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Southwestern Energy Announces 2017 Highlights And 2018 Guidance

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HOUSTON, Feb. 8, 2018 /PRNewswire/ -- Southwestern Energy Company (NYSE: SWN) today announced its 2017 highlights and its 2018 guidance based on a $2.85 NYMEX gas price.  The Company took on commodity price challenges and delivered on commitments made in its 2017 guidance.

2017 highlights include:

  • Delivered on commitment to invest within net cash flow (supplemented by the remaining $200 million from the 2016 equity offering as previously disclosed);
  • Total net production of 897 Bcfe, including 578 Bcfe from the Appalachian Basin and 316 Bcf from the Fayetteville Shale;
    • Comprised of 89% natural gas and 11% NGLs and condensate;
  • Record Appalachian Basin gross operated exit rate production of 2.35 Bcfe per day, a 40% increase compared to December 2016;
  • Increase in estimated pre-tax PV10 reserve value to approximately $5.8 billion, up 247% compared to year-end 2016, including $3.8 billion from the Appalachian Basin;
  • Preliminary total proved reserves(1) of approximately 14.8 Tcfe, including 11.1 Tcfe from the Appalachian Basin, up 181% and 393%, respectively, compared to 2016;
    • Comprised of 75% natural gas and 25% NGLs and condensate at year-end 2017, compared to 93% and 7% in 2016, respectively;
    • 46% proved undeveloped at year-end 2017; and
  • Further optimized completion techniques leading to enhanced well productivity and economics in the Appalachian Basin.

Detailed information on these and other 2017 results will appear in the Company's earnings release and annual report on Form 10-K to be issued on March 1, 2018.

2018 guidance highlights include:

  • Capital investments of $1.15 to $1.25 billion, funded entirely by net cash flow;
  • Average net production of 930 to 965 Bcfe, a 6% increase (using midpoints) over the 2017 production of 897 Bcfe;
    • Appalachian Basin net production of 671 to 698 Bcfe, an 18% increase over 2017, including a 30% increase in Southwest Appalachia;
    • NGLs and condensate production increase to approximately 130 Bcfe, an increase of 31% compared to 2017;
  • Improved capital efficiency demonstrated by investing almost $100 million less in drilling and completion activities while delivering both higher value and production growth versus the 2017 program;
  • Northeast Appalachia expected to generate positive cash flow from operations, net of capital for the first time, delivering approximately $150 million;
  • Total Company and Northeast Appalachia gas differentials expected to improve by approximately $0.10 per Mcf and $0.25 per Mcf, respectively; and
  • Hedge protection on approximately 69% of projected 2018 natural gas volumes at an average swap or purchased put strike price of $2.97 per Mcf.

(1)   Audited by independent petroleum engineering firm  

In a separate press release issued today, the Company announced its intent to actively pursue strategic alternatives for the Fayetteville Shale E&P and related midstream gathering assets along with other initiatives.  The 2018 guidance excludes any impact from the strategic actions announced today in that press release.

"Our commitment to value creation is clearly evident with our 2018 plan," said Bill Way, President and Chief Executive Officer of Southwestern Energy.  "We are delivering more with less, benefiting from the capital efficiency gains that we have captured over the past two years. We will continue to invest within net cash flow and maintain capital discipline by prioritizing investments to those projects that are expected to generate the highest returns for our shareholders." 

2018 Guidance Summary
Across the portfolio, the Company continues to identify opportunities to expand margins and increase capital efficiency, enhancing the value of its inventory.  During 2018, the Company plans to invest $1,130 million to $1,215 million in its E&P business, which includes $775 million to $815 million for drilling and completion activities, $210 million to $230 million for capitalized interest and expenses, $65 million to $75 million in water infrastructure and $80 million to $95 million for land, seismic and other items. 

The 2018 capital budget will once again prioritize investments generating the highest returns for shareholders and will focus on the Appalachian Basin, where the Company plans to begin the year operating four rigs and utilizing three completion crews in Southwest Appalachia and two rigs and two completion crews in Northeast Appalachia.  The 2018 program includes drilling 100 to 120 wells, completing 105 to 125 wells and placing 125 to 145 wells to sales. 

Southwest Appalachia – In Southwest Appalachia, based on current liquids realizations and improving economics, the Company plans to target the liquids rich portion of the play, which is expected to increase total production by 30% (using midpoints), with liquids representing 54% of total production in 2018.  The increase in liquids realizations is expected to generate a price uplift of approximately $0.80 per Mcfe.  This increase, coupled with reduced processing rates, is expected to further improve cash margins.  The Company plans to allocate approximately $490 million to $510 million in discretionary capital to Southwest Appalachia, with approximately $430 million to $450 million allocated to drilling and completions activities.  Approximately $60 million is planned to be used for land and seismic activity. The Company expects the average 2018 completed well cost for the wells placed to sales to be $7.6 million per well with approximately 7,200 foot average horizontal lateral length.  As the Company targets longer lateral lengths, the Company's drilled lateral lengths are expected to increase throughout the year, averaging approximately 8,500 feet for the second half of 2018.  Additionally, the Company commenced a water infrastructure project in late 2017 and plans to invest approximately $65 million to $75 million in capital in 2018.  While this project does not directly provide production growth, it is expected to reduce well costs by approximately $500 thousand per well beginning in late 2018 and lower the breakeven gas price threshold by $0.25 per Mcf.  This water project will be utilized for future development of the rich and lean gas Marcellus wells, along with dry gas Utica development.

Northeast Appalachia – The 2018 program plans to focus primarily on its core area in Susquehanna County while further developing its Tioga County acreage.  The Company plans to allocate approximately $340 million to $360 million in discretionary capital to Northeast Appalachia, with approximately $320 million to $340 million allocated to drilling and completions and the remaining $20 million allocated to land and other capital.  The Company expects the average 2018 completed well cost for the wells placed to sales to be $6.6 million per well with approximately 7,100 foot average horizontal lateral length. 

As additional pipeline capacity is added in the region, Southwestern's transportation portfolio is positioned to capture materially improving basis differentials without significant increases in transportation charges, resulting in a $0.25 per Mcf improvement in Northeast Appalachia margins.  As a result, the Company expects to generate approximately $150 million in positive cash flow from operations, net of capital, in 2018 while growing production 13% (using midpoints), capitalizing on the operational momentum created during 2017.    

FayettevilleThe Company continues to identify additional opportunities to realize incremental value from these assets.  Along with advancing its learnings and monitoring the longer term results from the Moorefield wells drilled in 2017, the Company plans in 2018 to further test additional redevelopment concepts in which the latest generation drilling and completion techniques are utilized in legacy development areas of the Fayetteville. The Company has announced an initiative to actively pursue strategic alternatives for the Fayetteville Shale E&P and related midstream gathering assets.

2018 Budget Overview
The following tables provide detailed information and guidance for 2018 based on an average natural gas price of $2.85 per Mcf and an average oil price of $60.00 per barrel. 




2018 Guidance

in millions (except per share amounts, production and well count)

$2.85 / $60.00

Capital investments:


     Discretionary capital

   $935 - $1,015

     Capitalized interest and expenses

$215 - $235

   Total capital investments

 $1,150 - $1,250



Net cash flow (1)

$1,150 - $1,250



Net income (2)

$350 - $450

Share Count(3)

585 - 595

Diluted earnings per share

$0.59 - $0.76



Adjusted EBITDA (1)

$1,250 - $1,350



Production (Bcfe)

930 – 965

Wells drilled

100 – 120

Wells completed

105 – 125

Wells placed to sales

125 – 145

Ending DUC inventory

35 – 45


(1)   This represents a Non-GAAP measure; see "Explanation and Reconciliation of Non-GAAP Financial Measures" below.

(2)   Assumes 24.5% income tax rate and no unsettled derivative gain/losses.

(3)   Mandatory preferred shares converted on January 12, 2018 to approximately 75 million shares.

 

Estimated Production and Capital Investments in 2018







2018 Guidance


Production


Capital


(Bcfe)


($ in millions)

Northeast Appalachia

440 – 454


$

340 – 360

Southwest Appalachia

231 – 244



490 – 510

Fayetteville Shale

258 – 265



15 – 25

Southwest Appalachia water project




65 – 75

Other E&P

1 – 2



10 – 15

Midstream Services




  5 – 10

Corporate




10 – 20

Capitalized interest




115 – 125

Capitalized expense




100 – 110

Total

930 - 965


$

1,150 - 1,250

 

Estimated Production by Quarter in 2018












1st Quarter


2nd Quarter


3rd Quarter


4th Quarter


Total Year

Guidance:










   Natural Gas (Bcf)

196 – 200


197 – 202


204 – 211


207 – 218


804 – 831

   Oil (MBbls)

560 – 635


665 – 730


900 – 965


900 – 970


3,025 – 3,300

   NGLs (MBbls)

3,950 – 4,200


4,050 – 4,400


4,750 – 5,000


5,250 – 5,400


18,000 – 19,000

 Total Production (Bcfe)

223 – 229


225 – 233


238 – 247


244 – 256


930 – 965

 Total Production (MMcfe/d)

2,478 – 2,544


2,473 – 2,560


2,587 – 2,685


2,652 – 2,783


2,548 – 2,644

 



Estimated E&P Pricing Deductions in 2018


Avg gas discount to NYMEX including transportation(1)

$0.70 - $0.85 per Mcf

Avg oil discount to WTI including transportation

$8.00 - $10.00 per Bbl

Avg NGL realization including transportation

23% - 28% of WTI



Estimated E&P Operating Expenses in 2018 (per Mcfe)


Lease operating expenses

$0.89 - $0.94

General & administrative expense

$0.19 - $0.23

Taxes, other than income taxes

$0.09 - $0.11

Full cost pool amortization

$0.55 - $0.60



Other Items in 2018


Midstream EBITDA ($ in millions)(2)

$170 - $200

Midstream depreciation ($ in millions)

$60 - $70

Interest expense - net of capitalization ($ in millions)

$150 - $160

Income tax rate (~100% Deferred)(3)

24.5%


(1)   Excludes impact of financial basis hedges

(2)   Non-GAAP measure – see explanation and reconciliation of Non-GAAP financial measures below

(3)   Assumes no impact from valuation allowance

 

Estimated Gross Well Counts in 2018














Beginning DUC
Inventory


Drilled


Completed


To Sales


Ending DUC
Inventory

NE Appalachia


30


36 – 44


50 – 58


56 – 64


  8 – 13

SW Appalachia


36


63 – 71


54 – 62


68 – 76


27 – 32

Fayetteville


-


1 – 5


1 – 5


1 – 5


Total Well Count


66


100 – 120


105 – 125


125 – 145


35 – 45

First Quarter 2018 Update
The Company's first quarter net production rates are estimated to average 2.48 Bcfe per day to 2.54 Bcfe per day.  The decline in production compared to the fourth quarter of 2017 is largely due to a reduction in activity in late 2017, the timing of completions and the impacts from severe winter weather on our operations in the month of January 2018.  The winter weather increased realized prices in the northeast to more than offset the impact on production, thus generating growth in cash flow.  In January, the Company realized an approximately $0.55 premium to NYMEX price in Northeast Appalachia, an improvement of almost $0.70 per Mcf compared to January 2017.

Additionally, on January 12, 2018, the Company's mandatory convertible preferred stock converted into approximately 75 million shares of the Company's common stock.  For the first quarter, the Company's weighted average share count is expected to be 570 million to 575 million shares.  This conversion eliminates approximately $108 million per year in dividends and also removes the allocation of net income to preferred shareholders, increasing the amount that is available to common shareholders.

Hedging Update

As of February 2, 2018, the Company had approximately 566 Bcf of its 2018 forecasted gas production protected at an average swap or purchased put strike price of $2.97 per Mcf.  Including the protected volumes, the Company retained upside exposure on approximately two thirds of its forecasted 2018 volumes.  Additionally, the Company had approximately 215 Bcf of its 2019 forecasted gas production protected at an average swap or purchased put strike price of $2.96 per Mcf, with upside exposure on approximately 57%, or 121 Bcf, of those protected volumes to $3.31 per Mcf.

A detailed breakdown of the Company's natural gas derivative financial instruments as of February 2, 2018 is shown below.  Southwestern's annual report on Form 10-K will have further information on the Company's commodity, basis and interest rate protection.


















Weighted Average Price per MMBtu


Volume
(Bcf)


Swaps


Sold Puts


Purchased
Puts


Sold Calls

Financial protection on production














  2018(1)














Fixed price swaps

265


$

2.98


$


$


$

Two-way costless collars

29







2.96



3.50

Three-way costless collars

273





2.40



2.97



3.38

Total

566













  2019 














Fixed price swaps

93


$

3.00


$


$


$

Two-way costless collars

9







2.90



3.27

Three-way costless collars

112





2.48



2.94



3.31

Total

215



























Sold call options














    2018 

63


$


$


$


$

3.50

    2019 

52









3.50

    2020 

68









3.63

    2021 

57









3.52

Total

240














Note: Amounts may not sum due to rounding

(1) Includes positions settled since January 1, 2018

As of February 2, 2018, the Company had also taken steps to mitigate the volatility of basis differentials by protecting basis on approximately 329 Bcf of its 2018 forecasted natural gas production at a basis differential to NYMEX natural gas prices of approximately ($0.31) per Mcf, which includes the impact of both physical and financial basis hedges.  A detailed breakdown of the Company's financial basis positions as of February 2, 2018 is shown below:

Financial basis positions

(excludes physical positions)

Volume

(Bcf)


Basis Differential

($/MMBTU)






Q1 2018(1)





   Dominion South

16.6


$

(1.20)

TETCO M3

8.7



0.99

Transco Z6 Non-NY

0.5



2.04

  Total

25.8


$

(0.40)






2018(1)





Dominion South

50.0


$

(0.83)

TETCO M3

28.0



(0.00)

Transco Z6 Non-NY

0.5



2.04

  Total

78.4


$

(0.52)






2019





Dominion South

1.0


$

(0.63)

TETCO M3

1.1



1.38

Transco Z6 Non-NY

0.0



-

  Total

2.2


$

0.42


(1) Includes positions settled since January 1, 2018

Sensitivities
Below is a summary of the approximate impacts of potential commodity price movements on expected net cash flow based on production estimates and the Company's hedging activities.





Price Sensitivities (based on annual prices)

Net Cash Flow


(in millions)

NYMEX Natural Gas:


$2.75/$60.00

$1,115 - $1,215

$2.85/$60.00

$1,150 - $1,250

$3.00/$60.00

$1,225 - $1,325

$3.25/$60.00

$1,350 - $1,475

+ $5.00 per bbl oil change (with constant NGL realization %)

~$40

+ 2% NGL realization change (with constant oil price)

~$20

Explanation and Reconciliation of Non-GAAP Financial Measures

The Company reports its financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results and the results of its peers and of prior periods.

One such non-GAAP financial measure is net cash flow. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the Company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

Additional non-GAAP financial measures referenced in this news release are adjusted net income and adjusted EBITDA. Management presents these measures because (i) they are consistent with the manner in which the Company's performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the forecasted 2018 annual period. Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.






2018 Guidance



NYMEX Price Assumption



$2.85 Gas / $60.00 Oil



(in millions)

Cash flow from operating activities:



Net cash provided by operating activities


$1,150 - $1,250

Add back (deduct):



   Change in operating assets and liabilities


-

Net cash flow


$1,150 - $1,250










Consolidated Adjusted EBITDA


2018 Guidance



NYMEX Price Assumption



$2.85 Gas / $60.00 Oil



(in millions)

Net income attributable to common stock


$350 - $450




Add back:



   Provision for income taxes


114 – 146

   Interest expense


150 – 160

   Non-cash stock based compensation


20 – 30

   Depreciation, depletion and amortization


590 – 610

Adjusted EBITDA(1)


$1,250 - $1,350

(1) Calculated consistently with provisions of the Company's principal credit agreements.






Midstream Adjusted EBITDA


2018 Guidance



NYMEX Price Assumption



$2.85 Gas / $60.00 Oil



(in millions)

Net income attributable to common stock


$75 - $100




Add back:



   Provision for income taxes


24 – 32

   Interest expense


   Non-cash stock based compensation


2 – 5

   Depreciation, depletion and amortization


60 – 70

Adjusted EBITDA


$170 - $200

Southwestern Energy Company is an independent energy company whose wholly-owned subsidiaries are engaged in natural gas and oil exploration, development and production, natural gas gathering and marketing. Additional information on the company can be found on the Internet at http://www.swn.com.

This news release contains forward-looking statements. Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by terminology such as "anticipate," "intend," "plan," "project," "estimate," "continue," "potential," "should," "could," "may," "will," "objective," "guidance," "outlook," "effort," "expect," "believe," "predict," "budget," "projection," "goal," "forecast," "target" or similar words. Statements may be forward looking even in the absence of these particular words. Where, in any forward-looking statement, the Company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, changes in commodity prices; changes in expected levels of natural gas and oil reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; international monetary conditions; unexpected cost increases; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission. Unless legally required, Southwestern Energy Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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SOURCE Southwestern Energy Company

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