CDN NEWS | 
US NEWS 
Continued outperformance, advantaged balance sheet, foundation set for value growth
SPRING, Texas–(BUSINESS WIRE)–Southwestern Energy Company (NYSE: SWN) today announced financial and operating results for the fourth quarter and year-end December 31, 2018. Fiscal year 2018 highlights, compared to prior year include:
- Reported net cash provided by operating activities of $1.22 billion and net cash flow of $1.35 billion, generating $100 million in free cash flow above capital investment of $1.25 billion;
- Total Company production of 946 Bcfe, above midpoint of guidance, adjusted for Fayetteville sale;
- Grew Appalachia production 21 percent to 702 Bcfe and liquids production 40 percent to 63,100 barrels per day;
- 23 percent higher weighted average realized price in Appalachia of $2.82 per Mcfe, net of transportation;
- Generated a $1.66 per Mcfe margin in Appalachia, an increase of 43 percent;
- Total Company proved reserves of 11.9 Tcfe, including 33 percent liquids, and pre-tax PV-10 value of $6.5 billion;
- Restructured G&A and reduced interest costs resulting in estimated future annual savings of $155 million;
- Closed Fayetteville sale on December 3rd receiving net proceeds of $1.65 billion;
- Reduced senior notes and bank debt by $2.1 billion;
- Repurchased 44 million shares of common stock for $199 million at an average price of $4.53 per share, as of February 28, 2019.
“The Company’s continued outperformance, the resulting advantaged balance sheet and impressive operational execution have set a solid foundation for further value growth,” said Bill Way, President and Chief Executive Officer, Southwestern Energy. “We carry strong momentum into 2019, refocused, reengineered and reenergized as a leading Appalachia basin operator, with a flexible, high value natural gas and natural gas liquids portfolio, supported by a net debt/EBITDA ratio of less than 2X.”
| FINANCIAL STATISTICS | For the three months ended | For the year ended | |||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Financial Results (in millions, except per share amounts) | |||||||||||||||
| Net income attributable to common stock | $ | 307 | $ | 267 | $ | 535 | $ | 815 | |||||||
| Adjusted net income attributable to common stock (non-GAAP) | $ | 176 | $ | 63 | $ | 590 | $ | 219 | |||||||
| Adjusted EBITDA (non-GAAP) | $ | 394 | $ | 345 | $ | 1,484 | $ | 1,247 | |||||||
| Net cash provided by operating activities | $ | 252 | $ | 308 | $ | 1,223 | $ | 1,097 | |||||||
| Net cash flow (non-GAAP) | $ | 359 | $ | 322 | $ | 1,352 | $ | 1,138 | |||||||
| Total Capital Investments | $ | 209 | $ | 347 | $ | 1,248 | $ | 1,293 | |||||||
| OPERATING STATISTICS | For the three months ended | For the year ended | |||||||||||||
| December 31, | December 31, | ||||||||||||||
| 2018 | 2017 | 2018 | 2017 | ||||||||||||
| Production | |||||||||||||||
| Gas production (Bcf) | 194 | 210 | 807 | 797 | |||||||||||
| Oil production (MBbls) | 1,073 | 580 | 3,407 | 2,327 | |||||||||||
| NGL production (MBbls) | 5,434 | 4,111 | 19,706 | 14,245 | |||||||||||
| Total production (Bcfe) | 234 | 239 | 946 | 897 | |||||||||||
| Division Production | |||||||||||||||
| Northeast Appalachia (Bcf) | 118 | 110 | 459 | 395 | |||||||||||
| Southwest Appalachia (Bcfe) | 71 | 52 | 243 | 183 | |||||||||||
| Fayetteville Shale (Bcf) (1) | 44 | 75 | 243 | 316 | |||||||||||
| Average unit costs per Mcfe | |||||||||||||||
| Lease operating expenses | $ | 0.93 | $ | 0.91 | $ | 0.93 | $ | 0.90 | |||||||
| General & administrative expenses | $ | 0.18 |
(2) |
$ | 0.23 | $ | 0.19 |
(3) |
$ | 0.22 |
(4) |
||||
| Taxes, other than income taxes | $ | 0.10 | $ | 0.07 | $ | 0.09 |
(5) |
$ | 0.10 | ||||||
| Full cost pool amortization | $ | 0.53 | $ | 0.48 | $ | 0.51 | $ | 0.45 | |||||||
| (1) | The Fayetteville Shale assets and associated reserves were sold on December 3, 2018. | |
| (2) | Excludes $18 million restructuring charges (including severance) and $1 million of legal settlement charges. | |
| (3) | Excludes $36 million restructuring charges (including severance) and $9 million legal settlement charges. | |
| (4) | Excludes $5 million of legal settlement charges. | |
| (5) | Excludes $1 million of restructuring charges. | |
| COMMODITY PRICES | For the three months ended | For the year ended | ||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2018 | 2017 | 2018 | 2017 | |||||||||||||
| Natural Gas Price: | ||||||||||||||||
| NYMEX Henry Hub Price ($/MMBtu) (1) | $ | 3.64 | $ | 2.93 | $ | 3.09 | $ | 3.11 | ||||||||
| Discount (Differential) to NYMEX (2) | (0.66 | ) | (0.93 | ) | (0.64 | ) | (0.88 | ) | ||||||||
| Average realized gas price per Mcf, excluding derivatives | $ | 2.98 | $ | 2.00 | $ | 2.45 | $ | 2.23 | ||||||||
| Gain (loss) on settled financial basis derivatives ($/Mcf) | (0.02 | ) | 0.07 | (0.04 | ) | (0.01 | ) | |||||||||
| Gain (loss) on settled commodity derivatives ($/Mcf) | (0.48 | ) | 0.05 | (0.06 | ) | (0.03 | ) | |||||||||
| Average realized gas price per Mcf, including derivatives | $ | 2.48 | $ | 2.12 | $ | 2.35 | $ | 2.19 | ||||||||
| Oil Price: | ||||||||||||||||
| WTI oil price ($/Bbl) | $ | 58.81 | $ | 55.40 | $ | 64.77 | $ | 50.96 | ||||||||
| Discount (Differential) to WTI | (7.94 | ) | (7.35 | ) | (7.98 | ) | (7.84 | ) | ||||||||
| Average oil price per Bbl, excluding derivatives | $ | 50.87 | $ | 48.05 | $ | 56.79 | $ | 43.12 | ||||||||
| Average oil price per Bbl, including derivatives | $ | 50.37 | $ | 48.05 | $ | 56.07 | $ | 43.12 | ||||||||
| NGL Price: | ||||||||||||||||
| Average net realized NGL price per Bbl, excluding derivatives | $ | 18.59 | $ | 17.97 | $ | 17.91 | $ | 14.46 | ||||||||
| Average net realized NGL price per Bbl, including derivatives | $ | 18.49 | $ | 17.99 | $ | 17.23 | $ | 14.48 | ||||||||
| Percentage of WTI oil price | 32 | % | 32 | % | 28 | % | 28 | % | ||||||||
| Average net realized C3+ price per Bbl, excluding derivatives | $ | 32.26 | $ | 39.38 | $ | 34.46 | $ | 30.08 | ||||||||
| Average net realized C3+ price per Bbl, including derivatives | $ | 32.75 | $ | 39.38 | $ | 33.77 | $ | 30.08 | ||||||||
| Percentage of WTI oil price | 55 | % | 71 | % | 53 | % | 59 | % | ||||||||
| Total Weighted Average Realized Price: | ||||||||||||||||
| Appalachian Basin, excluding derivatives ($/Mcfe) | $ | 3.31 | $ | 2.17 | $ | 2.82 | $ | 2.30 | ||||||||
| Total Company | ||||||||||||||||
| Excluding derivatives ($/Mcfe) | $ | 3.15 | $ | 2.19 | $ | 2.66 | $ | 2.32 | ||||||||
| Including derivatives ($/Mcfe) | $ | 2.72 | $ | 2.30 | $ | 2.57 | $ | 2.29 | ||||||||
| (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. | |
Financial Results
Southwestern Energy recorded net income attributable to common stock of $307 million or $0.54 per diluted share and $535 million or $0.93 per diluted share for the fourth quarter and year ended December 31, 2018, respectively. For full year 2018, net income reflects stronger operating performance driven by 78 percent higher liquids revenue of $548 million, which was partially offset by impairments associated with the Fayetteville sale, restructuring charges and unsettled derivative losses of $24 million in 2018 compared to an unsettled derivative gain of $451 million in 2017. Excluding the impact of unsettled derivatives, net income attributable to common stock was 54 percent higher for 2018 compared to the prior year. For the fourth quarter of 2018, net income was higher than 2017, due to higher natural gas and liquids revenue, offset by a settled derivative loss of $99 million in the fourth quarter and the impact of restructuring charges.
For the full year 2018, adjusted net income was $590 million, more than $370 million above the prior year. For the fourth quarter of 2018, adjusted net income attributable to common stock was $176 million, a 179 percent increase compared to the same quarter last year. Adjusted net income incorporates the impact of an assumed corporate tax rate of 24.5 percent, and excludes unsettled derivatives, as well as other one-time charges.
For the fiscal year 2018, adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”) was $1,484 million, 19 percent above 2017 due to improved realized prices, increased production and reduced general and administrative expenses, partially offset by higher operating expenses related to a shift to more liquids-rich production in Southwest Appalachia. The primary components of adjusted EBITDA included $1,168 million from Appalachia operations and $377 million from Fayetteville operations, including Fayetteville Midstream. Adjusted EBITDA was $49 million higher in the fourth quarter of 2018 compared to a year ago, and includes two months of Fayetteville ownership.
For the full year 2018, weighted average realized price excluding derivatives was $2.66 per Mcfe, 15 percent or 34 cents higher than the prior year. Including derivatives, weighted average realized pricing was $2.57 per Mcfe, 12 percent above the prior year. For fiscal year 2018, Appalachia weighted average realized pricing was $2.82 per Mcfe, a $0.52 per Mcfe improvement compared to the prior year due to natural gas basis improvement, higher liquids production and improved liquids pricing.
For the fourth quarter of 2018, weighted average realized pricing, excluding derivatives was $3.15 per Mcfe, which was 44 percent higher than the prior period, driven primarily by the impact of higher NGL and oil production and price realizations. Including the impact of derivative settlement losses of $99 million, weighted average realized pricing was $2.72 per Mcfe, 18 percent higher than the prior year. Appalachia weighted average realized pricing was $3.31 per Mcfe in the fourth quarter, 53 percent above the prior year.
Total debt reduction for 2018 was $2.1 billion, including credit facility refinancing and the repurchase of senior notes. During the fourth quarter of 2018, the Company closed on the sale of its Fayetteville Shale assets and used the net proceeds received of $1.65 billion to repurchase $900 million of senior notes, repurchase shares of common stock and repay all outstanding borrowings under its revolving credit facility, pending additional investments. Cash on hand at year-end was $201 million.
Pursuant to the Company’s $200 million authorized share repurchase program, during the fourth quarter of 2018, the Company invested $156 million to repurchase 34 million shares of common stock at an average price of $4.55 per share. In total, as of February 28, 2019, the Company has repurchased 44 million shares for a cumulative total of $199 million at an average price of $4.53 per share.
Southwestern Energy continues to execute a disciplined hedging program with physical, financial and basis derivatives on its forecasted natural gas, natural gas liquids and oil production. A summary of the Company’s financial derivative position is provided in the attached financial tables. Additional information on physical and financial derivatives can be found in the Company’s 2018 Form 10-K.
Operational Review
In 2018, the Company invested $1.23 billion in E&P operations which includes $1.11 billion in Appalachia and $60 million on the Southwest Appalachia water project. Southwestern Energy drilled 106 wells, completed 119 wells and placed 138 wells to sales.
During the fourth quarter of 2018, Southwestern invested a total of approximately $175 million in its Appalachia operations and $21 million on the water project. The Company drilled 15 wells, completed 11 wells and placed 25 wells to sales.
Southwest Appalachia – In 2018, Southwest Appalachia’s total net production increased 33 percent to 243 Bcfe and included 63,100 barrels per day of liquids. Liquids comprised 57 percent of production volumes. The Company brought 76 wells online, with approximately 80 percent of the wells located in the super rich acreage. The Company drilled and completed 71 Marcellus wells.
In the fourth quarter, the Company drilled nine wells, completed five and placed 17 to sales. These included two Upper Devonian wells with initial liquids production of 49 percent. Delineation of the Upper Devonian will continue in 2019.
On a full year basis, weighted average realized price on a natural gas equivalent basis was $3.34 per Mcfe, a $0.25 per Mcfe uplift compared to the NYMEX gas price of $3.09 per MMBtu. For the fourth quarter, weighted average realized price was $3.62 per Mcfe. The uplift is directly related to higher liquids production and premium pricing received from the sale of natural gas liquids and oil.
Northeast Appalachia – Northeast Appalachia’s 2018 total net production increased to 459 Bcf, up 16 percent. The increase in production was mainly due to Tioga well outperformance, gathering capacity expansion and cycle time improvements. The Company drilled 41 wells, completed 54 wells and placed 60 wells to sales.
Well activity in the fourth quarter of 2018 included six drilled wells, six completions and eight wells to sales. One of the eight wells brought online was a Company record, ultra-long lateral of 16,272 feet that met all timing, cost and initial production forecasts. The Company continues to increase its lateral lengths and plans to drill and complete more ultra-long laterals in 2019.
| Three Months Ended December 31, 2018 E&P Division Results | Appalachia | Fayetteville | ||||||||||||
| Northeast | Southwest | Shale (1) | ||||||||||||
| Gas Production (Bcf) | 118 | 32 | 44 | |||||||||||
| Liquids Production | ||||||||||||||
| NGL (MBbls) | – | 5,431 | – | |||||||||||
| Oil (MBbls) | – | 1,065 | – | |||||||||||
| Production (Bcfe) | 118 | 71 | 44 | |||||||||||
| Gross operated production (MMcfe/d) | 1,536 | 1,213 | – | |||||||||||
| Net operated production (MMcfe/d) | 1,256 | 752 | – | |||||||||||
| Capital investments ($ in millions) | ||||||||||||||
| Exploratory and development drilling, including workovers | $ | 51 | $ | 75 | $ | – | ||||||||
| Acquisition and leasehold | 4 | 1 | – | |||||||||||
| Seismic and other | – | – | 1 | |||||||||||
| Capitalized interest and expense | 7 | 37 | 2 | |||||||||||
| Total capital investments | $ | 62 | $ | 113 | $ | 3 | ||||||||
| Gross operated well activity summary | ||||||||||||||
| Drilled | 6 | 9 | – | |||||||||||
| Completed | 6 | 5 | – | |||||||||||
| Wells to sales | 8 | 17 | – | |||||||||||
| Average completed well cost (in millions) | $ | 9.7 |
(2) |
$ | 9.0 |
(2) |
$ | – | ||||||
| Average lateral length (in ft) | 9,119 | 6,992 |
(3) |
– | ||||||||||
| Realized Natural Gas Price | ||||||||||||||
| NYMEX Henry Hub Price ($/MMBtu) | $ | 3.64 | $ | 3.64 | $ | 3.64 | ||||||||
| Discount to NYMEX (4) | (0.51 | ) | (0.48 | ) | (1.22 | ) | ||||||||
| Average realized gas price per Mcf, excluding derivatives | $ | 3.13 | $ | 3.16 | $ | 2.42 | ||||||||
| Total weighted average realized price per Mcfe, excluding derivatives | $ | 3.13 | $ | 3.62 | $ | 2.42 | ||||||||
| (1) | The Fayetteville Shale assets and associated reserves were sold on December 3, 2018. | |
| (2) | Average completed well cost includes Marcellus wells only and amounts for delineation and science. | |
| (3) | Average lateral length includes Marcellus wells only. | |
| (4) | 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. | |
| Year Ended December 31, 2018 E&P Division Results | Appalachia | Fayetteville | ||||||||||||
| Northeast | Southwest | Shale (1) | ||||||||||||
| Gas Production (Bcf) | 459 | 105 | 243 | |||||||||||
| Liquids Production | ||||||||||||||
| NGL (MBbls) | – | 19,679 | – | |||||||||||
| Oil (MBbls) | – | 3,355 | – | |||||||||||
| Production (Bcfe) | 459 | 243 | 243 | |||||||||||
| Gross operated production (MMcfe/d) | 1,536 | 1,213 | – | |||||||||||
| Net operated production (MMcfe/d) | 1,256 | 752 | – | |||||||||||
| Capital investments ($ in millions) | ||||||||||||||
| Exploratory and development drilling, including workovers | $ | 370 | $ | 502 | $ | 15 | ||||||||
| Acquisition and leasehold | 14 | 37 | – | |||||||||||
| Seismic and other | 3 | 4 | 5 | |||||||||||
| Capitalized interest and expense | 35 | 148 | 13 | |||||||||||
| Total capital investments | $ | 422 | $ | 691 | $ | 33 | ||||||||
| Gross operated well activity summary | ||||||||||||||
| Drilled | 41 | 63 | 2 | |||||||||||
| Completed | 54 | 63 | 2 | |||||||||||
| Wells to sales | 60 | 76 | 2 | |||||||||||
| Average completed well cost (in millions) | $ | 7.5 |
(2) |
$ | 9.2 |
(2) |
$ | – | ||||||
| Average lateral length (in ft) | 7,584 | 7,267 |
(3) |
– | ||||||||||
| Realized Natural Gas Price | ||||||||||||||
| NYMEX Henry Hub Price ($/MMBtu) | $ | 3.09 | $ | 3.09 | $ | 3.09 | ||||||||
| Discount to NYMEX (4) | (0.55 | ) | (0.51 | ) | (0.88 | ) | ||||||||
| Average realized gas price per Mcf, excluding derivatives | $ | 2.54 | $ | 2.58 | $ | 2.21 | ||||||||
| Total weighted average realized price per Mcfe, excluding derivatives | $ | 2.54 | $ | 3.34 | $ | 2.21 | ||||||||
| (1) | The Fayetteville Shale assets and associated reserves were sold on December 3, 2018. | |
| (2) | Average completed well cost includes Marcellus wells only and amounts for delineation and science. | |
| (3) | Average lateral length includes Marcellus wells only. | |
| (4) | 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. | |
2018 Proved Reserves
The Company’s estimated proved natural gas, natural gas liquids and oil reserves, audited by an independent petroleum engineering firm, were 11.9 Tcfe as of December 31, 2018. The reserve life index was approximately 17 years at year-end 2018, excluding production associated with Fayetteville. The following tables detail additional information relating to reserve estimates as of and for the year ended December 31, 2018:
| Proved Reserves Summary | For the years ended December 31, | |||||||
| 2018 | 2017 | |||||||
| Proved reserves (in Bcfe) | 11,921 | 14,775 | ||||||
| Prices used | ||||||||
| Natural gas (per Mcf) | $ | 3.10 | $ | 2.98 | ||||
| Oil (per Bbl) | $ | 65.56 | $ | 47.79 | ||||
| Natural Gas Liquids (per Bbl) | $ | 17.64 | $ | 14.41 | ||||
| PV-10: | ||||||||
| Pre-Tax (millions) | $ | 6,524 | $ | 5,784 | ||||
| PV of Taxes (millions) | (525 | ) | (222 | ) | ||||
| After-Tax (millions) | $ | 5,999 | $ | 5,562 | ||||
| Percent of estimated proved reserves that are: | ||||||||
| Natural gas | 67 | % | 75 | % | ||||
| Natural gas liquids and oil | 33 | % | 25 | % | ||||
| Proved developed | 47 | % | 54 | % | ||||
|
2018 Proved Reserves by Commodity |
Natural Gas | Oil | NGL | Total | ||||||||
| (Bcf) | (MBbls) | (MBbls) | (Bcfe) | |||||||||
| Proved reserves, beginning of year | 11,126 | 65,636 | 542,455 | 14,775 | ||||||||
| Revisions of previous estimates due to price | 96 | 788 | 8,912 | 154 | ||||||||
| Revisions of previous estimates other than price | 316 | 410 | 8,855 | 372 | ||||||||
| Extensions, discoveries and other additions | 753 | 5,830 | 36,823 | 1,009 | ||||||||
| Production | (807 | ) | (3,407 | ) | (19,706 | ) | (946 | ) | ||||
| Acquisition of reserves in place | – | – | – | – | ||||||||
| Disposition of reserves in place (1) | (3,440 | ) | (250 | ) | (276 | ) | (3,443 | ) | ||||
| Proved reserves, end of year | 8,044 | 69,007 | 577,063 | 11,921 | ||||||||
| Proved developed reserves: | ||||||||||||
| Beginning of year | 6,979 | 14,513 | 142,213 | 7,920 | ||||||||
| End of year | 4,395 | 18,037 | 175,480 | 5,557 | ||||||||
|
Note: Amounts may not add due to rounding |
||||||||||||
|
(1) The 2018 disposition is primarily associated with the Fayetteville Shale sale. |
||||||||||||
| 2018 Proved Reserves by Division | Appalachia | Fayetteville | |||||||||||||
| Northeast | Southwest |
Shale (1) |
Other (2) | Total | |||||||||||
| Estimated Proved Reserves (Bcfe): | |||||||||||||||
| Reserves, beginning of year | 4,126 | 6,962 | 3,679 | 8 | 14,775 | ||||||||||
| Revisions of previous estimates due to price | 41 | 106 | 6 | 1 | 154 | ||||||||||
| Revisions of previous estimates other than price | 107 | 272 | (6 | ) | (1 | ) | 372 | ||||||||
| Extensions, discoveries and other additions | 551 | 457 | 1 | – | 1,009 | ||||||||||
| Production | (459 | ) | (243 | ) | (243 | ) | (1 | ) | (946 | ) | |||||
| Acquisition of reserves in place | – | – | – | – | – | ||||||||||
| Disposition of reserves in place | – | – | (3,437 | ) | (6 | ) | (3,443 | ) | |||||||
| Reserves, end of year | 4,366 | 7,554 | – | 1 | 11,921 | ||||||||||
|
(1) The Fayetteville Shale E&P assets and associated reserves were divested December 3, 2018. |
|||||||||||||||
|
(2) Other includes properties outside of the Appalachian Basin and Fayetteville Shale. |
|||||||||||||||
| 2018 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA (1) | |||||||||||||||||
| Appalachia | |||||||||||||||||
| Northeast | Southwest | Other (2) | Total | ||||||||||||||
| Estimated proved reserves: | |||||||||||||||||
| Natural gas (Bcf): | |||||||||||||||||
| Developed | 3,327 | 1,068 | – | 4,395 | |||||||||||||
| Undeveloped | 1,039 | 2,610 | – | 3,649 | |||||||||||||
| 4,366 | 3,678 | – | 8,044 | ||||||||||||||
| Crude oil (MMBbls): | |||||||||||||||||
| Developed | – | 17.9 | 0.1 | 18.0 | |||||||||||||
| Undeveloped | – | 51.0 | – | 51.0 | |||||||||||||
| – | 68.9 | 0.1 | 69.0 | ||||||||||||||
| Natural gas liquids (MMBbls): | |||||||||||||||||
| Developed | – | 175.5 | – | 175.5 | |||||||||||||
| Undeveloped | – | 401.6 | – | 401.6 | |||||||||||||
| – | 577.1 | – | 577.1 | ||||||||||||||
| Total proved reserves (Bcfe) (3): | |||||||||||||||||
| Developed | 3,327 | 2,229 | 1 | 5,557 | |||||||||||||
| Undeveloped | 1,039 | 5,325 | – | 6,364 | |||||||||||||
| 4,366 | 7,554 | 1 | 11,921 | ||||||||||||||
| Percent of total | 37 | % | 63 | % | 0 | % | 100 | % | |||||||||
| Percent proved developed | 76 | % | 30 | % | 100 | % | 47 | % | |||||||||
| Percent proved undeveloped | 24 | % | 70 | % | 0 | % | 53 | % | |||||||||
| Production (Bcfe) | 459 | 243 | 244 |
(4) |
946 | ||||||||||||
| Capital investments (in millions) | $ | 422 | $ | 691 | $ | 118 |
(5) |
$ | 1,231 | ||||||||
| Total gross producing wells (6) | 666 | 466 | 17 | 1,149 | |||||||||||||
| Total net producing wells (6) | 592 | 333 | 14 | 939 | |||||||||||||
| Total net acreage | 184,024 | 297,445 | 166,120 |
(7) |
647,589 | ||||||||||||
| Net undeveloped acreage | 73,174 | 220,331 | 153,159 |
(7) |
446,664 | ||||||||||||
| PV-10: | |||||||||||||||||
| Pre-tax (in millions) (8) | $ | 3,054 | $ | 3,470 | $ | – | $ | 6,524 | |||||||||
| PV of taxes (in millions) (8) | (245 | ) | (280 | ) | – | (525 | ) | ||||||||||
| After-tax (in millions) (8) | $ | 2,809 | $ | 3,190 | $ | – | $ | 5,999 | |||||||||
| Percent of total | 47 | % | 53 | % | 0 | % | 100 | % | |||||||||
| Percent operated (9) | 99 | % | 100 | % | 100 | % | 99 | % | |||||||||
| (1) | The Fayetteville Shale E&P assets and associated reserves were divested on December 3, 2018. | |
| (2) | Other reserves and acreage consists primarily of properties in Colorado. Production and capital investing includes Fayetteville Shale. | |
| (3) | We have no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. We used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors. | |
| (4) | Includes 243 Bcf of natural gas production related to our Fayetteville Shale operations which were sold on December 3, 2018. | |
| (5) | Other capital investments includes $33 million related to our Fayetteville Shale operations which were sold on December 3, 2018, $60 million related to our water infrastructure project, $16 million related to our E&P service companies and $9 million related to our exploration activities. | |
| (6) | Represents producing wells, including 394 wells in which we only have an overriding royalty interest in Northeast Appalachia, used in the December 31, 2018 reserves calculation. | |
| (7) | Excludes exploration licenses for 2,518,519 net acres in New Brunswick, Canada, which have been subject to a moratorium since 2015. | |
| (8) | Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a company’s proved reserves that we believe is used by securities analysts to compare relative values among peer companies without regard to income taxes. The reconciling difference in pre-tax PV-10 and the after-tax PV-10, or standardized measure, is the discounted value of future income taxes on the estimated cash flows from our proved natural gas, oil and NGL reserves. | |
| (9) | Based upon pre-tax PV-10 of proved developed producing activities. | |
The Company’s 2018 and three-year average proved developed finding and development (PD F&D) costs were $0.70 and $0.72 per Mcfe, respectively, when excluding the impact of capitalizing interest and portions of capitalized G&A costs in accordance with the full cost method of accounting.
| Total Company PD F&D | Three-Year | ||||||||||||||||
| 12 Months Ended December 31, | Total | ||||||||||||||||
| 2018 | 2017 | 2016 | 2018 | ||||||||||||||
| Total PD Adds (Bcfe): | |||||||||||||||||
| New PD adds | 177 | 1,258 | 257 | 1,692 | |||||||||||||
| PUD conversions | 1,139 |
(2) |
46 | 220 | 1,405 | ||||||||||||
| Total PD Adds | 1,316 | 1,304 | 477 | 3,097 | |||||||||||||
| Costs Incurred (in millions): | |||||||||||||||||
| Unproved property acquisition costs | $ | 164 | $ | 194 | $ | 171 | $ | 529 | |||||||||
| Exploration costs | 5 | 22 | 17 | 44 | |||||||||||||
| Development costs | 1,014 | 1,024 | 433 | 2,471 | |||||||||||||
| Capitalized Costs Incurred | $ | 1,183 | $ | 1,240 | $ | 621 | $ | 3,044 | |||||||||
| Subtract (in millions): | |||||||||||||||||
| Proved property acquisition costs | $ | – | $ | – | $ | – | $ | – | |||||||||
| Unproved property acquisition costs | (164 | ) | (194 | ) | (171 | ) | (529 | ) | |||||||||
| Capitalized interest and expense associated with development and exploration (1) | (93 | ) | (103 | ) | (91 | ) | (287 | ) | |||||||||
| PD Costs Incurred | $ | 926 | $ | 943 | $ | 359 | $ | 2,228 | |||||||||
| PD F&D | $ | 0.70 | $ | 0.72 | $ | 0.75 | $ | 0.72 | |||||||||
Note: Amounts may not add due to rounding
(1) Adjusting for the impacts of the full cost accounting method for comparability.
(2) Includes increased reserve estimates of 43 Bcfe in the Appalachian Basin, associated with productivity enhancements for newly developed PUD locations.
Conference Call
Southwestern Energy will host a conference call and webcast on Friday, March 1, 2019 at 9:30 a.m. Central to discuss fourth quarter and year-end 2018 results. To participate, dial US toll-free 877-883-0383, or international 412-902-6505 and enter access code 9372440. The conference call will webcast live at www.swn.com.
To listen to a replay of the call, dial 877-344-7529, International 412-317-0088, or Canada Toll Free 855-669-9658. Enter replay access code 10128185. The replay will be available until March 20, 2019.
About Southwestern Energy
Southwestern Energy Company is an independent energy company engaged in natural gas, natural gas liquids and oil exploration, development, production and marketing. For additional information, visit our website www.swn.com.
Forward Looking Statement
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.
Contacts
Investor Contact
Paige Penchas
Vice President, Investor Relations
(832) 796-4068
[email protected]
Media Contact
Jim Schwartz
Director, Corporate Communications
(832) 796-2716
[email protected]
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