Cabot Oil & Gas Corporation Announces Third Quarter 2013 Financial and Operating Results, Provides 2014 Operating and Financial Guidance

PR Newswire

HOUSTON, Oct. 24, 2013 /PRNewswire/ -- Cabot Oil & Gas Corporation (COG) today reported its financial and operating results for the third quarter of 2013. Highlights for the quarter include:

  • Production of 107.1 billion cubic feet equivalent (Bcfe), an increase of 61 percent over last year's comparable quarter.
  • Cash flow from operations of $276.7 million and discretionary cash flow of $282.3 million.
  • Net income of $69.9 million, or $0.17 per share.
  • Net income excluding selected items of $74.6 million, or $0.18 per share.
  • Total per unit costs (including financing) of $2.97 per thousand cubic feet equivalent (Mcfe), a 15 percent decline over last year's comparable quarter.

Third Quarter 2013 Financial Results

Production in the third quarter of 2013 was 107.1 Bcfe, consisting of 101.7 billion cubic feet (Bcf) of natural gas and 898,000 barrels of liquids. These figures represent increases of 61 percent, 62 percent, and 43 percent, respectively, compared to the third quarter of 2012. "Despite recent concerns over pricing in the Marcellus and the potential impact on Cabot's production growth, the Company grew equivalent production 13 percent sequentially compared to the second quarter of this year," said Dan O. Dinges, Chairman, President, and Chief Executive Officer.

Cash flow from operations in the third quarter of 2013 was $276.7 million, compared to $164.0 million in the third quarter of 2012. Discretionary cash flow in the third quarter of 2013 was $282.3 million, compared to $175.7 million in the third quarter of 2012. Higher equivalent production and, to a lesser extent, higher realized oil prices drove the quarter's overall improvement, partially offset by lower realized natural gas prices and increased operating expenses associated with higher production.

Net income in the third quarter of 2013 was $69.9 million, or $0.17 per share, compared to $36.6 million, or $0.09 per share, in the third quarter of 2012. Excluding the effect of selected items (detailed in the table below), net income was $74.6 million, or $0.18 per share, in the third quarter of 2013, compared to $43.1 million, or $0.11 per share, in the third quarter of 2012.

Natural gas price realizations, including the effect of hedges, were $3.36 per thousand cubic feet (Mcf) in the third quarter of 2013, down 9 percent compared to the third quarter of 2012.  "Our third quarter natural gas price realizations came in on the high-end of our expectations based on the guidance range we provided in early September," stated Dinges. "It is our belief that a combination of seasonal demand increases during the winter months and new pipeline takeaway capacity additions in Northeast Pennsylvania will positively impact Marcellus basis differentials over the coming months." Oil price realizations, including the effect of hedges, were $103.76 per barrel (Bbl), up 2 percent compared to the third quarter of 2012.

Total per unit costs (including financing) decreased to $2.97 per Mcfe in the third quarter of 2013, down 15 percent from $3.50 per Mcfe in the third quarter of 2012. All operating expense categories decreased on a per unit basis relative to last year's comparable quarter except for transportation and gathering expense, which increased from $0.52 per Mcfe in the third quarter of 2012 to $0.57 per Mcfe in the third quarter of 2013, primarily as a result of increased Marcellus production volumes, slightly higher transportation rates and new transportation agreements in the Marcellus.

Year-to-Date 2013 Financial Results

Production during the nine-month period ended September 30, 2013 was 291.7 Bcfe, consisting of 277.5 Bcf of natural gas and 2.4 million barrels of liquids. These figures represent increases of 54 percent, 56 percent, and 34 percent, respectively, compared to the nine-month period ended September 30, 2012.

For the nine-month period ended September 30, 2013, cash flow from operations was $766.7 million, compared to $455.1 million for the nine-month period ended September 30, 2012. Discretionary cash flow was $813.7 million for the nine-month period ended September 30, 2013, compared to $456.3 million for the nine-month period ended September 30, 2012. Higher equivalent production and, to a lesser extent, higher realized natural gas and oil prices drove the period's overall improvement, partially offset by increased operating expenses associated with higher production.

For the nine-month period ended September 30, 2013, net income was $201.8 million, or $0.48 per share, compared to $90.9 million, or $0.22 per share, for the nine-month period ended September 30, 2012.  Excluding the effect of selected items (detailed in the table below), net income was $223.8 million, or $0.53 per share, compared to $81.8 million, or $0.20 per share, for the nine-month period ended September 30, 2012.

Operational Highlights

Marcellus Shale

Cabot's Marcellus Shale position in the core of the dry gas window in Susquehanna County continues to produce peer-leading well results as evidenced by the recent noteworthy wells included below:

  • A four-well pad completed with 109 fracture stimulation (frac) stages with an initial production (IP) rate of 110 Mmcf per day and a 30-day production rate of 90 Mmcf per day.
  • A three-well pad completed with 68 frac stages with an IP rate of 98 Mmcf per day (still within the 30-day window).
  • A three-well pad completed with 50 frac stages with an IP rate of 59 Mmcf per day and a 30-day production rate of 57 Mmcf per day.
  • A three-well pad completed with 45 frac stages with an IP rate of 56 Mmcf per day and a 30-day production rate of 52 Mmcf per day.

"To date, our 2013 program has averaged three to four additional frac stages per well compared to our 2012 program due to longer lateral lengths and tighter frac stage spacing, resulting in higher production rates and higher estimated ultimate recoveries (EURs)," explained Dinges. "Our Marcellus wells continue to provide peer-leading production rates and EURs per 1,000' of lateral. We continue to see improvements in our rate-of-return profile as a result of our increased well performance, even if one assumes wider basis differentials to reflect the recent short-term softness in Marcellus pricing."

While certain Marcellus volumes were held back for a brief period of time during the end of the third quarter due to a combination of softness in Marcellus spot market pricing and scheduled infrastructure maintenance projects, the Company's gross Marcellus production volumes have since surpassed previous highs and recently achieved a record gross production rate of 1,295 Mmcf per day.

Eagle Ford Shale

During the third quarter, Cabot's Eagle Ford program experienced strong sequential growth with liquids production volumes increasing by approximately 28 percent over the second quarter. This was on the strength of new wells from Cabot's operated and non-operated positions. The Company's first four-well pad in the Eagle Ford was drilled during the third quarter in 58 days (spud to rig release) with a combined measured depth of approximately 58,000'. Completion is scheduled to begin at the end of October with lateral lengths ranging from 5,200' to 8,000'. The Company is currently drilling a six-well pad with a planned average lateral length of 9,000' per well.  Estimated cost savings from the use of a walking rig in the Company's multi-well pad drilling operations is $500,000 to $600,000 per well. In addition to the cost savings from its drilling operations, Cabot continues to see significant reductions in its stimulation costs per stage, further enhancing the return profile of its Eagle Ford wells. "We are in the process of further refining our well design in the Eagle Ford including drilling longer laterals, decreasing the spacing between frac stages and increasing the amount of proppant per stage," commented Dinges.  "Based on our work to date, we anticipate a significant uptick in returns as we begin implementing these new initiatives across the program."

Financial Position

As of September 30, 2013, the Company's net debt to adjusted capitalization ratio was 32.8 percent, compared to 33.2 percent at December 31, 2012 (detailed in the table below). The Company's total debt was $1,162 million, of which $475 million is outstanding under the Company's credit facility.

2014 Capital Budget and Guidance

The Company has reaffirmed its 2014 production growth guidance range of 30 to 50 percent, based on a capital program of $1.375 to $1.475 billion. Approximately 85 percent of the capital budget will be spent on drilling and completion activities, with over 75 percent of the drilling and completion capital focused on its Marcellus Shale operations. The capital budget assumes seven operated rigs in the Marcellus Shale and two operated rigs in the Eagle Ford Shale. The Company expects to drill 170 to 190 net wells in 2014, including 130 to 140 net wells in the Marcellus Shale and 40 to 50 net wells in the Eagle Ford Shale. The mid-point of guidance for 2014 unit costs (including financing) of $2.65 per Mcfe implies over a 10 percent decrease relative to the mid-point of 2013 unit cost guidance.

Conference Call

A conference call is scheduled for Friday, October 25, 2013, at 9:30 a.m. Eastern Time to discuss third quarter 2013 financial and operating results. To access the live audio webcast, please visit the Investor Relations section of the Company's website at www.cabotog.com. A replay of the call will also be available on the Company's website. The latest financial guidance, including the Company's hedge positions, is also available in the Investor Relations section of the Company's website.

Cabot Oil & Gas Corporation, headquartered in Houston, Texas is a leading independent natural gas producer, with its entire resource base located in the continental United States. For additional information, visit the Company's website at www.cabotog.com.

The statements regarding future financial performance and results and the other statements which are not historical facts contained in this release are forward-looking statements that involve risks and uncertainties, including, but not limited to, market factors, the market price (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in the Company's Securities and Exchange Commission filings.

FOR MORE INFORMATION CONTACT
Matt Kerin (281) 589-4642

 

 

            OPERATING DATA               

















Quarter Ended



Nine Months Ended





September 30,



September 30,





2013


2012



2013


2012

PRODUCED NATURAL GAS (Bcf) & LIQUIDS (MBbl)










Natural Gas










Appalachia


95.9


56.1



261.1


158.1

Other


5.8


6.6



16.4


20.3

  Total


101.7


62.7



277.5


178.4













Crude/Condensate/NGL


898


629



2,352


1,760













Equivalent Production (Bcfe)


107.1


66.5



291.7


188.9













PRICES(1)










Average Produced Gas Sales Price ($/Mcf)










Appalachia

$

3.38

$

3.80


$

3.65

$

3.70

Other

$

3.09

$

2.65


$

3.06

$

2.60

  Total 


$

3.36

$

3.68


$

3.62

$

3.57













Average Crude/Condensate Price ($/Bbl)

$

103.76

$

101.34


$

103.07

$

100.30













WELLS DRILLED 










  Gross


51


38



134


104

  Net


41


30



110.7


81

  Gross success rate


100%


95%



98%


97%













(1)  These realized prices include the realized impact of derivative instrument settlements.  





Quarter Ended


Nine Months Ended





September 30,



September 30,





2013


2012



2013


2012

     Realized Impacts to Gas Pricing


$   0.20


$  0.91



$  0.12


$  1.03

     Realized Impacts to Oil Pricing


$ (1.33)


$  6.65



$  1.43


$  3.39

 

 

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)



























Quarter Ended


Nine Months Ended





September 30,


September 30,





2013


2012


2013


2012

Operating Revenues









  Natural gas


$        341,901


$ 231,896


$ 1,004,085


$ 639,729

  Crude oil and condensate


84,209


57,870


220,090


165,317

  Brokered natural gas


7,165


5,238


26,302


23,831

  Other


2,575


1,870


8,338


5,790





435,850


296,874


1,258,815


834,667

Operating Expenses









  Direct operations


32,923


28,269


101,398


84,895

  Transportation and gathering


60,803


34,430


159,672


97,827

  Brokered natural gas


5,913


4,258


21,006


20,380

  Taxes other than income


11,532


10,436


34,583


39,873

  Exploration


3,891


9,303


12,444


29,548

  Depreciation, depletion and amortization


168,980


110,448


469,022


335,421

  General and administrative (excluding stock-based compensation) 


12,448


13,440


41,048


69,808

  Stock-based compensation(1)


12,249


10,389


40,961


23,441





308,739


220,973


880,134


701,193

Gain / (loss) on sale of assets


4,421


(126)


4,601


67,042

Income from Operations


131,532


75,775


383,282


200,516

Interest expense and other 


15,796


16,219


48,752


51,631

Income before income taxes


115,736


59,556


334,530


148,885

Income tax expense


45,847


22,948


132,703


58,021

Net Income


$          69,889


$   36,608


$    201,827


$   90,864

Earnings per share - Basic


$              0.17


$        0.09


$           0.48


$        0.22

Weighted average common shares outstanding


420,986


419,312


420,664


418,866



(1)

Includes the impact of the Company's performance share awards, restricted stock, stock appreciation rights and expense associated with the Supplemental Employee Incentive Plan. 

 

 


CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

  (In thousands)






September 30,


December 31,


2013


2012

Assets




Current assets

$          289,756


$           270,310

Properties and equipment, net

4,690,176


4,310,977

Other assets

51,460


35,026

   Total assets

$       5,031,392


$        4,616,313





Liabilities and Stockholders' Equity




Current liabilities

$          399,273


$           444,139

Long-term debt

1,162,000


1,012,000

Deferred income taxes

986,943


882,672

Other liabilities

154,442


146,055

Stockholders' equity

2,328,734


2,131,447

   Total liabilities and stockholders' equity

$       5,031,392


$        4,616,313




















CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

  (In thousands)


















Quarter Ended


Nine Months Ended


September 30,


September 30,


2013


2012


2013


2012

Cash Flows From Operating Activities








Net income

$            69,889


$             36,608


$      201,827


$       90,864

Deferred income tax expense

37,573


15,641


107,235


42,714

 (Gain) / loss on sale of assets

(4,421)


126


(4,601)


(67,042)

Exploration expense

1


1,193


807


12,118

Unrealized (gain) / loss on derivative instruments

-


149


-


449

Income charges not requiring cash

179,234


121,942


508,473


377,239

Changes in assets and liabilities

(5,567)


(11,692)


(47,065)


(1,230)

Net cash provided by operations

276,709


163,967


766,676


455,112









Cash Flows From Investing Activities








Capital expenditures

(319,472)


(257,871)


(843,528)


(669,198)

Proceeds from sale of assets

14,268


25


15,174


132,740

Investment in equity method investment

(4,374)


(2,400)


(8,624)


(4,488)

Net cash used in investing

(309,578)


(260,246)


(836,978)


(540,946)









Cash Flows From Financing Activities








Net increase (decrease) in debt

20,000


90,000


75,000


112,000

Stock-based compensation tax benefit

1,936


-


9,284


-

Capitalized debt issuance cost

-


-


-


(5,005)

Dividends paid

(8,423)


(4,193)


(16,830)


(12,561)

Other

11


(671)


44


(1,010)

Net cash provided by (used in) financing

13,524


85,136


67,498


93,424









Net increase (decrease) in cash and cash equivalents

$          (19,345)


$           (11,143)


$        (2,804)


$         7,590

 

 


Selected Item Review and Reconciliation of Net Income and Earnings Per Share

(In thousands, except per share amounts)










Quarter Ended


Nine Months Ended


September 30,


September 30,


2013


2012


2013


2012

As reported - net income

$          69,889


$         36,608


$ 201,827


$   90,864

Reversal of selected items, net of tax:








         (Gain) / loss on sale of assets

(2,670)


77


(2,776)


(41,030)

         Stock-based compensation expense

7,397


6,358


24,712


14,346

         Pension expense(1)

-


-


-


12,294

         Unrealized (gain) / loss on derivative instruments

-


91


-


275

         Pennsylvania impact fee(2)

-


-


-


5,067

Net income excluding selected items

$          74,616


$         43,134


$ 223,763


$   81,816

As reported - earnings per share 

$               0.17


$              0.09


$        0.48


$        0.22

Per share impact of reversing selected items 

0.01


0.02


0.05


(0.02)

Earnings per share including reversal of selected items

$               0.18


$              0.11


$        0.53


$        0.20

Weighted average common shares outstanding

420,986


419,312


420,664


418,866



(1)

On July 28, 2010, the Company notified its employees of its plan to terminate its qualified pension plan effective September 30, 2010. This amount represents pension expense related to the plan termination, including settlement costs and related expenses. Final distribution of the qualified pension plan occurred in the second quarter 2012. Pension expense is included in General and administrative expense in the Condensed Consolidated Statement of Operations. 

(2)

In February 2012, the Pennsylvania state legislature authorized the assessment of an impact fee on Marcellus Shale production. This amount represents the initial year accrual related to our 2011 and prior wells. Expenses associated with the impact fee are included in Taxes other than income in the Condensed Consolidated Statement of Operations. 

 

 

Discretionary Cash Flow Calculation and Reconciliation

(In thousands)


Quarter Ended


Nine Months Ended


September 30,


September 30,


2013


2012


2013


2012

   Discretionary Cash Flow








   As reported - net income

$          69,889


$         36,608


$ 201,827


$   90,864

   Plus / (less): 








   Deferred income tax expense

37,573


15,641


107,235


42,714

   (Gain) / loss on sale of assets

(4,421)


126


(4,601)


(67,042)

   Exploration expense

1


1,193


807


12,118

   Unrealized (gain) / loss on derivative instruments

-


149


-


449

   Income charges not requiring cash

179,234


121,942


508,473


377,239

   Discretionary Cash Flow

282,276


175,659


813,741


456,342

   Changes in assets and liabilities

(5,567)


(11,692)


(47,065)


(1,230)

   Net cash provided by operations

$        276,709


$       163,967


$ 766,676


$ 455,112

 

 

Net Debt Reconciliation

(In thousands)






September 30,


December 31,


2013


2012





   Current portion of long-term debt

$                      -


$          75,000

   Long-term debt

$     1,162,000


$    1,012,000

   Total debt

$     1,162,000


$    1,087,000

   Stockholders' equity

2,328,734


2,131,447

        Total Capitalization

$     3,490,734


$    3,218,447





   Total debt

$     1,162,000


$     1,087,000

   Less:  Cash and cash equivalents

(27,932)


(30,736)

        Net Debt

$     1,134,068


$    1,056,264





   Net debt

$     1,134,068


$    1,056,264

   Stockholders' equity

2,328,734


2,131,447

        Total Adjusted Capitalization

$     3,462,802


$    3,187,711





  Total debt to total capitalization ratio

33.3%


33.8%

   Less:  Impact of cash and cash equivalents

0.5%


0.6%

        Net Debt to Adjusted Capitalization Ratio

32.8%


33.2%

 

 

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