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Southwestern Mum on 2020 Plans, but Expects 'Reduced Capital', 'Front Loaded'

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   |    Friday,October 25,2019

Southwestern Energy Co. announced its Q3 results as well as gave a vague outlook for 2020.

'Expects Reduced Capital Plan' for 2020 - Front Loaded

In its call, the company commented: "While it's still too early to be definitive on specific 2020 targets, let me give you some brief color on how we are thinking about capital allocation. For the second year of our transition plan, capital investment will be limited to cash flow based on strip pricing at the time we set our plans, plus up to $300 million of the remaining monetized Fayetteville cash flow. Should the strip at the time we set our budget in 2020, we lower than we set the '19 plan, I would expect a reduced capital program.

"Consistent with prior years, we expect to have a front loaded program in 2020 as well.

"If the forward curve goes down from where we set the budget, I would expect the capital program will be lower for 2020. And to be clear the discipline around this capital allocation that you've come to know over the last several years remains unchanged."

Q3 Highlights:

  • Leading operational efficiency gains expected to result in full-year wells to sales at the high end of guidance while not exceeding $1.15 billion annual capital investment;
  • Beating 25% reduction target for full-year average well costs, averaging $784 per lateral foot and 10,466 feet lateral length in the quarter;
  • Condensate production of greater than 15 MBbls per day, up 50% from second quarter, contributing 19% of E&P revenues;
  • Total production of 202 Bcfe, including 22% liquids at approximately 80 MBbls per day;
  • Borrowing base reaffirmed, revolver maturity extended one year to 2024, no borrowings outstanding under $2 billion commitment as of September 30, 2019;
  • Realized $88 million of settled derivative gains, increasing weighted average realized price by $0.44 per Mcfe; and
  • Reported weighted average realized price of $2.55 per Mcfe, including derivatives and excluding transportation.

 

President & CEO Bill Way commented: "The SWN team continues to innovate and deliver value, embracing the challenges our industry faces today. Our people are driving improved operational efficiency and cost structure, maximizing cash flow, increasing well performance and optimizing base production.

"In this volatile commodity environment, resiliency is key today and going forward. The intentional actions we have taken over time and continue to take to strengthen our balance sheet, coupled with operational execution, are all a part of our deliberate transition back to free cash flow, without compromising long-term value. We are in an enviable position with our debt maturity profile to take advantage of financial, operational and strategic opportunities."

Operational Discussion

Total production was 202 Bcfe, an 8% increase compared to the prior year third quarter excluding Fayetteville, including 158 Bcf of gas production, 1.4 MMBbls of oil production and 5.9 MMBbls of NGL production. Oil production was up 42% compared to the third quarter of 2018 and liquids increased to 22% of total production for the quarter ended September 30, 2019.

Capital invested was on plan at $240 million, 35% lower than the second quarter. During the third quarter, SWN drilled 24 wells, completed 30 wells and placed 34 wells to sales. The average well cost for wells to sales in the third quarter of 2019 was $784 per lateral foot, with an average lateral length of 10,466 feet. In the first nine months of 2019, the Company drilled 95 wells, completed 101 wells and placed 89 wells to sales, with well costs for wells to sales averaging $849 per lateral foot.

Three Months Ended September 30, 2019 E&P Division Results

 

Appalachia

   

Northeast

 

Southwest

Gas production (Bcf)

 

118

 

40

Liquids production

       

Oil (MBbls)

 

-

 

1,413

NGL (MBbls)

 

-

 

5,908

Production (Bcfe)

 

118

 

84

Gross operated production as of September 2019 (MMcfe/d)

 

1,553

 

1,707

Net operated production as of September 2019 (MMcfe/d)

 

1,258

 

1,059

         

Capital investments ($ in millions)

       

Exploratory and development drilling, including workovers

 

$

65

 

$

109

Acquisition and leasehold

 

-

 

9

Seismic and other

 

1

 

-

Capitalized interest and expense

 

8

 

36

Total capital investments

 

$

74

 

$

154

         

Gross operated well activity summary

       

Drilled

 

10

 

14

Completed

 

14

 

16

Wells to sales

 

13

 

21

         

Average well cost on wells to sales (in millions)

 

$

6.5

 

$

9.2

Average lateral length (in ft)

 

8,739

 

11,534

         

Total weighted average realized price per Mcfe, excluding derivatives

 

$

1.49

 

$

2.04

Southwest Appalachia's total production averaged 913 MMcfe per day, which represents a 27% growth over the prior year quarter. Natural gas production was 440 MMcf per day, oil production was 15.4 MBbls per day and natural gas liquids production was 64.2 MBbls per day. Similar to the previous quarter, natural gas liquids volumes were reduced to capture greater value through ethane rejection into the gas stream.

The Company drilled 14 wells, completed 16 wells and placed 21 wells to sales in the quarter. Of the 21 wells to sales, 20 were Marcellus wells, 16 located in the Company's super rich acreage and four located in the rich acreage. The Company also brought online its fourth Upper Devonian well, its first located in the super rich acreage, with initial standalone performance in line with offset Marcellus wells in the area.

Nine of the super rich wells were online for at least 30 days and had an average 30-day rate of 13 MMcfe per day, while the four rich wells were all online for at least 30 days and had an average 30-day rate of 27 MMcfe per day, representing a 60% and 100% increase year over year, respectively, primarily driven by lateral length and well performance.

Northeast Appalachia's total production averaged 1.3 Bcf per day, essentially flat with prior year quarter.

During the third quarter, the Company drilled 10 wells, completed 14 wells and placed 13 wells to sales. Of the nine wells online for at least 30 days, six were Lower Marcellus with an average 30-day rate of 15 MMcf per day, 14% higher than the prior year quarter. Three of the nine were new generation Upper Marcellus tests with an average 30-day rate of 10 MMcf per day, in line with expectations.

As a part of its ongoing base optimization efforts, the Company began to see the benefit of recently installed pad compression, resulting in an initial gross production uplift of 55 MMcf per day. These continued efforts are reducing the base decline and can be applied across a broader area.

OPERATING STATISTICS

 

For the three months ended

 

For the nine months ended

 
   

September 30,

 

September 30,

 
   

2019

 

2018

 

2019

 

2018

 

Production

                 

Gas production (Bcf)

 

158

   

215

   

449

   

613

   

Oil production (MBbls)

 

1,419

   

998

   

3,210

   

2,334

   

NGL production (MBbls)

 

5,911

   

5,181

   

17,011

   

14,272

   

Total production (Bcfe)

 

202

   

252

   

570

   

712

   
                   

Division Production

                 

Northeast Appalachia (Bcf)

 

118

   

121

   

343

   

341

   

Southwest Appalachia (Bcfe)

 

84

   

66

   

227

   

172

   

Fayetteville Shale (Bcf) (1)

 

-

   

65

   

-

   

199

   
                   

Average unit costs per Mcfe

                 

Lease operating expenses (2)

 

$

0.94

   

$

0.92

   

$

0.92

   

$

0.93

   

General & administrative expenses (3)

 

$

0.15

 

(4)

$

0.18

   

$

0.17

 

(4)

$

0.19

 

(5)

Taxes, other than income taxes

 

$

0.08

   

$

0.09

   

$

0.09

   

$

0.08

 

(6)

Full cost pool amortization

 

$

0.58

   

$

0.52

   

$

0.57

   

$

0.50

   

(1) The Fayetteville Shale assets were sold on December 3, 2018.
(2) LOE includes post-production costs such as: gathering, processing, fractionation and compression charges.
(3) Excludes restructuring charges.
(4) Excludes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $3 million of legal settlement charges for the three and nine months ended September 30, 2019.
(5) Excludes $8 million of legal settlement charges for the nine months ended September 30, 2018.
(6) Excludes $1 million on restructuring charges for the nine months ended September 30, 2018.

Financial Results

The table below summarizes financial statistics. Year over year results are not comparable as prior year's results include the contribution of Fayetteville assets, which were sold in December 2018.

FINANCIAL STATISTICS

 

For the three months ended

 

For the nine months ended

   

September 30,

 

September 30,

(in millions)

 

2019

 

2018

 

2019

 

2018

Net income (loss) attributable to common stock

 

$

49

   

$

(29

)

 

$

781

   

$

229

 

Adjusted net income attributable to common stock (non-GAAP)

 

$

44

   

$

146

   

$

229

   

$

414

 

Diluted earnings (loss) per share

 

$

0.09

   

$

(0.05

)

 

$

1.44

   

$

0.39

 

Adjusted diluted earnings per share (non-GAAP)

 

$

0.08

   

$

0.25

   

$

0.42

   

$

0.71

 

Adjusted EBITDA (non-GAAP)

 

$

202

   

$

377

(1)

 

$

707

   

$

1,090

(1)

Net cash provided by operating activities

 

$

196

   

$

307

   

$

739

   

$

971

 

Net cash flow (non-GAAP)

 

$

185

   

$

355

   

$

667

   

$

993

 

Total capital investments (2)

 

$

240

   

$

298

   

$

933

   

$

1,039

 

(1) Includes $99 million and $291 million of Adjusted EBITDA from the divested Fayetteville Shale assets for the three and nine months ended September 30, 2018, respectively.
(2) Capital investments on the cash flow statement include decreases of $53 million and $31 million for the three months ended September 30, 2019 and 2018, respectively, and increases of $52 million and $21 million for the nine months ended September 30, 2019 and 2018, respectively, relating to the change in accrued expenditures between periods.

Southwestern Energy reported net income attributable to common stock of $49 million, or $0.09 per share, and adjusted net income (non-GAAP) of $44 million, or $0.08 per share. The decrease in adjusted net income as compared to the third quarter of 2018 is primarily due to decreased commodity prices, partially offset by an $88 million increase in the gain from settled derivatives. Adjusted EBITDA (non-GAAP) was $202 million, net cash provided by operating activities was $196 million and net cash flow (non-GAAP) was $185 million.

In the third quarter, the Company benefited $0.44 per Mcfe from the impact of settled commodity derivatives, reporting a weighted average realized price of $2.16 per Mcfe, essentially the same as in the second quarter, even with the lower commodity price environment. Excluding $0.39 per Mcfe in transportation costs, weighted average realized price for the third quarter was $2.55 per Mcfe. The Company benefited from its rolling three-year hedging program, continued focus on condensate production and optimizing its low-cost transportation portfolio.

By commodity, including the benefit of derivatives, SWN's realized natural gas price was $1.87 per Mcf, oil realizations were $49.67 per Bbl and NGL realizations were $11.93 per Bbl. Excluding derivatives, the natural gas differential to NYMEX was $0.78 per Mcf, oil differential to WTI was $9.91 per Bbl and NGL realizations were 16% of WTI. All realized prices include the cost of transportation.

The Company added derivatives for 2020 during the quarter, bringing the total financial derivative volumes for next year to 360 Bcf of natural gas, 2,837 MBbls of oil and 7,137 MBbls of NGLs. Of the natural gas volumes hedged in 2020, over half are protected by collars, which limits exposure to the downside risk while allowing for upside. The 2020 natural gas three-way collars have an average floor price of $2.67 per MMBtu, a ceiling price of $2.98 per MMBtu and a sub-floor price of $2.34 per MMBtu. Fixed price swaps comprise 42% of 2020 natural gas hedges with an average strike price of $2.58 per MMBtu and settlement dates primarily in the second and third quarters.

At September 30, 2019, the Company had cash of $29 million, an undrawn revolver of $2 billion, total debt of $2.3 billion and a trailing 12 month net debt/EBITDA ratio of 2.2 times, excluding the benefit of Adjusted EBITDA associated with the Fayetteville Shale. During the quarter, the Company repurchased $50 million of senior notes at a discount of 13%, which will reduce interest costs on senior notes by $21 million until maturity. These repurchases were funded principally by sales of non-core, non-producing assets.

In accordance with its planned activity reduction, Southwestern Energy invested capital totaling $240 million, including capitalized interest and expense of $45 million, bringing year to date capital investment to $933 million. As announced earlier this year, annual capital investment is not expected to exceed $1.15 billion.

REALIZED PRICES

 

For the three months ended

 

For the nine months ended

(includes transportation costs)

 

September 30,

 

September 30,

   

2019

 

2018

 

2019

 

2018

Natural Gas Price:

                       

NYMEX Henry Hub price ($/MMBtu)(1)

 

$

2.23

   

$

2.90

   

$

2.67

   

$

2.90

 

Discount to NYMEX (2)

   

(0.78

)

   

(0.76

)

   

(0.63

)

   

(0.62

)

Realized gas price per Mcf, excluding derivatives

 

$

1.45

   

$

2.14

   

$

2.04

   

$

2.28

 

Loss on settled financial basis derivatives ($/Mcf)

   

(0.01

)

   

(0.03

)

   

(0.02

)

   

(0.04

)

Gain on settled commodity derivatives ($/Mcf)

   

0.43

     

0.05

     

0.18

     

0.07

 

Realized gas price per Mcf, including derivatives

 

$

1.87

   

$

2.16

   

$

2.20

   

$

2.31

 

Oil Price:

                       

WTI oil price ($/Bbl)

 

$

56.45

   

$

69.50

   

$

57.06

   

$

66.75

 

Discount to WTI

   

(9.91

)

   

(8.30

)

   

(9.92

)

   

(7.24

)

Realized oil price per Bbl, excluding derivatives

 

$

46.54

   

$

61.20

   

$

47.14

   

$

59.51

 

Realized oil price per Bbl, including derivatives

 

$

49.67

   

$

59.96

   

$

49.74

   

$

58.69

 

NGL Price:

                       

Realized NGL price per Bbl, excluding derivatives

 

$

8.89

   

$

21.60

   

$

11.24

   

$

17.65

 

Realized NGL price per Bbl, including derivatives

 

$

11.93

   

$

19.43

   

$

13.18

   

$

16.75

 

Percentage of WTI

   

16

%

   

31

%

   

20

%

   

26

%

Total Weighted Average Realized Price:

                       

Excluding derivatives ($/Mcfe)

 

$

1.72

   

$

2.51

   

$

2.21

   

$

2.51

 

Including derivatives ($/Mcfe)

 

$

2.16

   

$

2.48

   

$

2.41

   

$

2.51

 

(1) Based on last day monthly futures settlement prices.
(2) This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation charges and fuel charges, and excludes financial basis derivatives.



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