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SM to 'Spend Less' in 2020, Become Permian-Focused Co; Touts Q3 Well Cost Cuts

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   |    Monday,November 04,2019

SM Energy reported its Q3 results. Below are highlights (for the full release, scroll down below analysis).

Hints at 2020 Plans; 'Will Be Less Than 2019'

While SM Energy didn't go into detail about its 2020 plans, the company did note that it will be spending less than it did in 2019.

In its Q2 report, the company noted 2020 average capital spending of ~$80-90 million per month (~$255 million per quarter for a total of $1.02 billion). SM's 2020 capex will likely be less than $1.02B due to its Q3 commentary that said it will be spending less than 2019.

Preparing to be a Permian Focused Company

In the call, SM talked about plans for 'reorganization' - which centers on largely closing up shop in the Eagle Ford and focus solely on the Permian Basin.

Question: The reorganization that you're implementing, wanted to see if that is going to limit your ability to grow in the future or does it give us an indication of your outlook that you're kind of preparing the company for a lower growth area in oil and gas?

• Jay Ottoson commented: "I think are -- really what we're looking at -- we're just looking at our activity operates mostly in operating reorganization in the sense that we've always run as a regionally focused company. And when you look at our planned operations now for the next few years, we're going to be largely Permian based. And as you start to look at there is redundancies obviously in management positions and other things by having a regionally focused organization. So it just makes sense to us, to simplify our operations and eliminate some of those redundancies right now. We're going to continue to have a robust exploration effort here, continued robust looking at new opportunities, business development. We're not cutting those functions. Really, this is just an opportunity to streamline -- the operations portion of our business."

Well Cost Improvements

The company commented: "We pumped more than nine stages per day per spread on average in the Midland Basin, a 23% improvement from our expectations, and that directly translated into quantifiable capital efficiency as our well costs are now averaging right at $700 per lateral foot."

Wells Cost Reduction - Eagle Ford

• Herb Vogel: "So you probably seen in previous earnings reports, we've talked about $650 per foot in the Eagle Ford, and we expect the same sort of environment there which would be deflation in addition to completion enhancements, and we have specifically identified where those could be, and we would implement those next year."

Drops Completion Crew to Save Capital

Brad Heffern: "Okay. And then you guys mentioned that you dropped the second Permian completion crew, is the plan for that to stay down for all of the fourth quarter and then for it to come back at the beginning of next year?"

Herb Vogel: "Brad, this is, Herb. So we were running three frac spreads in the third quarter and we dropped to two just at the very beginning of October. And we're just going to continue that until we get our budget lined out and we'll figure out the level, will be doing next year, at that time."

SM Q3 2019 PRESS RELEASE

SM Energy Co. announced financial and operating results for the third quarter of 2019.

Highlights include:

• Production exceeded expectations - Third quarter 2019 total production was 12.4 MMBoe (134.9 MBoe/d), 44% oil and 61% liquids. Production exceeded the Company's guidance range by 0.2 MMBoe, or 2,250 Boe/d, driven by better than expected well performance and two accelerated Austin Chalk wells in South Texas.
• Permian operations continue to rank top tier - The Company's high oil content assets generate among the highest realized price per Boe in the Basin, averaging $44.77 in the third quarter, while capital efficiencies continue to reduce the current average RockStar drill, complete and equip costs to approximately $700 per lateral foot.
• New South Texas wells generating higher oil/liquids production - Two recent Austin Chalk wells each delivered on average more than 800 Bbls/d oil peak 30-day IP rates. Twelve new design wells (Lower Eagle Ford) in the Briscoe area reached peak 30-day IP rates averaging 2,532 Boe/d (3-stream), including 463 Bbls/d oil.

President and Chief Executive Officer Jay Ottoson comments: "Our third quarter results continue to demonstrate the quality of our Midland Basin assets and execution.  Our efforts to prove up oily economic drilling inventory in our large South Texas operating area are showing success.  As we go forward, we expect to allocate a high percentage of our capital to the Midland Basin, while focusing our investment in South Texas on these higher margin opportunities.  Our capital efficiency continues to improve, and we have taken steps to streamline our organization and reduce cash costs. We expect to generate free cash flow in the fourth quarter of 2019 and our corporate objective is to generate free cash flow, reducing absolute debt and leverage in 2020."

Well Results Summary

     ROCKSTAR

New well results include RockStar area wells that reached their peak 30-day IP rates subsequent to the Company's August 2019 update: 11 new RockStar wells drilled into the Wolfcamp A and Lower Spraberry intervals, at locations that span the acreage position, having an average lateral length of 10,150 feet, delivered peak 30-day IP rates that averaged 1,180 Boe/d per well and 90% oil. All of the wells were half or fully bounded.

     SOUTH TEXAS

In the South Texas, efforts to drive value and inventory through more efficient well design and testing the higher liquids content/higher margin Austin Chalk are showing success.

• The Galvan Ranch B904H Austin Chalk test is the best Company oil well drilled to date in South Texas, based on its peak 24-hour IP rate of 3,900 Boe (3-stream), with approximately 1,100 Bbls oil. The two new Austin Chalk wells were drilled in the eastern and northern areas of the Company's South Texas acreage, intended to demonstrate the geographic extensions of the Austin Chalk across the Company's acreage position. The wells were drilled with approximately 11,300' laterals. While results are early stage, the oil content of these wells is particularly encouraging.
• As reported during the quarter, four new design Lower Eagle Ford wells reached peak 30-day IP rates averaging approximately 3,000 Boe/d (3-stream) each with 560 Bbls/d oil, or 19% oil and 41% NGLs. The wells are part of the Company's joint development program. With more than 90 days of production, these wells demonstrate cumulative production curves consistent with expectations.
• Eight additional new design Lower Eagle Ford wells (also part of the joint development program) with average lateral lengths ranging between 8,200' and 15,000' reached peak 30-day IP rates during the quarter that averaged approximately 2,300 Boe/d (3-stream) each, with 18% oil and 42% liquids.

• Permian volumes increased 11% year-over-year and were flat sequentially.
• Oil sales comprised 75% of production revenue.
• As projected, there were shut-in volumes during the quarter related to offset well completion activity and other impacts.

• Benchmark pricing for the quarter included NYMEX WTI at $56.45/Bbl, NYMEX Henry Hub natural gas at $2.23/MMBtu and Hart Composite NGLs at $18.89/Bbl.
• In the Permian Basin, the Midland-Cushing oil differential improved to approximately ($0.61)/Bbl on average for the three months while the WAHA-NYMEX natural gas differential improved to approximately ($1.43)/MMBtu.
• The average realized price per Boe of $31.39 is before the effect of hedges. Including the effect of realized hedges, the average price was $33.38 per Boe, resulting in approximately $24.7 million of realized net hedge gains for the quarter.

Q3 Financials

Third quarter of 2019 net income was $42.2 million, or $0.37 per diluted common share, compared with a net loss of ($135.9) million, or ($1.21) per diluted common share, in the third quarter of 2018.  For the first nine months of 2019, net loss was ($84.9) million or ($0.76) per diluted common share.

Third quarter of 2019 net cash provided by operating activities was $203.2 million.  For the first nine months of 2019, net cash provided by operating activities was $581.6 million.

The following paragraphs discuss adjusted EBITDAX, adjusted net income (loss), and adjusted net income (loss) per diluted common share, all of which are non-GAAP measures.  Please reference the definitions and reconciliations of these measures to the most directly comparable GAAP financial measures at the end of this release.

Third quarter of 2019 adjusted EBITDAX was $257.8 million.  Adjusted EBITDAX is largely unchanged year-over-year as higher production in the 2019 period was offset by higher realized (post-hedge) prices in the 2018 period.  Sequentially, adjusted EBITDAX was largely unchanged given comparable production and operating margins.

Third quarter of 2019 adjusted net loss was ($12.1) million, or ($0.11) per diluted common share, compared with adjusted net loss of ($1.0) million, or ($0.01) per diluted common share, in the third quarter of 2018.  For the first nine months of 2019, adjusted net loss was ($48.5) million, or ($0.43) per diluted common share.

COMMODITY DERIVATIVES

As of October 30, 2019, the Company had commodity derivatives in place for the fourth quarter of 2019 that included:

• WTI oil hedges for approximately 90% of expected oil production;
• HSC natural gas hedges for approximately 70% of expected natural gas production;
• Midland-Cushing differential hedges for approximately 60-65% of expected Permian oil production; and
• WAHA natural gas hedges for approximately 40% of expected Permian residue natural gas production (assumes ethane rejection.)

Detailed data on derivatives are provided in the accompanying IR presentation and the Company's Quarterly Report on Form 10-Q for the third quarter of 2019.

Financial Position

On September 30, 2019, the outstanding principal amount of the Company's long-term debt was $2.5 billion in senior notes plus $172.5 million in senior convertible notes, and $129.0 million drawn on the Company's senior secured revolving credit facility.  Amounts drawn under this facility increased by $11 million sequentially, keeping total net debt nearly flat compared with the second quarter of 2019.

Subsequent to quarter-end, the Company's lenders reaffirmed the senior secured revolving credit facility borrowing base of $1.6 billion and commitment level of $1.2 billion.  The Company had $1.1 billion of liquidity at quarter-end.

Costs incurred in oil and gas activities for the third quarter of 2019 were $270.9 million.  Total capital spend (a non-GAAP measure defined and reconciled below) for the quarter was $263.4 million.  During the third quarter, the Company drilled 22 net wells and had 19 net flowing completions in the Permian and drilled six net wells and completed six net wells in South Texas.

• During the third quarter, the Company continued to realize capital efficiencies in the form of increased lateral feet drilled per day and more stages completed per day. As a result, the Company completed more wells in the first nine months of 2019 than expected (including completed wells that have not been put on production), reduced the number of completion crews in the Permian to two, and Company-operated South Texas well completions have been concluded for the year.
• A number of wells in the Permian at quarter-end were completed but not yet producing in order to manage and reduce flowback costs.

Updated Guidance

• Full year expected production: raised at the mid-point to 47.5 - 47.9 MMBoe, or 130-131 MBoe/d, with approximately 44% oil in the commodity mix. Implied fourth quarter production is 12.0-12.4 MMBoe or 130.4-134.8 MBoe/d and assumes ethane rejection for NGL volumes and certain shut-in volumes related to maintenance, offset activity and other.
• Full year expected total capital spend: unchanged at $1,000 - 1,050 million. Implied fourth quarter total capital spend is $160-210 million. Expected net completions for 2019 are unchanged at 100+ in the Permian and 19 in South Texas.
• Full year expected general and administrative expense: the Company expects to continue to concentrate capital in the Midland Basin and has initiated a reorganization to eliminate duplicate regional functions and reduce overhead costs. As a result, the Company expects to take an associated charge to G&A in the fourth quarter of 2019. Guidance is revised to $125-130 million including non-cash compensation and reorganization charge.
• Full year expected LOE per Boe is reduced to $4.70-$4.80. The implied fourth quarter LOE per Boe is $4.80-$5.15.
• Full year expected transportation expense per Boe is reduced to $4.05-$4.15. The implied fourth quarter transportation per Boe is $4.15-$4.40.