that estimates of unproved reserves and resource potential could change significantly as additional data becomes available. It provides an overview of the company, including its asset base, reserve growth history, second quarter 2015 highlights showing production and cost improvements, and discussion of its low-cost structure enabled by infrastructure like its water recycling facility.
NYSE:DNR is an oil and gas company focused on CO2 enhanced oil recovery. It owns over 1,100 miles of CO2 pipelines and has significant CO2 reserves. Its core assets have long lives and large estimated original oil in place that could potentially be recovered through CO2 flooding. The company is reducing costs and debt in response to low oil prices while continuing to optimize its operations and preserve liquidity. It provided 2016 capital and production guidance focused on its low decline, oil-weighted assets.
PVA is an E&P company focused on growing its oil and NGL production and reserves. It has successfully transitioned to focus on oil-rich plays like the Eagle Ford shale through acquisitions and drilling. This strategy has increased revenues and cash flows as oil and NGL production rose 192% from 2010 to 2011. PVA will continue developing the Eagle Ford and testing new oil prospects while retaining gas assets for potential future price increases to further optimize its portfolio.
- PVA is a small-cap E&P company focused on oil and liquids-rich plays like the Eagle Ford Shale with excellent drilling results to date. PVA has been executing a strategy to transition from natural gas to growing oil and NGL production and reserves.
- PVA appears undervalued relative to peers based on trading at a discount to peer multiples of 2012 estimated cash flow per share and EBITDAX, and its enterprise value is only modestly above its year-end 2011 proved reserve value.
- PVA has options to build financial liquidity in 2012 including potential asset sales, reducing capital expenditures given its focus on oil and liquids plays, and continuing its active hedging program.
- EOG Resources Inc. acquired Yates Petroleum Corporation, adding 1.6 million net acres across multiple regions for $2.5 billion.
- The acquisition significantly increases EOG's core positions in the Delaware Basin, Powder River Basin, and Northwest Shelf, providing over 1,700 additional premium drilling locations.
- The high quality acreage acquired from Yates is estimated to contain over 1.6 billion barrels of oil equivalent in net resource potential, and will enable expanded development and exploration across EOG's portfolio.
This presentation discusses an oil and gas company's Wolfcamp shale resource play in the Permian Basin. Key points include:
- The company has 160,000 gross acres and estimates over 1 billion barrels of unrisked oil resource potential from the multi-bench Wolfcamp shale.
- The 2014 capital budget of $400 million will fund a 3-rig horizontal drilling program targeting the Wolfcamp A, B and C zones, with an aim to drill around 70 wells.
- The development plan focuses on pad drilling, stacked laterals, and infrastructure to reduce costs and drive projected 45% production growth in 2014 to nearly 5 million barrels of oil-equivalent.
This document provides an investor presentation for Devon Energy Corporation (DVN). It summarizes DVN's operations in the STACK and Delaware Basins, where it has over 30,000 potential locations across the two plays. DVN is focused on expanding high-margin production from these core areas to drive rapid cash flow growth. The presentation outlines DVN's strategic vision to optimize its portfolio and balance sheet through 2020 to improve returns and deliver top-tier value to shareholders.
The document provides an operational and financial summary for the 4th quarter of 2013. It discusses the company's asset base which includes over 163,000 gross acres and over 1 billion barrels of estimated oil and gas resources. The company is accelerating development through running 3 horizontal drilling rigs and plans to drill 70 wells in 2014. It highlights the company's track record of reserve and production growth, driven by drilling in the Wolfcamp shale play. Charts show proved reserves increasing 20% in 2013 to over 114 million barrels of oil equivalent and oil production up 49% from the prior year. The company aims to grow production 40% in 2014 through increased horizontal drilling in the Wolfcamp.
- The company reported its second quarter 2014 results with increased production and revenue.
- Production for the quarter averaged 14.1 MBoe/d, a 58% increase year-over-year.
- The company drilled and completed 16 horizontal wells in the Wolfcamp shale play and realized an average IP rate of 556 Boe/d.
- Guidance for 2014 was increased with expected production of 4,950 MBoe and capital expenditures of $400 million to drill 70 horizontal wells.
The document summarizes AREX's first quarter 2016 results. It discusses:
- Drilling of 4 Wolfcamp wells on time and on budget during the quarter with no completions.
- Production of 1,165 Mboe during the quarter as no new wells were completed.
- EBITDAX of $8.7 million and cash flow from operations of $5.3 million for the quarter. Capital expenditures were $4.9 million.
- The company maintains a strong financial position and liquidity of $54 million providing flexibility for its 2016 plan.
Victory Energy (VYEY) Investor PresentationDerek Gradwell
Victory Energy Corporation is a public oil and gas exploration company focused on development in the Permian Basin. The company owns interests in several producing properties in the basin. Victory plans to deploy $15 million in 2014 for drilling, completions, and acquisitions to increase production and proved reserves. The goal is to achieve over 30 million barrels of proved reserves by year-end and increase revenue to over $1 million. A key focus is the recently acquired 4,050 acre Fairway project, which Victory expects can generate a 60% internal rate of return over three years of planned drilling.
EnerCom’s The Oil and Gas Conference 21 PresentationApproachResources
The document discusses forward-looking statements and provides cautionary statements regarding oil and gas quantities estimates. It then provides an overview of the company, noting it has an enterprise value of $588 million with 167 million barrels of oil equivalent of proved reserves, of which 63% are liquids. It also discusses the company's Permian Basin assets which include 139,000 gross acres and an estimated 1 billion barrels of oil equivalent of unrisked resource potential from 1,800 identified drilling locations.
This document provides an overview of Penn Virginia Corporation (PVA), an independent oil and gas exploration and production company. PVA has successfully transitioned its portfolio towards oil and natural gas liquids (NGLs) rich plays like the Eagle Ford Shale. This has driven significant growth in production, revenues, cash flows and margins. However, PVA currently trades at a discount to its peers on earnings and cash flow multiples despite its improved portfolio and growth outlook. Management plans to further build financial liquidity in 2012 through additional asset sales, reducing capital expenditures, and continuing its active hedging program.
This investor presentation provides an overview of Penn Virginia Corporation (PVA):
1) PVA has transitioned to focus on oil and liquids-rich plays like the Eagle Ford Shale, growing oil production over 250% since 2010.
2) The company is executing a strategy of continued drilling in the Eagle Ford with an inventory of up to 250 well locations, while maintaining gas assets for potential future price recovery.
3) Challenges include the capital intensity of the industry and building financial liquidity, which PVA is addressing through asset sales and reducing spending and dividends.
Approach Resources Inc. reported third quarter 2013 results. Key highlights included accelerating their completion pace and drilling efficiencies, driving down well costs below $5.5 million per well on average, and delivering strong initial production rates from Wolfcamp B and C wells across their acreage, with some wells producing over 1,000 barrels of oil equivalent per day. Approach is on track to increase production 40% in 2014 by drilling 75% more horizontal Wolfcamp wells with their 3-rig program.
PVA is an E&P company focused on transitioning to oil and liquids production. It has built up a position in the Eagle Ford shale through drilling and leasing, with over 25,000 net acres and up to 250 well locations. PVA has successfully grown its oil and NGL production in recent years while retaining substantial gas assets. The company is taking steps to improve liquidity and focus on further expanding its oil reserves and drilling inventory through continued activity in the Eagle Ford and testing a new Viola Lime oil prospect. PVA's strategy is aimed at continuing its transition to oil and liquids in order to grow production and cash flows in the current environment of higher oil prices relative to natural gas prices.
An updated copy of a PowerPoint presentation used by Eclipse to summarize and convey important information about the company's shale drilling operations in the Marcellus/Utica region.
PVA is an oil and gas E&P company focused on growing its oil and liquids production. It has successfully transitioned to focus on oil-rich plays like the Eagle Ford shale, growing its oil production significantly. PVA is working to improve its liquidity through asset sales and reducing capital spending while maintaining strong drilling results in its key oil assets. The company remains attractively valued given its transition towards oilier production and reserves.
PVA is an E&P company focused on transitioning from natural gas to oil production through development of its Eagle Ford Shale position. It has grown its Eagle Ford acreage and is seeing strong production and reserve growth from its Eagle Ford drilling program. PVA is also taking steps to improve its financial liquidity by selling non-core assets and reducing capital spending and dividends. Its strategy is focused on continued expansion of its Eagle Ford drilling inventory and reserves to grow its oil and liquids production and cash flows.
August 2016 corporate_presentation_final Eclipse resourcesSteve Wittrig
Eclipse Resources is an oil and gas company focused on developing its 115,000 net acres in the core of the Utica Shale and 13,000 net acres in the Marcellus Shale. The presentation highlights Eclipse's strong operational performance, including increasing lateral lengths by 200% while decreasing drilling costs by 50% per foot. Eclipse plans to resume drilling activities in mid-2016 and grow production over 30% year-over-year in 2017 through completing DUCs and operating a one-rig program. The company also discusses its super-lateral drilling program aimed to significantly improve well returns through extending lateral lengths.
PVA is an E&P company focused on transitioning to oil and liquids production. It has built up a position in the Eagle Ford shale play with over 25,000 net acres and 250 well locations. PVA is executing a strategy of continued drilling in the Eagle Ford to grow its oil and liquids production and cash flows. It is also taking steps to improve its financial liquidity by selling non-core assets and reducing capital spending and dividends. PVA sees opportunities to expand its oil and liquids reserves and drilling inventory through further exploration and leasing in South Texas and other oil-rich plays.
PVA is an E&P company focused on transitioning to oil and liquids production. It has built up a position in the Eagle Ford shale through leasing and exploration, and now has nearly 25,000 net acres and up to 250 well locations. PVA has grown its oil/NGL production significantly in recent years through Eagle Ford development. It is also exploring other oil prospects while retaining gas-heavy assets. PVA's strategy is focused on continuing its transition to oil, expanding its drilling inventory, improving liquidity, and growing its oil and liquids production and cash flows.
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2. Forward-looking statements
Scotia Howard Weil 43rd Annual Energy Conference – March 2015 2
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes
or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this
presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including
as to the Company’s Wolfcamp shale resource play, estimated resource potential and recoverability of the oil and gas, estimated reserves and drilling locations, capital
expenditures, typical well results and well profiles, type curve, and production and operating expenses guidance included in the presentation. These statements are based on
certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors
believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words “will,” “potential,” “believe,” “intend,” “expect,” “may,”
“should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “target,” “profile,” “model” or their negatives, other similar expressions or the statements that include those
words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a
number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied
or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's
most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. Any forward-looking statement speaks only as of the date on which such statement is made
and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as
required by applicable law.
The Securities and Exchange Commission (“SEC”) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that
meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The
Company uses the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” and other descriptions of volumes of reserves potentially recoverable through
additional drilling or recovery techniques that the SEC’s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more
speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company.
EUR estimates, identified drilling locations and resource potential estimates have not been risked by the Company. Actual locations drilled and quantities that may be
ultimately recovered from the Company’s interest may differ substantially from the Company’s estimates. There is no commitment by the Company to drill all of the drilling
locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Company’s drilling project, which will be directly affected by
the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and
actual drilling results, as well as geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per well EUR and resource potential may change
significantly as development of the Company’s oil and gas assets provides additional data.
Type/decline curves, estimated EURs, resource potential, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core
data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are
presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. The Company has limited
production experience with this project, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential
and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. Unless
otherwise noted, IRR estimates are before taxes and assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based
on Company drilling and completion cost estimates that do not include land, seismic or G&A costs.
Cautionary statements regarding oil & gas quantities
3. Company overview
AREX OVERVIEW ASSET OVERVIEW
Enterprise value $668MM
$1.4 BN proved PV-10
High-quality reserve base
146 MMBoe proved reserves
66% Liquids, 38% oil
Permian core operating area
155,000 gross (136,000 net) acres
~1+ BnBoe gross, unrisked resource potential
~2,000 Identified HZ drilling locations targeting
Wolfcamp A/B/C
2015 Capital program focused on flexibility and
returns
Running an average of 1 HZ rig in the Wolfcamp
shale play with a capital budget of approximately
$160 MM
Notes: Proved reserves and acreage as of 12/31/2014. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing share
price of $6.74 per share on 3/19/2015, plus net debt as of 12/31/2014. See “PV-10 (unaudited)” slide.
3Scotia Howard Weil 43rd Annual Energy Conference – March 2015
4. Key investment highlights
4
Low-Risk, Oil-Rich Asset Base in Midland Basin
• Drilled over 150 HZ Wolfcamp wells, acreage derisked and type curve validated by actual results
• Drilling achieving ~20% IRR at current NYMEX strip prices
Solid Financial and Liquidity Position
• Low leverage and significant liquidity
• Well-hedged in 2015
Lowest Cost Driller in the Midland Basin
• Achieved $5.5MM average well cost in 2014, target 15% - 20% reduction by 2Q15
• 2014 Drill bit F&D cost $8.92/Boe
• 2014 Lease operating expense of $6.48/Boe compares favorably to basin peers
High Degree of Operational Flexibility
• 100% Operated reserve base with ~100% working interest
• Minimal drilling obligations and no long-term service contracts
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
5. Valuation and leverage well supported by proved reserve base
5
• 12/31/2014 reserve summary prepared by DeGolyer and MacNaughton (“D&M”)
• Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per Boe1
• Total proved reserves up 27% YoY, proved oil reserves up 20% YoY
• PV-10 up 25% YoY to a record $1.4 billion
Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) PV-10 ($ MM) 2
PDP 17,599 18,319 133,583 58,181 $870.0
PDNP 379 763 5,378 2,039 $12.4
PUD 37,360 21,825 161,059 86,028 $530.6
Total Proved 55,338 40,907 300,020 146,248 $1,413.0
Total Proved Reserves Reserves by Commodity Proved PV-10
38%
28%
34%
Oil NGLs Natural Gas
40%
1%
59%
PDP PDNP PUD
62%
< 1%
38%
PDP PDNP PUD
1. Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year.
2. PV-10 calculated based on the first-of-the-month, 12-month average prices for oil, NGLs and natural gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas.
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
6. Strong, simple balance sheet
6
AREX Liquidity and Capitalization• Following the Fall 2014 redetermination, the borrowing base
under our $1 billion revolving credit facility was increased to
$600 million, with a company-elected commitment limit of
$450 million
• Provides a sizable cushion against more conservative bank
lending framework
• Manageable Debt / LTM EBITDAX of 2.1x
• LTM EBITDAX / LTM Interest of 8.7x, well above minimum
2.5x covenant requirement
• Simple balance sheet with no near-term debt maturities
AREX Debt Maturity Schedule ($ MM)
AREX Capitalization as of 12/31/2014 ($ MM)
Cash $0.4
Credit Facility 150.0
7.0% Senior Notes due 2021 250.0
Total Long-Term Debt $400.0
Shareholders’ Equity 774.3
Total Book Capitalization $1,174.3
AREX Liquidity as of 12/31/2014
Borrowing Base $450.0
Cash and Cash Equivalents 0.4
Borrowings under Credit Facility (150.0)
Undrawn Letters of Credit (0.3)
Liquidity $300.1
$150.0
$250.0
$0.0
$50.0
$100.0
$150.0
$200.0
$250.0
$300.0
$350.0
$400.0
$450.0
2015 2016 2017 2018 2019 2020 2021
$300 MM undrawn
borrowing capacity 7.0% Senior Notes
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
7. Well prepared for commodity price cycle
7
Key areas of focus in 2015
• Plan to stay nimble in 2015 with key focus on financial discipline and returns
• Capital budget of ~$160 MM is flexible
• No significant drilling or service contract obligations – capital budget can be cut further
• Plan to time and size the development budget based on magnitude of service cost reductions and direction of
commodity prices
• Delayed all completion and new well hook-ups in Q1 to March 2015 (no new wells hooked into sales since mid-
December)
• Operating team’s top priority is service cost reduction
• Expect reduction of 15% - 20% in D&C costs in second quarter 2015
• Lower D&C costs significantly improves break-even price threshold
• Water recycle center to be fully operational by end of Q1 2015
• Strong balance sheet ensures financial flexibility
• Debt / LTM EBITDAX of 2.1x – top tier for SMID cap E&P universe
• Liquidity of $300 MM at 12/31/2014
• Borrowing base of $600 MM vs elected commitment of $450 MM provides further protection to liquidity
• Solid hedge book in place for 2015
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
8. Strong track record of reserve growth
8
RESERVE GROWTH
0
20
40
60
80
100
120
140
160
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Gas (MMBoe) Oil & NGLs (MMBbls)
5.0
18.1
37.3
46.1
55.3
0
10
20
30
40
50
60
2010 2011 2012 2013 2014
Oil (MMBbls)
OIL RESERVE GROWTH
• YE14 reserves up 27% YoY
• Replaced 819% of produced reserves at a drill-
bit F&D cost of $8.94/Boe
• 124.8 MMBoe proved reserves booked to HZ
Wolfcamp play
• Strong, organic oil reserve growth driven by
HZ Wolfcamp shale
• Oil reserves up 20% YoY
• Oil reserves up 11x since YE10
Note: See “Drill-bit F&D cost (unaudited)” slide.
MMBoe MMBbls
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
9. Strong track record of production growth
9
PRODUCTION GROWTH
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Natural Gas (MBoe/d) Oil & NGLs (Mbbls/d)
246
482
969
1,444
2,024
0
500
1,000
1,500
2,000
2,500
2010 2011 2012 2013 2014
Oil (MBbls)
OIL PRODUCTION GROWTH
• 2014 Production increased 47% YoY
• Targeting 10-14% production growth in 2015
• Strong, organic oil production growth driven
by HZ Wolfcamp shale
• Oil production up 40% YoY
• Oil production up over 8x since FY10
MBblsMBoe/d
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
10. Outperformance in gas/NGL volumes achieves higher reserve
recovery and drives production growth
10
85
135
166
247 270
312
82
128
153
230
259
286
260
424
396
481
475
510
0
200
400
600
800
1,000
1,200
3Q13 4Q13 1Q14 2Q14 3Q14 4Q14
Gas NGLs Oil
Horizontal Wolfcamp Production by Commodity
Mboe
96% oil growth since 3Q13
159% growth in HZ Wolfcamp
production since 3Q13
248% NGL growth since 3Q13
269% gas growth since 3Q13
427
687
715
957
1,004
1,108
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
11. 1111
AREX HZ WOLFCAMP (BOE/D)
Note: Daily production normalized for operational downtime. Gas EUR is unprocessed wellhead volume.
AREX HZ Wolfcamp Well Performance
Oil EUR = 230 MBBL
Well EUR = 510 MBOE
Gas EUR = 1,271 MMCF
Average GOR = 5,000 – 6,000
Average Oil
Average BOE
Average Gas
Average GOR
N = 93 Wells
AREX Wolfcamp Horizontal Type Curve
Year-end 2014
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
12. Probability Distribution of AREX 93 Type Curve Wells at Year-
end 2014
12Scotia Howard Weil 43rd Annual Energy Conference – March 2015
13. 13
Midland Basin - Wolfcamp Horizontal Well Activity
13
Southern
Midland Basin
Northern
Midland Basin
18.3%
Northern
Midland Basin
81.7%
Southern Midland Basin
Source: DrillingInfo and IHS
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
14. 14
Midland Basin - IP and Drilling & Completion Cost
14
Source: Company releases/presentations, DrillingInfo, IHS, public databases, and internal studies.
Note: Three-stream IP estimated using 0.1539 Bbl per Mcf and 25% shrinkage factor.
D&CCost($MM)
18% with
IP > 1,000
BOE
5% with
IP > 1,500
BOE
Entire Midland
Basin Average IP
689 BOE
Southern
Midland Basin
Northern Midland
Basin
$0
$2
$4
$6
$8
$10
$12
Actual Cost
Target Cost
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
15. Proven track record of delivering lowest D&C cost in the Midland
Basin
15
$8.6
$7.0
$5.8
$5.5
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
$9.0
2011 2012 2013 2014 Q2 2015 Target
Approach’s annual average horizontal well D&C cost
Demonstrated 35%
improvement 2011-2014
$ MM
15% – 20%
reduction target
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
16. D&C Cost reductions will significantly improve profitability
16
Note: HZ Wolfcamp economics assume $4.00/Mcf realized natural gas price and NGL price based on 40% of realized oil price.
0%
10%
20%
30%
40%
50%
60%
70%
$40 $50 $60 $70 $80 $90
IRR(%)
Realized Oil Price ($/Bbl)
$4.1MM D&C
$4.6MM D&C
$5.1MM D&C
$5.5MM D&C
IRR at NYMEX strip
pricing
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
17. Established infrastructure in place is critical to low cost
structure
17
Benefits of water recycling
• Reduce D&C cost
• Reduce LOE
• Increase project profit margin
• Minimize fresh water use, truck
traffic and surface disturbance
Pangea
West
North & Central Pangea
South
Pangea
SchleicherCrockett
IrionReagan
Sutton
Recently completed
water recycling facility
329,000 Bbl Capacity
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
18. 18
AREX Flowback and Produced Water Recycle Facility
• Reduce drilling and completion
cost by $450K per well
• Reduce LOE by up to $1.00 per
BOE
• Eliminate usage of potable fresh
water for completion
• Minimize surface disturbance
• Skim oil sale up to 200 Bbls per
day - more than sufficient to pay
for facility operating expense
32,000
BBL Dirty
Water
TankSkim Oil Sales
Flowback & Produced Water Offloading
Terminal & Separation Facility
Flowback & Produced Water Supply
90 BPM
Pump StationWater Treatment
&
Filtration Facility
63,000 BBL
Treated
Water
Tank
44,000 BBL
Treated
Water
Tank
8”Flowback&ProducedSaltwaterLine
8”LowChlorideTreatedFracWaterSupplyLine
20”TreatedFlowback&ProducedFracWaterSupplyLine
32,000
BBL
Treated
Water
Tank
N
63,000 BBL
Treated
Water
Tank
63,000 BBL
Treated
Water
Tank
32,000
BBL
Treated
Water
Tank
32,000
BBL
Treated
Water
Tank
329,000 Bbl Capacity Facility
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
19. AREX Horizontal Wolfcamp activity
19
Note: Acreage as of 12/31/2014.
• 19,000 gross acres
• Pad drilling with AB and AC “stacked” wellbores
• 18 horizontal wells drilled to date
• 47,000 gross acres
• Legacy gas/NGL field
• No horizontal Wolfcamp
locations assigned to this
leasehold
• 89,000 gross acres
• Pad drilling with AC and BC
“stacked” wellbores
• 131 horizontal wells drilled to date
Legend
│ HZ Producer
│ HZ – Waiting on Completion
NORTH & CENTRAL
PANGEA
PANGEA WEST
SOUTH PANGEA
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
20. Legend
│ HZ Producer
│ HZ – Waiting on Completion
Baker 122HC
• IP: 827 Boe/d
• IP oil: 70%
Elliott 129HC
• IP: 806 Boe/d
• IP oil: 63%
Baker 122HC and Elliott 129HC drilled in 2014 have validated
significant upside potential of AREX’s portfolio
20
2014 HZ Wolfcamp activity
Well performance
Over 40,000 gross acres
delineated by these
recent C-bench wells
0
100
200
300
400
500
600
700
800
900
Day 9 19 29 39 49 59 69 79 89 99 109
Boe/d
Elliot 129HC Baker 1AW 122HC 510 Mboe Typecurve
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
21. Current hedge position
21
Commodity & Period Contract Type Volume Contract Price
Crude Oil
January 2015 – March 2015 Collar 1,500 Bbls/d $85.00/Bbl - $95.30/Bbl
January 2015 – December 2015 Collar 1,600 Bbls/d $84.00/Bbl - $91.00/Bbl
January 2015 – December 2015 Collar 1,000 Bbls/d $90.00/Bbl - $102.50/Bbl
January 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $94.00/Bbl
January 2015 – December 2015 3-way Collar 500 Bbls/d $75.00/Bbl - $84.00/Bbl - $95.00/Bbl
Natural Gas
January 2015 – June 2015 Collar 80,000 MMBtu/month $4.00/MMBtu - $4.74/MMBtu
January 2015 – December 2015 Swap 200,000 MMBtu/month $4.10/MMBtu
January 2015 – December 2015 Collar 130,000 MMBtu/month $4.00/MMBtu - $4.25/MMBtu
• Based on the midpoint of current 2015 guidance, approximately 64% of forecasted oil production and 44% of
forecasted natural gas production are hedged at weighted average floor prices of $80.59/Bbl and $4.05/MMBtu,
respectively.
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
22. Production and expense guidance
22
2015 Guidance
Production
Oil (MBbls) 2,200 – 2,325
NGLs (MBbls) 1,575 – 1,625
Natural Gas (MMcf) 10,050 – 10,200
Total (MBoe) 5,450 – 5,650
Operating costs and expenses (per Boe)
Lease operating $6.00 - $7.00
Production and ad valorem taxes 7.25% of oil & gas revenues
Cash general and administrative $3.75 - $4.25
Exploration (non-cash) $0.50 - $1.00
Depletion, depreciation and amortization $20.00 - $22.00
Capital expenditures (in millions) ~$160
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
24. Fourth quarter and full-year 2014 financial highlights
24
FY 2014 Q4 2014
Significant cash
flow and capex
below budget
Strong financial
position
Record revenue
and net income
• Revenues of $258.5 MM (up 43% YoY)
• Net income of $56.2 MM, or $1.42 per
diluted share
• Adjusted net income (non-GAAP) of
$29.2 MM, or $0.74 per diluted share
• Revenues of $55.1 MM (down 6% YoY
despite 25% YoY drop in oil prices)
• Net income of $27.0 MM, or $0.68 per
diluted share
• Adjusted net income (non-GAAP) of $3.4
MM, or $0.08 per diluted share
• EBITDAX (non-GAAP) of $188.3 MM (up
47% YoY), or $4.78 per diluted share (up
46% YoY)
• Capital expenditures of $393.5 MM,
below $400 MM capex guidance
• EBITDAX (non-GAAP) of $44.3 MM (up
8% YoY), or $1.12 per diluted share (up
7% YoY)
• Capital expenditures of $92.9 MM
• Liquidity of $300 MM at December 31st
• Borrowing base increased to $600 MM during 4Q14, with elected commitments of $450 MM
• 34% Debt-to-capital ratio
Note: See “Adjusted Net Income,” “EBITDAX” and “Strong, Simple Balance Sheet” slides.
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
25. Fourth quarter and full-year 2014 operating highlights
25
FY 2014 Q4 2014
Low cost, on
time, and on
budget
Higher well
recoveries and
advancing
delineation
Solid execution
• Completed 64 HZ wells
• Total production 5,049 MBoe vs early
guidance of 4,790 MBoe
• 2014 oil production of 5,545 Bbl/d (up
40% YoY)
• Completed 13 HZ wells
• Total production 1,390 MBoe
• 4Q14 oil production of 5,902 Bbl/d (up
14% YoY and 7% QoQ)
• FY2014 capex of $394 MM ($364 MM
D&C) vs $400 MM budget
• Cash operating cost of $14.36/Boe (down
7% YoY)
• Q4 2014 capex of $93 MM ($87 MM
D&C)
• Cash operating cost of $13.47/Boe (down
21% YoY)
• Strong well results from the Baker and
Elliott areas demonstrate upside potential
of central and eastern acreage
• 4Q14 HZ Wolfcamp B/C average IP 795
Boe/d
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
26. AREX Wolfcamp acreage is offset by large operators
26
Pangea West
EOG
COP
Enervest
EP ENERGY
others
MPO
APA
PXD
DVN
AREX
AREX
AREX
AREX
APA
APA
APA
DVN
DVN
SAMSON
PXD
DVN
APA
APA
APA
EOG
Pangea
Enervest
EOG /
AEP
AEP
BROADOAK
ENDEAVOR
APA
UPTON
CROCKETT
REAGAN
IRION
SCHLEICHER
SUTTON
EP ENERGY
EOG
Pangea West
EOG
COP
Enervest
EP ENERGY
others
MPO
APA
PXD
DVN
AREX
AREX
AREX
AREX
APA
APA
APA
DVN
DVN
SAMSON
PXD
DVN
APA
APA
APA
EOG
Pangea
Enervest
EOG /
AEP
AEP
BROADOAK
ENDEAVOR
APA
UPTON
CROCKETT
REAGAN
IRION
SCHLEICHER
SUTTON
EP ENERGY
EOG
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
27. Adjusted net income (unaudited)
27
(in thousands, except per-share amounts)
Three Months Ended
December 31,
2014 2013
Net income $ 26,987 $ 64,321
Adjustments for certain items:
Unrealized (gain) loss on commodity derivatives (36,907) 1,348
Gain on sale of equity method investment - (90,743)
Related income tax effect 13,287 33,076
Adjusted net income $ 3,367 $ 8,002
Adjusted net income per diluted share $ 0.08 $ 0.20
The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe
adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before
recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and
should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and
posted on our website.
The following table provides a reconciliation of adjusted net income to net income (loss) for the three months ended December 31, 2014 and 2013.
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
28. EBITDAX (unaudited)
28
We define EBITDAX as net income (loss), plus (1) exploration expense, (2) gain on the sale of our equity method investment, (3) depletion, depreciation and amortization
expense, (4) share-based compensation expense, (5) unrealized loss (gain) on commodity derivatives, (6) interest expense and (7) income taxes. EBITDAX is not a measure of
net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein
and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund
development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in
our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
The following table provides a reconciliation of EBITDAX to net income (loss) for the three and twelve months ended December 31, 2014 and 2013.
(in thousands, except per-share amounts)
Three Months Ended
December 31,
2014 2013
Net income $ 26,987 $ 64,321
Exploration 236 228
Gain on sale of equity method investment - (90,743)
Depletion, depreciation and amortization 28,664 22,005
Share-based compensation 2,521 512
Unrealized (gain) loss on commodity derivatives (36,907) 1,348
Interest expense, net 5,715 5,225
Income tax provision 17,102 38,207
EBITDAX $ 44,318 $ 41,103
EBITDAX per diluted share $ 1.12 $ 1.05
Twelve Months Ended
December 31,
2014 2013
$ 56,172 $ 72,256
3,831 2,238
- (90,743)
106,802 76,956
8,247 5,901
(42,113) 4,596
21,651 14,084
33,692 42,507
$ 188,282 $ 127,795
$ 4.78 $ 3.28
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
29. F&D costs (unaudited)
29
F&D Cost reconciliation
Cost summary (in thousands)
Property acquisition costs
Unproved properties $ 4,578
Proved properties -
Exploration costs 3,831
Development costs 382,995
Total costs incurred $ 391,404
Reserves summary (MBoe)
Balance – 12/31/2013 114,661
Extensions & discoveries 43,247
Production (1) (5,281)
Revisions to previous estimates (6,379)
Balance – 12/31/2014 146,248
F&D cost ($/Boe)
All-in F&D cost $ 10.62
Drill-bit F&D cost 8.94
Reserve replacement ratio
Drill-bit 819%
All-in finding and development (“F&D”) costs are calculated by dividing the sum of
property acquisition costs, exploration costs and development costs for the year by
the sum of reserve extensions and discoveries, purchases of minerals in place and
total revisions for the year.
Drill-bit F&D costs are calculated by dividing the sum of exploration costs and
development costs for the year by the total of reserve extensions and discoveries for
the year.
We believe that providing F&D cost is useful to assist in an evaluation of how much it
costs the Company, on a per Boe basis, to add proved reserves. However, these
measures are provided in addition to, and not as an alternative for, and should be
read in conjunction with, the information contained in our financial statements
prepared in accordance with GAAP (including the notes), included in our previous
SEC filings and to be included in our annual report on Form 10-K to be filed with the
SEC on February 26, 2015. Due to various factors, including timing differences, F&D
costs do not necessarily reflect precisely the costs associated with particular
reserves. For example, exploration costs may be recorded in periods before the
periods in which related increases in reserves are recorded, and development costs
may be recorded in periods after the periods in which related increases in reserves
are recorded. In addition, changes in commodity prices can affect the magnitude of
recorded increases (or decreases) in reserves independent of the related costs of
such increases.
As a result of the above factors and various factors that could materially affect the
timing and amounts of future increases in reserves and the timing and amounts of
future costs, including factors disclosed in our filings with the SEC, we cannot assure
you that the Company’s future F&D costs will not differ materially from those set forth
above. Further, the methods used by us to calculate F&D costs may differ
significantly from methods used by other companies to compute similar measures. As
a result, our F&D costs may not be comparable to similar measures provided by other
companies.
The following table reconciles our estimated F&D costs for 2014 to the information
required by paragraphs 11 and 21 of ASC 932-235.
(1) Production includes 1,390 MMcf related to field fuel.
Scotia Howard Weil 43rd Annual Energy Conference – March 2015
30. PV-10 (unaudited)
30
The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $1.4 billion at December 31, 2014, and was calculated based on the first-of-the-month,
twelve-month average prices for oil, NGLs and gas, of $94.56 per Bbl of oil, $31.50 per Bbl of NGLs and $4.55 per MMBtu of natural gas.
PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs
and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their
“present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP
financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because
there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is
valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.
The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in
accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
(in millions) December 31,
2014
PV-10 $ 1,413
Less income taxes:
Undiscounted future income taxes (1,267)
10% discount factor 910
Future discounted income taxes (357)
Standardized measure of discounted future net cash flows $ 1,056
Scotia Howard Weil 43rd Annual Energy Conference – March 2015