Recent Company Earnings:


March 14, 2019

2018 Earnings season gets ready for a wrap

As oil and gas earnings are getting ready for the wrap party, a group of middle market producers and a proppant company announced earnings in the past few days, with key points summarized in brief below.

Earnings in Brief: Six E&Ps and a Sand Supplier Announce 2018 Wins, Losses - Oil & Gas 360

Earnings in Brief: Six E&;Ps and a Sand Supplier Announce 2018 Wins, Losses – Oil & Gas 360

Mid-Con Energy Partners

Mid-Con Energy Partners, LP (NASDAQ: MCEP) announced operating and financial results for the fourth quarter and full year ended December 31, 2018.

“2018 was a transformative year for the Partnership,” commented President and CEO, Jeff Olmstead. “We significantly improved our financial position by extending the maturity of our Revolving Credit Facility, increasing the borrowing base amount, reducing total outstanding debt, and reducing our total leverage as calculated by our banks. We closed approximately $23 million in acquisitions, including several properties in our new core area of Wyoming, and expanded our footprint in Oklahoma. This all resulted in production increasing approximately 30% from the first quarter of 2018 compared to the fourth quarter of 2018.

In February 2019, we announced the execution of two agreements to sell substantially all of our Texas assets and to acquire assets in Oklahoma. The net effect of this transaction will be to significantly reduce outstanding debt and to add long-lived, low-decline assets with potential for margin enhancements through operational efficiency to our portfolio. This continues our track record from 2018 of entering into transactions that help strengthen our financial position and lower our base PDP decline rate. The lower PDP decline rate provides us a more stable reserve base, which allows for more operational and financial control, to grow from. Lower decline properties require less capital investment to maintain production and reserves, and provide the flexibility to invest additional free cash flow into development of new reserves and/or into new acquisitions.

Recent Events and 2018 Summary

  • Completed $15.0 million private offering (the “Offering”) of Class B Convertible Preferred Units (“Class B Preferred Units”) on January 31, 2018, to investors led by John Goff. The Partnership used a portion of net proceeds from this Offering to acquire assets in the Powder River Basin(“PRB Acquisitions”) and the remaining approximately $7.2 million to pay down debt.
  • Closed approximately $23 million, after post-close adjustments, in acquisitions during 2018. The acquisitions included entering into a new core area consisting of two basins, the Powder River Basin and the Big Horn Basin, as well as increasing our footprint in Oklahoma. These properties consist of approximately 9,271 MBoe of net total proved reserves as of December 31, 2018 at the standardized measure for pricing approved by the SEC (“SEC pricing”).
  • In February 2019, we executed definitive agreements to sell substantially all of our Eastern Shelf assets in Texas for $60.0 million, and to acquire Oklahoma properties in Osage, Caddo, and Grady counties for $27.5 million, both subject to customary purchase price adjustments. The properties include 10 mature waterflood units and consist of low decline (average PDP decline of less than 5%), long-lived assets with opportunities to both grow production and decrease current operating expenses through operational efficiencies. Net proved developed producing reserves of these Oklahoma properties as of January 1, 2019 were 6.2 MMBoe (96% oil) based on SEC pricing as of January 1, 2019.
  • On December 19, 2018, the Partnership’s borrowing base was increased to $135.0 million as part of the regularly scheduled semi-annual redetermination.
  • We reduced total debt outstanding at December 31, 2018 by $6.0 million, or 6.1%, from December 31, 2017 and in January 2018 the revolving credit facility maturity was extended by two years to November 2020. Compliance Total Leverage, as calculated per our credit agreement, was approximately 3.17x as of December 31, 2018 compared to 3.54x as of December 31, 2017.
  • Fourth quarter 2018 average daily production of 3,663 Boe/d, an increase of 30.8% from first quarter 2018.
  • Lease operating expenses (“LOE”) of approximately $22.5 million, an increase of 8.3% year-over-year.
  • Realized revenues, inclusive of cash settlements from matured derivatives and net premiums, were $59.0 million, an increase of 8.2% year-over-year.
  • Full year net loss of $18.3 million in 2018 compared to a net loss of $27.3 million in 2017.
  • Adjusted EBITDA, a non-GAAP measure, was $25.2 million at December 31, 2018, an increase of 5.7% year-over-year, primarily due to higher oil and gas revenue from an increase in commodity prices.

Earthstone Energy

Earthstone Energy, Inc. (NYSE: ESTE) announced financial and operating results for the fourth quarter and year ended December 31, 2018.

Fourth Quarter 2018 Highlights

  • Revenues of $41.2 million
    • Increased 16% over fourth quarter 2017
  • Average daily production of 10,454 Boepd(1)
    • Increased 15% over fourth quarter 2017 while the oil component increased 27% over fourth quarter 2017
  • Net income of $81.0 million
    • Compared to $5.5 million in fourth quarter 2017
  • Net income attributable to Earthstone Energy, Inc. of $36.1 million, or $1.26 per diluted share
    • Compared to $2.3 million, or $0.09 per diluted share in fourth quarter 2017
  • Adjusted EBITDAX(2)of $23.9 million
    • Increased 8% over fourth quarter 2017

Full Year 2018 Highlights

  • Revenues of $165.4 million
    • Increased by 53% over 2017
  • Average daily production of 9,937 Boepd(1)
    • Increased by 26% over 2017 while the oil component increased 30% over 2017
  • Net income of $95.2 million
    • Compared to a net loss of $44.7 million in 2017
  • Net income attributable to Earthstone Energy, Inc. of $42.3 million, or $1.50 per diluted share
    • Compared to a net loss of $12.5 million, or a $0.53 loss per share in 2017
  • Adjusted EBITDAX(2)(3)of $96.2 million
    • Increased by 59% over 2017

Robert J. Anderson, President of Earthstone, said, “2018 was a very successful year for Earthstone as we keenly focused on operating efficiencies and thereby generated low-cost reserve additions and strong cash margins. We realized significant improvement in every metric including production, revenues and operating expenses, thus driving a 59% increase in Adjusted EBITDAX to $96.2 million for the year. We also increased our proved reserves by 24% with a finding and development cost of only $9.49 per Boe for extensions and discoveries. Considering that we have only been operating in the Midland Basin for less than two years, we are pleased with our accomplishments and the contributions of all of our employees.

“For 2019, we have set high expectations for Earthstone as we build on these successes. Our strong balance sheet, substantial hedge position averaging over $65 per barrel of oil and positive operating margins give us the confidence to increase our capital budget by approximately 25%, allowing us the flexibility to continue to demonstrate the quality of our acreage position through the drill bit.

“We are executing a successful one-rig development program in the Midland Basin and expect to continue our multi-year growth in production, although our 2019 production profile is projected to remain lumpy with a majority of the completions scheduled in the second half of the year. We presently estimate that we will achieve free cash flow in 2020 assuming we maintain our existing pace of development and current commodity prices continue through such time.”


Abraxas Petroleum

Abraxas Petroleum Corporation (NASDAQ:AXAS) reported financial and operating results for the three and twelve months ended December 31, 2018.

Financial Highlights for the Three Months Ended December 31, 2018

The three months ended December 31, 2018 resulted in:

  • Production of 965 MBoe (10,493 Boepd)
  • Revenue of $36.0 million
  • Net income of $55.8 million, or $ 0.34 per share
  • Adjusted net income(a) (excluding certain non-cash items) of $4.1 million, or $ 0.02 per share
  • EBITDA(a)of $20.1 million
  • Adjusted EBITDA per bank loan covenants of $20.1 million(a)

The twelve months ended December 31, 2018 resulted in:Financial Highlights for the Twelve Months Ended December 31, 2018

  • Production of 3.6 MMBoe (9,809 Boepd)
  • Revenue of $149.2 million
  • Net income of $57.8 million, or $ 0.35 per share
  • Adjusted net income(a) (excluding certain non-cash items) of $30.7 million, or $ 0.19 per share
  • EBITDA(a)of $83.9 million
  • Adjusted EBITDA per bank loan covenants of $84.2 million(a)

Williston Basin, North Dakota

Western North Dakota has experienced one of the coldest winters on record. Abraxas has experienced several days when all surface work was shut down due to temperatures and wind chill that put personnel safety and equipment reliability in jeopardy. The Ravin NE Pad is still under production restriction due to a natural gas pipeline installation delay requiring the flaring of all gas production from this pad. The pipeline is scheduled to be in service within the next two weeks at which point we are expecting normal production operations to be resumed. The Abraxas Raven Rig#1 is scheduled to be started up within the next several months to begin drilling operations on the six well Jore Extension Pad.

Delaware Basin, West Texas

In the Delaware Basin of West Texas, the Company has successfully drilled, completed and started flowback on the two well Creosote Pad in Ward County, where Abraxas now owns an approximate 95% working interest. The Wolfcamp A-1 and A-2 were targeted with a 26 stage fracture treatment (frac) in 5,000’ laterals. The one well Hackberry pad has been successfully drilled and a 26 stage fracture treatment in the Wolfcamp A-1 is scheduled to start next Monday. Abraxas owns an approximate 75% working interest in this 5,000’ lateral well located in Winkler County. The Company is currently drilling a two well pad, Woodberry, in which we own a 100% working interest. The Woodberry Pad adjoins our Caprito block in Ward County.

Year End 2018 Reserves

The Company’s total proved reserves at December 31, 2018 were 67.2 million barrels of oil equivalent (MMBOE), an increase of 2.8% over year end 2017 after production of 3.6 MMBOE and property divestitures of 3.8 MMBOE. The SEC PV10 (a non-GAAP measure) was approximately $689 million. SEC pricing was $65.56 per barrel for oil and $3.03 per mcf for gas. Proved developed reserves were 24.6 MMBOE, or 37% of the total. Oil represented 63% of total proved reserves, natural gas 22%, and natural gas liquids 15%.


Midstates Petroleum

Midstates Petroleum Company, Inc. (NYSE: MPO) announced fourth quarter and full year 2018 results.

Fourth Quarter and Full-Year 2018 Highlights and Recent Key Items

  • Reported net income of $49.8 million, or $1.91 per share, for the full year 2018 and net income of $35.8 million, or $1.38 per share, in the fourth quarter 2018
  • Announced year-end 2018 SEC proved reserves of 72.4 million barrels of oil equivalent (MMBoe) with a net present value discounted at 10% (PV-10) of approximately $580 million
    • Year-end 2018 SEC proved developed producing (PDP) reserves of 46.5 MMBoe with a PV-10 of approximately $425 million
  • Achieved Mississippian Lime production of 16,747 barrels of oil equivalent per day (Boepd) for the full year 2018
  • Generated Adjusted EBITDA of $27.8 million in the fourth quarter of 2018, outpacing quarterly operational capital expenditures by approximately $24.2 million; full-year 2018 Adjusted EBITDA totaled $116.4 million, approximately $19.9 million higher than full-year operational capital expenditures
  • Initiated a process pursuing all strategic and opportunistic transactions that create significant shareholder value
  • Completed workforce reduction in January 2019 to better align general and administrative costs (G&A) with current activity levels; reduced Adjusted Cash G&A expense by $4 million to $5 million annually (excluding one-time severance costs)
  • Successfully executed $50 million tender offer for outstanding capital stock in February 2019, returning capital to shareholders

For the fourth quarter of 2018, Midstates reported net income of $35.8 million, or $1.38 per share, which included the impact of a $25.4 million gain related to the Company’s commodity derivative contracts. In the same period in 2017, the Company reported a net loss of $121.0 million, or ($4.78) per share, including the impact of a $5.1 million commodity derivative charge, and in the third quarter of 2018 reported net income of $11.5 million, or $0.44 per share, including the impact of a $6.6 million commodity derivative charge. For the full year 2018, Midstates reported net income of $49.8 million, or $1.91 per share, which included the impact of a $3.6 million gain related to the Company’s commodity derivative contracts, compared to a net loss of $85.1 million, or ($3.39) per share, including the impact of a $3.7 million gain related to the Company’s commodity derivative contracts, in 2017.

In the fourth quarter of 2018, Midstates generated Adjusted EBITDA of $27.8 million, excluding advisory fees and costs incurred for strategic reviews. This compares to $33.9 million for the same quarter in 2017 and $31.9 million for the third quarter of 2018. For the full year 2018, Midstates generated Adjusted EBITDA of $116.4 million, excluding advisory fees and costs incurred for strategic reviews, compared to $128.2 million, in 2017.

David Sambrooks, President and Chief Executive Officer, commented, “In 2018 we continued our strong operational results and strengthened Midstates financially through several notable accomplishments. Operationally, we optimized base production through a substantial workover program and have taken actions to drive down lease operating and overhead expenses to help maximize margins and grow value. Midstates generated $116.4 million in Adjusted EBITDA, outpacing our operational capex by $20 million and we monetized a portion of our portfolio by selling our non-core Anadarko asset, using the proceeds and free cash flow to pay down $105 million in debt during 2018.

“We are forecasting significant free cash flow generation in 2019, which allowed us to successfully execute a $50 million tender offer earlier this year and affords us the opportunity to consider multiple options moving forward, including returning a substantial portion of our excess cash to our shareholders. As we look to the future, we remain committed to optimizing our production, minimizing costs and operating efficiently, as well as actively pursuing all opportunities that enhance us financially and operationally.”

Operational Update

Midstates ceased drilling at the end of the third quarter of 2018 in order to further study the production results of its recent extended lateral wells. With the erosion of commodity prices in the fourth quarter of 2018, the Company elected to continue the pause in drilling through mid-year 2019 to maximize free cash flow generation from its producing properties and will evaluate future development plans as the Company moves forward.

The Company did not bring online any new saltwater disposal injection wells during the fourth quarter of 2018. Midstates is currently operating 11 non-Arbuckle injection wells in Woods and Alfalfa Counties, Oklahoma, with permitted injection capacity of approximately 240,000 barrels of water per day. The Company’s total permitted injection capacity in all formations in Woods and Alfalfa Counties, Oklahoma, which may differ from actual injection capacity due to operational constraints, is approximately 372,000 barrels of water per day. The Company’s current disposal rate into all formations is approximately 135,000 barrels of water per day. Approximately 45% of the Company’s water injection is currently being injected into non-Arbuckle formations.

Production and Pricing

Production during the fourth quarter of 2018 totaled 16,351 Boepd, compared with 17,996 Boepd during the third quarter of 2018. Oil volumes comprised 27% of total production, natural gas liquids (NGLs) 26%, and natural gas 47% during the fourth quarter of 2018. Production for the full year 2018 totaled 20,326 Boepd, compared with 22,148 Boepd for the full year 2017. Production from the Company’s Mississippian Lime properties contributed approximately 82%, or 16,747 Boepd, and the Anadarko Basin properties contributed approximately 18%, or 3,579 Boepd. Midstates divested its Anadarko Basin properties in the second quarter of 2018. For the total Company, oil volumes comprised 29% of total production, natural gas liquids (NGLs) 25%, and natural gas 46% for the full year 2018.


Oryx Petroleum

Oryx Petroleum Corporation Limited announced its financial and operational results for the year ended December 31, 2018. All dollar amounts set forth in this news release are in United States dollars, except where otherwise indicated.

2018 Financial Highlights:

  • Total revenues of $97.6 million on working interest sales of 1,542,300 barrels of oil (“bbl”) and an average realised sales price of $57.00/bbl for 2018
    • 160% annual increase in revenues versus 2017
    • Q4 2018 revenues increased 24% versus Q3 2018
    • The Corporation has received full payment in accordance with production sharing contract entitlements for all oil sale deliveries into the Kurdistan Region Export Pipeline through November 2018
  • Operating expenses of $19.2 million ($12.48/bbl) and an Oryx Petroleum Netback1of $21.68/bbl
    • 37% decrease in operating expenses per barrel versus 2017
  • Profit of $43.8 million ($0.09 per common share) in 2018 versus loss of $39.1 million in 2017 ($0.11 per common share)
    • Improvement primarily attributable to higher netback and impairment reversal
  • Net cash generated by operating activities was $8.1 million versus net cash used in operating activities of $9.7 million in 2017 comprised of Operating Funds Flow2of $23.2 million partially offset by a $15.1 millionincrease in non-cash working capital
  • Net cash used in investing activities during 2018 was $32.8 million including payments related to drilling and facilities work in the Hawler license area, seismic processing and interpretation costs in the AGC Central license area, and partially offset by a decrease in non-cash working capital
  • $14.4 million of cash and cash equivalents as of December 31, 2018

2018 Operations Highlights:

  • Average gross (100%) oil production of 6,500 bbl/d (working interest 4,200 bbl/d) for the year ended December 31, 2018 vs 3,300 bbl/d (working interest 2,100 bbl/d) for the year ended December 31, 2017
    • 97% increase in gross (100%) oil production in 2018 versus 2017; 46% increase in gross (100%) oil production in Q4 2018 versus Q3 2018
    • Successful completion of six producing wells during the year
    • Commencement of production from the Tertiary and Cretaceous reservoirs at the Banan field
  • Gross (working interest) proved plus probable oil reserves of 127 million barrels as at December 31, 2018
    • 4% increase versus 2017
  • Processing and interpretation of 3D seismic data covering the AGC Central license area completed with prospects remapped and ranked
    • Best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels as at December 31, 2018

2019 Operations Update:

  • Average gross (100%) oil production of 11,400 bbl/d (working interest 7,400 bbl/d) and 9,800 bbl/d (working interest 6,300 bbl/d) in January and February 2019, respectively. Production in February was curtailed for a number of days due to a temporary shut-down of the Kurdistan Region Export Pipeline.
  • The Banan-6 appraisal well targeting the Cretaceous reservoir is expected to be spudded in the coming days. The well is expected to be drilled to a measured depth of 1,840 metres and completed as a producing well.
  • Final prospect ranking has been completed in the AGC Central license area with an environmental impact assessment planned for 2019 with preparation for drilling in 2020 to follow

 Oryx Petroleum’s Chief Executive Officer, Vance Querio, said, “2018 was a good year for Oryx Petroleum. During the year we substantially increased production from the Hawler license area thanks to the successful completion of six new producing wells, increasing production from the Zey Gawra Cretaceous reservoir and commencing production from both the Cretaceous and Tertiary reservoirs in the Banan field.

“We continued to refine our prospect inventory in the AGC Central license area with the remapping of 23 prospects in six structures. We have also identified and ranked a series of wells that will allow us to start exploring the license that has best estimate unrisked gross (working interest) prospective oil resources of 2.2 billion barrels.”


Chaparral Energy

Chaparral Energy, Inc. (NYSE: CHAP) announced its fourth quarter and full year 2018 financial and operational results with the filing of its form 10-K. The company will hold its financial and operating results call this morning, March 14 at 9 a.m. Central.

2018 Highlights

  • Recorded 2018 full year STACK production of 14.5 thousand barrels of oil equivalent per day (MBoe/d), representing a 52% year-over-year increase
  • Achieved 2018 full year total company production of 20.5 MBoe/d
  • Reported full year 2018 net income of $33.4 million, or 73 cents per diluted share
  • Achieved full year 2018 adjusted EBITDA, as defined below, of $125 million
  • Grew 2018 total proved reserves to 94.8 million barrels of oil equivalent (MMBoe), which adjusted for 2018 divestitures marks a 35% year-over-year increase, and represents a PV-10 value of $686 million
  • Increased STACK proved reserves by 50% year-over-year to 74.1 MMBoe, while replacing 519% of STACK production
  • Invested $194.7 million in STACK drilling and completion (D&C) activities in 2018
  • Reduced total company lease operating expense per barrel of oil equivalent (LOE/Boe) almost $4 from $10.96 in 2017 to $7.24 in 2018
  • Strengthened the balance sheet by issuing $300 million of unsecured senior notes and increasing the borrowing base to $325 million in 2018

“Our team is extremely proud of all we accomplished in 2018,” said Chief Executive Officer Earl Reynolds. “From strategically adding to our STACK acreage position to uplisting to the New York Stock Exchange to successfully completing a $300 million senior notes offering and increasing our borrowing base, we were able to increase the value of our assets while also strengthening our balance sheet. In addition, our outstanding operational and drilling results allowed us to significantly grow production and reserves in 2018.”

“While we continue to monitor market conditions and plan to be flexible with our capital expenditures, our current plan for 2019 is to invest $275 to $300 million in capital, more than 80% of which is dedicated to low-cost, high-return STACK/Merge D&C activity. “

Operational Update – STACK Production Soars in 2018

Chaparral increased its STACK production to 16.6 MBoe/d during the fourth quarter, which is up 6% as compared to the previous quarter. Full year STACK production grew by 52% to 14.5 MBoe/d compared to the previous year. Total company production was 21.7 MBoe/d during the fourth quarter, which is a 2% quarter-over-quarter increase. Total company production for the full year was 20.5 MBoe/d, which represents an 11% decrease from the previous year. Excluding production from divested EOR assets in 2017, total company production increased by 13% on a year-over-year basis. Total company production for 2018 was 36% oil, 25% natural gas liquids (NGLs) and 39% natural gas.


Smart Sand

  • 4Q and full year 2018 revenue of $52.2 million and $212.5 million, respectively.
  • 4Q and full year 2018 total tons sold of approximately 610,000 and 2,995,000, respectively.
  • 4Q and full year 2018 net (loss) income of $(4.4) million and $18.7 million, respectively.
  • 4Q and full year 2018 Adjusted EBITDA of $18.7 million and $66.0 million, respectively.

Smart Sand, Inc. (NASDAQ: SND), a producer of high quality Northern White raw frac sand and provider of proppant logistics solutions through both our in-basin transloading terminal and wellsite storage solutions, announced results for the fourth quarter and full year ended December 31, 2018.

Charles Young, Smart Sand’s Chief Executive Officer, stated, “Smart Sand had a good quarter and we’ve responded well to the challenging conditions in the fourth quarter. We recently contracted two sets of last mile storage solutions and have two additional sets ready to be deployed. Our investment in the Van Hook terminal in the Bakken is a strong contributor to our operating performance. We remained focused on our long-term objectives and we’ve proven that we’re profitable through all operating cycles with consistent results of operations. Looking forward, we plan to stay the course in continuing to execute on our already-profitable plan to provide long-term value to the Company, our employees, our customers, and our shareholders.”

Full Year 2018 Highlights

Revenues of $212.5 million for the full year 2018 were the highest in the history of the Company representing a 55% increase over full year 2017 revenue of $137.2 million.  The increase in revenues was primarily due to higher sales volumes resulting from increased exploration and production activity, higher average selling prices of proppant due to increased in-basin sales generated from our Van Hook terminal in the Bakken and favorable price adjustments under certain take-or-pay contracts based on the Average Cushing Oklahoma WTI Spot prices.

Overall tons sold were approximately 2,995,000 in the full year 2018, compared to full year 2017 volume of 2,449,000 tons. Tons sold increased by 22.3% due to increased exploration and production activity in the oil and natural gas industry in 2018 compared to 2017.

Net income was $18.7 million, or $0.46 per basic share and $0.46 per diluted share, for the full year 2018, compared with net income of $21.5 million, or $0.54 per basic share and $0.53 per diluted share, for the full year 2017, a decrease of 13% year over year.

 

 

February 26, 2019

Magnolia Oil & Gas Corporation Announces Fourth Quarter and 2018 Year-End Results

Ring Energy Releases Fourth Quarter and Twelve Month 2018 Financial and Operational Results

February 22, 2019

Cabot Oil & Gas Corporation Establishes Several New Full-Year Records, Returns $1.0 Billion to Shareholders, Repays $304 Million of Debt

February 20, 2019

Energy Transfer Reports Fourth Quarter 2018 Results with Record Performance and Continued Growth

February 19, 2019

Noble Energy, Inc. (NYSE:NBL) Chairman and CEO David Stover said today that the oil and gas industry needs to prioritize capital discipline and corporate returns over top-line production growth.

“Our 2019 capital program and early 2020 outlook aligns capital investment with the environment and sets the stage for Noble Energy to generate sustainable organic free cash flow in 2020 and beyond,” Stover said.

Stover said Noble’s U.S. onshore business is anticipated to be self-funding by the end of 2019 and will underpin the company’s production growth of five to ten percent per year, before the additional impact of major projects.

“We will be completing spend for Leviathan, offshore Israel, this year and commencing production and cash flow from the project by the end of the year,” Stover said in a statement.

“Our early 2020 outlook provides over $500 million in free cash flow(1) at strip pricing, which we plan to return to shareholders through the dividend and share repurchase program.”

Highlights from the company’s 2019 plan include:

  • Organic capital expenditures funded by Noble Energy are planned at a range of $2.4 to $2.6 billion, 17 percent lower at the midpoint compared to 2018.
  • Total company volumes are anticipated in the range of 345-365 MBoe/d, an increase of 5 percent(3)at the midpoint as compared to 2018.
  • The Company’s U.S. onshore business is anticipated to deliver asset-level free cash flow(2)by the end of 2019, while delivering total volume growth of approximately 10 percent(3) and oil production growth of 13 percent(3) from 2018 levels.
  • First gas sales from Leviathan are expected by the end of 2019, delivering substantial production and cash flow growth in 2020.

 

Noble’s plans for organic capital expenditures by area (in $MM) are estimated to be:

United States Onshore 1,600 – 1,700
NBL-funded Midstream 100 – 125
Eastern Mediterranean 550 – 600
West Africa 100 – 125
Other 50
Total 2,400 – 2,600

Sixty percent of the Company’s total organic capital for 2019 is expected to be spent in the first half of the year due to the timing of Leviathan spend and U.S. onshore activity. Excluded from the amounts above is an estimated $195 million of Noble Midstream Partners’ (NYSE: NBLX) capital, which will be consolidated into Noble Energy. Third-party customer activity represents 65 percent of the NBLX capital.

U.S. Onshore

Approximately 90 percent of Noble Energy’s U.S. onshore capital will be focused in the DJ and Delaware Basins. Activity in the DJ Basin includes progressing the second row of development in Mustang, which benefits from the Company’s approved Comprehensive Drilling Plan and access to multiple gas processing providers. In addition, Noble Energy expects to bring online a number of pads within Wells Ranch and East Pony. In the Delaware, operated activity is focused on row development primarily in the Wolfcamp A and Third Bone Spring zones. The Company will continue to optimize base production and cash flows from the Eagle Ford.

Noble Energy expects to commence production in 2019 on between 165-175 wells across the U.S. onshore, including 95-100 in the DJ Basin, 50-55 in the Delaware Basin and approximately 20 in the Eagle Ford. The second and third quarter are planned to have a higher count of wells commencing production as compared to the first and fourth quarters of the year.

The Company anticipates full-year 2019 average U.S. onshore sales volumes of between 262 and 278 thousand barrels of oil equivalent per day (MBoe/d). Combined, production from the DJ and Delaware Basins is expected to increase throughout 2019, up 15 to 20 percent(3) on a full year basis. Sales volumes in the Eagle Ford are anticipated to be lower on a full year basis, with volumes growing from the first half to the second half of the year.

Compared to the second half of 2018, Noble Energy expects capital costs per well in 2019 to be lower by 10 to 15 percent. The majority of these costs savings have been realized through operational efficiencies and lower service costs.

International Offshore

Offshore, the Company is focused on maintaining its strong base production and cash flow in Israel and Equatorial Guinea (E.G.), while progressing the Leviathan project offshore Israel for first gas sales by the end of the year. In addition, Noble Energy expects to sanction the Alen gas monetization project in E.G. in the first half of 2019, with first gas sales estimated for the first half of 2021.

In Israel, gross natural gas sales volumes are anticipated to be flat to up slightly from 2018, reflecting the nearly fully utilized capacity of the Tamar field on an annual basis. Organic capital expenditures in the Eastern Mediterranean primarily comprise spending to complete the Leviathan project. Excluded from the Company’s organic capital expenditures guidance are costs related to an acquisition of interest in the EMG pipeline, which provides a connection point for the export of natural gas from Israel to Egypt.

In E.G., sales volumes are expected to be lower than 2018 due to natural field declines through the year and anticipated downtime for the third-party LNG facility turnaround in the first quarter. The Company’s 2019 capital expenditure guidance includes initial costs for the Alen gas monetization project as well an additional development well at the Aseng oil field to help mitigate field decline. First production from the Aseng development well is anticipated in the third quarter of 2019.

The Company’s new guidance for 2019 replaces its prior 2019 and multi-year outlook, it said in a press release.

First Quarter 2019 Guidance

The Company anticipates sales volumes in the first quarter in the range of 321 to 336 MBoe/d. In E.G., sales volumes are anticipated to be lower than the fourth quarter 2018 by approximately 15 MBoe/d as a result of the timing of oil liftings (production is anticipated to be greater than sales) and the turnaround maintenance at the third-party LNG facility. The variance from the fourth quarter 2018 is estimated to be 40 percent from oil volumes and 60 percent from natural gas volumes, which will also result in equity method investment income being lower than prior quarters.

U.S. onshore sales volumes in the first quarter 2019 are also anticipated to be slightly lower than the fourth quarter 2018 as a result of the timing of well activities in late 2018 and early 2019. The first quarter is planned to be the low quarter for wells commencing production in 2019. Natural decline in the Eagle Ford will also impact the first quarter 2019. Second half U.S. onshore production is anticipated to be approximately 15 percent higher than the first half of the year.

The Company’s planned first quarter organic capital expenditures of between $725 and $800 million are anticipated to be the highest quarter of 2019, driven by the timing of drilling and completion activities in the U.S. onshore business as well as Leviathan spend.

Additional full-year and first quarter 2019 guidance details are available in the latest presentation deck provided on the ‘Investors’ page of the Company’s website, www.nblenergy.com.

Noble  announces 2018 results

Noble also announced full-year 2018 financial and operating results.

Full year 2018 Highlights

  • Returned more than $500 million to shareholders, including $295 million through the Company’s share repurchase program and $208 million through Noble Energy’s quarterly dividend.
  • Strengthened the Company’s balance sheet by paying down $609 million in Noble Energy debt.
  • Enhanced the portfolio to focus on high-return U.S. onshore liquids and international gas by divesting the Company’s Gulf of Mexico assets and midstream ownership in Appalachia.
  • Sales volumes totaled 353 MBoe/d, up 11 percent(1)as compared to 2017, on organic capital expenditures funded by Noble Energy of less than $3 billion.
  • Implemented row development in the DJ and Delaware Basins and grew U.S. onshore oil production 26 percent(1)as compared to 2017.
  • Received approval for the first large-scale Comprehensive Drilling Plan across the Company’s Mustang area in the DJ Basin.
  • Progressed the Leviathan project, offshore Israel, to approximately 75 percent complete.
  • Executed gas sales agreements for up to 700 MMcf/d of natural gas, gross, to customers in Egypt from the Tamar and Leviathan fields.
  • Negotiated Heads of Agreement to progress monetization of natural gas from the Alen field in Equatorial Guinea.

Enable Midstream Announces Fourth Quarter and Full-Year 2018 Financial and Operating Results

February 7, 2019

PANHANDLE OIL AND GAS INC. Reports First Quarter 2019 Results

February 1, 2019

Sizeable profits: ExxonMobil adds $20.8 billion, Chevron $14.8 billion, Shell $21.4 billion

Royal Dutch Shell (stock ticker: RDSA, $RDSA), ExxonMobil (stock ticker: XOM, $XOM) and Chevron (stock ticker: CVX, $CVX) have all reported 2018 earnings during the previous 24 hours.

Shell earns $21.4 billion profit for the year

Royal Dutch Shell started things off, reporting unaudited results yesterday, including full year earnings of $21.4 billion for 2018, which reflected higher realized oil, gas and LNG prices, partly offset by movements in deferred tax positions.

Cash flow from operating activities for the fourth quarter 2018 was $22.0 billion, which included positive working capital movements of $9.1 billion, mainly as a result of a fall in crude oil price and lower inventory levels. Excluding working capital movements, cash flow from operations of $12.9 billion mainly reflected increased earnings, compared with the fourth quarter 2017, Shell said.

Shell upstream

During the quarter, Shell completed the sale of its Upstream interests in Ireland, as well as the disposal of its interests in the Draugen and Gjøa fields in Norway.

In December, Shell and its partners renewed a number of onshore oil mining leases in the Niger Delta for 20 years (Shell interest 30%).

Read Shell’s full press release here.


Exxon tallies $20.8 billion profit

Exxon reported 2018 earnings of $20.8 billion, or $4.88 per share assuming dilution, compared with $19.7 billion a year earlier. Excluding U.S. tax reform and asset impairments, earnings were $21 billion, compared with $15.3 billion in 2017. Cash flow from operations and asset sales was $40.1 billion, including proceeds associated with asset sales of $4.1 billion. Capital and exploration expenditures were $25.9 billion, including incremental spend to accelerate value capture.

Exxon said its fourth quarter 2018 earnings were $6 billion, or $1.41 per share assuming dilution, compared with $8.4 billion in the prior-year quarter. Earnings excluding U.S. tax reform and impairments were $6.4 billion, compared with $3.7 billion in the prior-year quarter.

Exxon Q4 upstream

  • Crude prices weakened in the fourth quarter, while natural gas prices strengthened with higher LNG prices and increased seasonal demand.
  • Natural gas volumes were supported by stronger seasonal gas demand in Europe.
  • Permian unconventional production continued to ramp up in the fourth quarter, with production up more than 90 percent from the same period last year.

Read Exxon’s full press release here.


Chevron captures $14.8 billion profit for 2018

  • Record annual net oil-equivalent production of 2.93 million barrels per day, 7 percent higher than a year earlier; 4 to 7 percent growth targeted for 2019
  • Reserves replacement of 136 percent
  • Dividend increase of $0.07 per share
  • Share repurchases of $1.0 billion in fourth quarter

Chevron ticked off earnings of $3.7 billion ($1.95 per share – diluted) for fourth quarter 2018, compared with $3.1 billion ($1.64 per share – diluted) in the fourth quarter of 2017, which included $2.02 billion in tax benefits related to U.S. tax reform. Included in the current quarter was an asset write-off totaling $270 million. Foreign currency effects increased earnings in the 2018 fourth quarter by $268 million.

Full-year 2018 earnings were $14.8 billion ($7.74 per share – diluted), the company said, compared with $9.2 billion ($4.85 per share – diluted) in 2017. Included in 2018 were impairments and other charges of $1.59 billion and a gain on an asset sale of $350 million. Foreign currency effects increased earnings in 2018 by $611 million.

Chevron said its sales and other operating revenues in Q4 were $40 billion, compared to $36 billion in the year-ago period.

Chevron U.S. upstream

Chevron’s U.S. upstream operations earned $964 million in fourth quarter 2018, compared with $3.69 billion a year earlier. The decrease was primarily due to the absence of the prior year benefit of $3.33 billion from U.S. tax reform, partially offset by higher crude oil production and realizations, Chevron said in a statement.

The company’s average sales price per barrel of crude oil and natural gas liquids was $56 in fourth quarter 2018, up from $50 a year earlier. The average sales price of natural gas was $2.01 per thousand cubic feet in fourth quarter 2018, up from $1.86 in last year’s fourth quarter.

Net oil-equivalent production of 858,000 barrels per day in fourth quarter 2018 was up 187,000 barrels per day from a year earlier.

Production increases from shale and tight properties in the Permian Basin in Texas and New Mexico and base business in the Gulf of Mexico were partially offset by normal field declines and the impact of asset sales of 17,000 barrels per day. The net liquids component of oil-equivalent production in fourth quarter 2018 increased 30 percent to 674,000 barrels per day, while net natural gas production increased 20 percent to 1.10 billion cubic feet per day.

Read Chevron’s full press release here.

On a side note…

The U.S.’s largest independent exploration and production company announced its fourth quarter results yesterday. ConocoPhillips (stock ticker: COP) ($COP) showed earnings of $1.9 billion, or $1.61 per share for the quarter.

For the year, ConocoPhillips earned $6.3 billion in 2018, or $5.32 per share. [Editor’s note: COP’s earnings were not included in the profit tally above; that was strictly generated by the three integrated international oils.]

Conoco has been firing on all cylinders since mid-2017, and has reported six straight quarters of profits, the first time the company has achieved this since Q3 2014. 2018 also represents the first yearly profit Conoco reported since 2014, as its 2017 results were hampered by a major impairment.

Conoco reported it now holds 5.3 billion BOE of reserves, up from 5.0 billion BOE last year. The company replaced 147% of production, with oil accounting for over 90% of new reserves.

Read about Conoco’s good year here.

 

Enterprise Products Partners (stock ticker: EPD, $EPD) has just completed a record-setting tear, based on its 2018 results.

Jim Teague, chief executive officer of Enterprise’s general partner, put it like this:

“Total gross operating margin for 2018 increased 29 percent to a record $7.3 billion compared to $5.7 billion in 2017.”

According to Teague, the partnership established 23 operational and financial records for the year. “All of our business segments reported operational records,” he said in a statement.

Compared to 2017:

  • liquid pipeline volumes increased 9 percent;
  • natural gas pipeline volumes increased 12 percent;
  • marine terminal volumes increased 12 percent;
  • NGL fractionation volumes increased 14 percent; and
  • propylene plant production volumes increased 23 percent.

Enterprise reported record net income attributable to limited partners for 2018 of $4.2 billion, or $1.91 per unit on a fully diluted basis, which represents a 47 percent increase compared to $1.30 per unit on a fully diluted basis for 2017. Net cash flow provided by operating activities (referred to in this press release as “cash flow from operations” or “CFFO”) for 2018 increased 31 percent to a record $6.1 billion. Free cash flow, which is defined as CFFO less net cash used in investing activities plus net cash contributions from noncontrolling interests, for 2018 increased 50 percent to a record $2.0 billion compared to 2017.

Distributable cash flow (“DCF”) increased 33 percent to a record $6.0 billion in 2018 compared to 2017. DCF for 2018 included $183 million of proceeds from asset sales and monetization of interest rate derivatives. Excluding these proceeds, distributable cash flow, provided 1.5 times coverage of the distributions declared with respect to 2018. Distributions declared with respect to 2018 increased 2.5 percent to $1.725 per unit compared to 2017. Enterprise retained $2.2 billion of DCF for 2018, a 155 percent increase from the $867 million of retained DCF for 2017.

“We generated $6.0 billion of distributable cash flow, which allowed us to increase the distributions paid to our partners for the 20th consecutive year while self-funding the equity portion of our growth capital expenditures. We achieved our goal of equity self-funding a year earlier than expected. Today, we announced the authorization of a $2.0 billion multi-year, common unit buyback program that provides us with an alternative means to opportunistically return capital to our limited partners,” said Teague.

“During 2018, Enterprise completed construction and began service on $1.9 billion of organic growth capital projects, including two cryogenic natural gas processing plants in the Delaware Basin and our ninth NGL fractionator at Mont Belvieu. We have another $6.7 billion of growth projects under construction. This includes five major projects scheduled to be completed in 2019, including: the conversion of one of the Seminole NGL pipelines to crude oil service; the Shin Oak NGL pipeline; the third processing train at our Orla complex; our isobutylene dehydrogenation unit at Mont Belvieu; and our ethylene export terminal on the Houston Ship Channel. In addition, our integrated footprint of assets and customer relationships continue to provide new opportunities for growth projects that are currently under development,” said Teague.

Read the full 2018 earnings release here.

August 9, 2018

Heard on The Call: Bonanza Creek Energy

Bonanza Creek Energy is presenting at the EnerCom Conference on Wednesday, August 22nd in Denver.

Bonanza Creek Energy Inc. reported Q2 results today and elaborated on its DJ Basin operations during the company’s Q2 2018 earnings call held August 9. Excerpts from the call are below.

  • Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells
  • Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg
  • Well head pressures effectively managed via Rocky Mountain Infrastructure’s (“RMI”) multiple third-party gas processing optionality
  • Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income(1)of $24.2 million, or $1.18 per diluted share

Q: My question has to do to a 1,000 locations you guys have talked about and I think this is the first time you actually openly speak about. Firstly, are those net locations? And then secondarily, could you give us a little insight as to what that would translate into if you were to be drilling more extended reach laterals?

Bonanza Creek President and CEO Eric Greager: It is the first time we’ve indicated because we needed to complete the resource assessment that we started when I first came on-board in April. And that resource assessment, if you’ve been through these before, it starts with that fundamental understanding of the resource itself.

As you work your way through the resource across the acreage position, combine it with what you understand about spacing, stacking, stimulation design, and the latest application of well performance initiatives, you roll all of that together and that has yielded the 1,000-plus locations. They are – and I want to point out, we’ve stated in our press release and elsewhere, these are SRL equivalents. That’s our measure to keep things clear on that.

And the other point of clarification, I think, I need to make is that they are gross locations and that provides some opportunity for us as we continue to develop the resource and continue to drive and apply more cutting-edge subsurface engineering and development. There’s an opportunity to continue to grow this, but I wanted to qualify, A, they’re gross; and B, they are SRL equivalents.

Q: What is the net equivalent?

President and CEO Eric Greager: Because these are SRL equivalents, I don’t know that we have released the net working interest on all of those leases, Irene. We’re going to take a little bit more time and continue working on that. But it’s – our working interest is large on much of our contiguous acreage and all of these wells are sticked in our contiguous acreage, meaning we didn’t stick up scattered acreage that kind of sat at all by itself.

So, there is upside potential with additional acreage that will be sticked up. We wanted to stick with the more contiguous acreage position, one, because we better understand the continuous resource potential; and two, because we wanted to get this information out as quickly as possible.

Q: Of these locations, how many are Niobraras? And do you have some Codells in there and maybe a little bit on spacing and EURs?

President and CEO Eric Greager: Yeah. It’s – I think EURs are kind of in the same space as net working interest although we’ll be able to guide on net working interest relatively quickly. EURs is something that evolves over time, and that’s something that you can expect to get periodic guidance on. I think what we intend to do going forward here is when we finish our assessment throughout 2018 for the well performance and we move into our budget season for 2019, we’ll begin to lean in and start providing our type curves to help model the business and the programs for 2019. And then each year, you can expect to get new type curves that indicate our best guess. But the thing about given EURs and type curve performance for the longer run is it – it fails really to recognize the upside potential that we continue to drive into the business. And I think there’s a significant amount of upside potential yet to come in terms of how we intend to develop our resource over time.

Q:  And also the split between Niobrara and Codell?

President and CEO Eric Greager: Yeah. I think you can look at the Niobrara and Codell. You can look back on our current distribution between Niobrara and Codell and that’s going to represent itself largely proportionately going forward. So, if it turns out to be a typical 6-well pad for example has 1 Codell and 5 Niobrara and perhaps 2 benches, then I think you can expect that same distribution over time. But the thing that you got to keep in mind is, we’re going to continue to optimize every pad going forward with the very best information we have in terms of spacing, stacking and stimulation design, and the interdependencies of those. And I think what you’ll see in the well performance that we’re releasing this quarter is even in a period as short as a quarter, you can create some substantial uplift in well performance, and we certainly don’t anticipate that growth slowing down over time.

The Oil and Gas Conference®

Bonanza Creek Energy Inc. is presenting at EnerCom’s The Oil & Gas Conference® at the Denver Downtown Westin Hotel, Denver, Colo. Aug. 19-22, 2018. EnerCom expects to have more than 80 presenting oil and gas companies and more than 2000 financial professionals attending this year’s conference.

To learn more about the conference and presenter schedule please visit the conference website here.

August 7, 2018

Carrizo Oil & Gas Inc. (NASDAQ: CRZO) elaborates on current operations and Q2 earnings. The Excerpts from the Q2 Call are below.

Q: Eagle Ford continues to look like you’re having really nice success there. Can you just talk about space in a little bit more there? I know you’ve been able to down space a bit with the Brown Trust and others, but just any comments you could have around how you view the rest of your space and field?

President and Chief Executive Officer S.P. “Chip” Johnson: I think generally we’re sticking with 330-foot spacing in bulk of the acreage. There’s still a couple of places we think 500 feet might be better on the Brown Trust. We did have some of the wells in 250 feet. And so far we haven’t seen any interference or better or worse performance, but we’re still in the early six-month period where everything is on restricted chokes and constrained rate. So it’s hard to tell. I think we’d rather just say 330-foot is the easy answer and we’ll keep trying to figure out ways to tighten that up.

Q: Secondly, Chip, there seemed to be a little confusion or maybe just talk a little bit about the Brown Trust accelerated payout. Is that sort of typical of what you’re seeing on a lot of your plays? And again, I mean, frankly I was glad to see it, but I just – if you could talk maybe a bit more about that?

President and Chief Executive Officer S.P. “Chip” Johnson: Well, I don’t think we have back-ins after payout anywhere else in our inventory. We used to – we bought out some of those partners three or four years ago. But this was an arrangement we got into with a major where we had at least half the minerals, they own the other half, and we made a deal with them eight years ago where we could drill and they could either participate or they could back-in after payout. And sometimes they participate, sometimes they back in.

This time, they’re going to back in. And this had been in the fourth quarter. We probably would have had to draw attention to it. But if it had just been in the middle of the year, it wouldn’t have made much difference. But they have 1,000 barrel a day drop in production in the fourth quarter. We felt like we needed to point that out. Otherwise, we thought this would have happened in the first or second quarter of next year.

Q: When that just balances, I guess that’s just sort of a onetime item then, correct?

President and Chief Executive Officer S.P. “Chip” Johnson: On those wells. Next year when we bring on more wells in the Brown Trust, if that company has not participated, then it’ll start another back-in after payout on those wells.

The good thing was we made that much more EBITDA this year than we expected to, because of the raise in the oil prices. So, we felt like it was a good thing.

Q: Just wanted to follow up a little bit on what you’d said there on the Permian and, clearly, you guys were talking about lower activity as you work later this year. But I guess just from a high level, should we expect Permian to continue to grow in the third quarter and then also in the fourth quarter or do you start to see Permian flatten out or even decline a little late this year in terms of the production there? And then into the first half of 2019, just a similar question, does Permian grow? Does it flatten? Does it decline? How do you see that playing out with the activity shift?

Vice President of Investor Relations Jeff P. Hayden: So, if you think about it, you just kind of add on a little bit in some of those questions about activity. What you probably see just given the drilling activity in Eagle Ford this year, and then in fact we’re keeping four rigs there for the first half of next year, I think it’s safe to assume that you probably see the completion activity weighted to the Eagle Ford in the first half of the year. And then it’ll probably be weighted a little more towards Permian in the back half of the year. Given that, what you’re probably going to looking at in the Permian is kind of a flattening. I don’t know if you’ll necessarily see a decline, but maybe a flattening of production over the next several quarters. And then as you get kind of later next year, you probably see the Permian start to incline a lot more as we start increasing the completion activity out there.

In the meantime, I think, between now and then you’re going to see a lot of production growth likely in the Eagle Ford Shale as we kind of shift our activity over there.

Q: I guess is it safe to assume that the changes you guys have made, a shift in capital to Permian that basically all your Permian acreage as you’re looking to protect will get held over the next year here?

President and Chief Executive Officer S.P. “Chip” Johnson: We’ve got a drilling schedule in the Permian that takes care of our acreage. That’s still something – that’s the most critical thing we have to do at this point.

Q: Okay. Now that makes sense for sure. And I guess just lastly on the asset sale that you guys had just mentioned here. Just trying to get a sense in terms of magnitude, if you guys could let us know what the proceeds are and is this a one-off deal or might you guys monetize other little bits and pieces of the Permian going forward?

President and Chief Executive Officer S.P. “Chip” Johnson: Well, I guess in the past we’ve actually sold some little bits and pieces. This one, especially because it was non-op and the new owner, the new operator of these assets was pretty aggressive about capital spending. We felt like this could reduce our non-op CapEx budget significantly over the next two years and we felt like we got a good price for it. Part of our CapEx increase this year has been non-op. We have some other non-op partners who ramped up their activity in different parts of the core of the Delaware Basin and so we’ve had to increase our CapEx for that. But we felt like this was a good chance to maybe get out of some non-op at a good price and reduce that exposure to somebody else’s capital footprint.

August 2, 2018

Nabors Industries (NYSE: NBR) held its Q2 conference call today; excerpts from the Q & A are below:

Q: Tony, you mentioned that your latest survey has another 30 to 40 rigs being added to the rest of this year. And I would tell you, consensus from most investors that I’ve spoken with, is that we’re going to see a meaningful fall off in the Permian, maybe as much as 75 rigs. And so, overall, U.S. rig count is going to suffer modestly. So, this is a very different opinion. Obviously, I assume you’re closer to the customer than most of my – investors I’ve talked to. Give us more color on these rigs. Or are we going to see a decline in the Permian, or does the Permian stay flat and you add in the Eagle Ford and other areas? Just help us understand where that’s going.

Chairman, President and Chief Executive Officer Anthony G. Petrello: Sure. I hate to be the guy in the outlier here. So that’s the reason why we did these surveys because this information doesn’t come from me, it comes from the customers and that’s what the customers told us. Now, I know it runs a little counter to the major concern regarding the differentials in West Texas. So, that led us to go back and we just did this past 48 hours.

We went back to the top 20 operators in the Permian, and we asked them specifically about their limitation for pipeline access. And while our information may not be perfect, it suggested that only 2 of

During the Q2 conference calls this week, some enlightening comments were made by oil and gas company CEOs.

Chesapeake Energy (NYSE:CHK) CEO Doug Lawler examines 2019 goals

Q: Can you talk about 2019 and what the broad parameters of how that is going to look. It sounds like you guys are planning to stop the outspending versus cash flow and now spend within cash flow. And is that the right read on 2019? And what’s the kind of commodity price at which we should think about that being a valid read? And how are you – I know it’s early, but how are you projecting oil volumes to grow and your overall volumes to grow?

Chesapeake Energy CEO Robert Douglas Lawler: Sure, We’re happy to provide a little more clarity with that. And as we’ve stated, we anticipate our 2019 oil volumes to grow by 10% and this recognition of our ability with the remaining assets post Utica divestiture of being able to replace that EBITDA within a year speaks to the capital efficiency and the cash flow generating capability of our assets.

As we look forward to 2019, the reduction in our interest expense, it will help us as we pay down some of our debt. But we anticipate that that free cash flow neutrality is – as a primary target will be something that we have to continue to look at. And as noted, in 2019, we aren’t forecasting any major asset sales. But through our own operations from our existing assets, we expect that production growth will help us in reducing any outspend.

Nick’s point on the sustainable free cash flow at this point and you look to 2019, we will accomplish that principally through our organic production growth, but we will also have and continue to look at smaller asset sales and other opportunities for us to generate cash.

What we’re excited about is that, as I noted, each of the assets are free cash flow positive today, with the exception of the Powder, and the oil’s growth, strength there, we clearly will achieve that in 2020, but targeting with the team to try to achieve that in 2019.

So, our objective to be free cash flow positive is very strong. And from an operating cash flow basis, we’re there. When you look at all the other corporate liabilities that we have, we’re making excellent progress on that and expect to share good results with you as we progress.

Anadarko Petroleum (NYSE: APC) – Delware goal is $8 million per well, DJ is $3 million

Q: What are your current well costs in each basin for the second quarter? What was your AFE or spending in Delaware and DJ?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: So, from a Delaware standpoint, we’ve communicated previously we’ve got around $8 million is what we expect per copy once we’re in the development mode. We’re higher than that now, as we’ve communicated. It’s closer to $10 million. As we think about DJ, it’s I’d say sort of tilted to $3 million but it depends on the lateral length. And so, the longer wells obviously cost you more, the shorter wells are a little bit less. But think of it as around $3 million.

Q: As you go into 2019, does the Gulf of Mexico pick up a little bit more relative capital versus the onshore business?

Chairman, President and Chief Executive Officer Robert A. Walker: I’d say it’s more of a steady state, but if the options are such that we feel like we want to change that, we can, picking up a spot rig is not particularly difficult. So, I wouldn’t read too much into the implied rig schedule suggesting activity. But I think for us, Gulf of Mexico is two things, it’s more of a steady-state environment that throws off a lot of free cash flow, and that’s real attractive. And if you’re right, we see a tremendous price differential between WTI, LLS, and Brent, where the waterborne has a tremendous advantage, it’s just going to throw off more free cash flow. And I think that’s really the state that we see ourselves in.

Q: At least on our numbers, we’re pretty much in line with strip for the next three or four years, I guess. We still see substantial free cash if you maintain, which I expect you will, your capital discipline. Also, the $1 billion increase in the buyback is terrific. But how do you think about that going forward? It seems to me that you could reload that for a pretty much an extended period. And I’ll leave it there. Thanks.

Chairman, President and Chief Executive Officer Robert A. Walker: Yeah, I think you’re seeing it consistent with the way we see it and hopefully we’re both right. But we definitely believe the approach we’re taking today has tremendous durability. So, we don’t see it as something that’s just very temporary. Obviously, if oil backs up to $40, we’re going to be in a situation like many where we’re going to rethink what we want to do with our capital investments. But in a $50-plus environment and we’re throwing off a lot of free cash flow, there’s tremendous durability to buying back stock, retiring debt, and periodically looking at increasing our dividend which we think, coupled with the attractive growth that we can throw off at $50 as the steady state, is a pretty good business model.

Q: In the Delaware, can you take us through the next year in terms of how you expect your productivity and efficiency to evolve? Specifically, what your expectations are for the percent of your overall rig fleet drilling the multi-well pads, where you think lateral length can go, any shifts in completion methodology? And then you highlighted the goal of $8 million well costs from $10 million. When do you expect to achieve that?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: Thanks for the question. I’ll try to address them and if I miss one along the way, just remind me afterwards. Obviously, from a – since you’re talking about over the course of the next year or so, clearly our capital plans for 2019 we’ll be talking about in more detail in the fourth quarter. So, I won’t go into too much detail there. But from a general standpoint, we have been, we’ve been working our gen two completions which are, essentially, like some others in the industry, higher water content, higher proppant, closer spacing. We’ve been pleased with the performance we see there. I anticipate that that will be our completion style as we move through certainly the foreseeable future. Our pad development has been, I would say, hovering around 50% currently for 2018. But I’ll say the pads we’ve been able to do aren’t – that’s more than one well. And so, some of these pads are only two-well pads which gets us some efficiency, but not the significant efficiency increases we would expect to see as we get to really substantial multi-well pads which is what we’re looking forward to doing. So, four or five wells per pad is obviously going to be much more efficient for us as we go to two.

So, as we look forward from here, we should see the amount of wells that we’re drilling on pad increase, and the actual wells per pad to increase, both of which will then drive increasing efficiency through the system. So, that’s what I’d say on that. Hopefully I got everything.

Q – Yeah. All but maybe the one, which is that $8 million well cost goal. When would you expect to achieve that?

Executive Vice President of U.S. Onshore Operations Daniel E. Brown: Yeah. So, we’re currently thinking over the course of – as we get to our multi-well pad developments where we’re doing four to five wells per pad, that’s what we’re anticipating. We think over the course of the next, say, two or three years we should be transitioning over where substantially all of our development is sort of in that kind of place. And so that’s how we’d expect that to work over time. So, once we’re doing four to five wells per pad, that’s the type of well costs you should see and we think that transition is going to take place over the next few years.


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