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COG > SEC Filings for COG > Form 10-Q on 26-Jul-2013All Recent SEC Filings

Show all filings for CABOT OIL & GAS CORP

Form 10-Q for CABOT OIL & GAS CORP


26-Jul-2013

Quarterly Report


ITEM 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations

The following review of operations for the three and six month periods ended June 30, 2013 and 2012 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Form 10-Q and with the Consolidated Financial Statements, Notes and Management's Discussion and Analysis included in the Cabot Oil & Gas Corporation Annual Report on Form 10-K for the year ended December 31, 2012 (Form 10-K).

Overview

On an equivalent basis, our production for the six months ended June 30, 2013 increased by 51% compared to the six months ended June 30, 2012. For the six months ended June 30, 2013, we produced 184.5 Bcfe, or 1,019.6 Mmcfe per day, compared to 122.4 Bcfe, or 672.8 Mmcfe per day, for the six months ended June 30, 2012. Natural gas production increased by 60.1 Bcf, or 52%, to 175.8 Bcf for the first six months of 2013 compared to 115.7 Bcf for the first six months of 2012. This increase was primarily the result of increased production in the Marcellus Shale associated with our drilling program and continued expansion of infrastructure in the area. This increase was partially offset by decreases in production in Texas, Oklahoma and West Virginia due to reduced natural gas drilling and normal production declines. Crude oil/condensate/NGL production increased by 323 Mbbls, or 29%, from 1,131 Mbbls in the first six months of 2012 to 1,454 Mbbls in the first six months of 2013. This increase was primarily the result of increased production resulting from our oil-focused drilling program in south Texas and Oklahoma.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Our average realized natural gas price for the first six months of 2013 was $3.77 per Mcf, 7% higher than the $3.52 per Mcf price realized in the first six months of 2012. Our average realized crude oil price for the first six months of 2013 was $102.65 per Bbl, 3% higher than the $99.76 per Bbl price realized in the first six months of 2012. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to "Results of Operations" below. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success.

During the first six months of 2013, we drilled 83 gross wells (69.7 net) with a success rate of 96% compared to 66 gross wells (51.2 net) with a success rate of 99% for the comparable period of the prior year. For the six months ended June 30, 2013, our total capital and exploration spending was $554.1 million compared to $436.5 million for the six months ended June 30, 2012. The increase in capital spending was primarily due to our Marcellus Shale horizontal drilling program in northeast Pennsylvania, the Eagle Ford and Pearsall Shale in south Texas and the Marmaton oil play in Oklahoma. For the full year 2013, we plan to drill approximately 185 to 195 gross wells (155 to 165 net). Our 2013 drilling program includes between $1.1 billion and $1.2 billion in capital and exploration expenditures and is expected to be funded by operating cash flow, existing cash and, if required, borrowings under our credit facility. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

Financial Condition

Capital Resources and Liquidity

Our primary sources of cash for the six months ended June 30, 2013 were funds generated from the sale of natural gas and crude oil production (including realizations from our derivative instruments) and net borrowings under our credit facility. These cash flows were primarily used to fund our capital and exploration expenditures and payment of dividends. See below for additional discussion and analysis of cash flow.

Operating cash flow fluctuations are substantially driven by commodity prices, changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been and continue to be volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties, as described in our Form 10-K and other filings with the Securities and Exchange Commission, have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See "Results of Operations" for a review of the impact of prices and volumes on revenues.


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Our working capital is also substantially influenced by the variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate availability under our credit facility and liquidity available to meet our working capital requirements.

                                                Six Months Ended
                                                    June 30,
(In thousands)                                  2013        2012
Cash flows provided by operating activities   $ 489,967   $ 291,142
Cash flows used in investing activities        (527,400 )  (280,700 )
Cash flows provided by financing activities      53,974       8,288
Net increase in cash and cash equivalents     $  16,541   $  18,730

Operating Activities. Net cash provided by operating activities in the first six months of 2013 increased by $198.8 million over the first six months of 2012. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and unfavorable changes in working capital and long-term assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized natural gas and crude oil prices. Equivalent production volumes increased by 51% for the six months ended June 30, 2013 compared to the six months ended June 30, 2012. Average realized natural gas prices increased by 7% and average realized crude oil prices increased by 3% for the first six months of 2013 compared to the first six months of 2012.

See "Results of Operations" for additional information relative to commodity price, production and operating expense movements. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may decline in future periods.

Investing Activities. Cash flows used in investing activities increased by $246.7 million for the first six months of 2013 compared to the first six months of 2012. The increase was primarily due to $131.8 million of lower proceeds from sale of assets, an increase of $112.7 million in capital expenditures and an increase of $2.2 million in capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution).

Financing Activities. Cash flows provided by financing activities increased by $45.7 million for the first six months of 2013 compared to the first six months of 2012. This increase was primarily due to $33.0 million of higher net borrowings, an increase of $7.3 million in tax benefits associated with our stock-based compensation and a $5.0 decrease in capitalized debt issuance costs.

Effective April 17, 2013, the lenders under our revolving credit facility approved an increase in our borrowing base from $1.7 billion to $2.3 billion as part of the annual redetermination under the terms of the revolving credit facility. The Company's commitments under the credit facility of $900.0 million remained unchanged. At June 30, 2013, we had $380.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.0% and $519.0 million available for future borrowings.

We were in compliance with all restrictive financial covenants in both the revolving credit facility and senior notes as of June 30, 2013.

We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. Management believes that, with internally generated cash flow from operations, existing cash on hand and availability under our revolving credit facility, if required, we have the capacity to finance our spending plans, service our debt obligations as they become due and maintain our strong financial position.


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Capitalization



Information about our capitalization is as follows:



                             June 30,      December 31,
(Dollars in thousands)         2013            2012

Debt (1)                    $ 1,142,000   $    1,087,000
Stockholders' equity          2,286,241        2,131,447
Total capitalization        $ 3,428,241   $    3,218,447

Debt to capitalization              33%              34%

Cash and cash equivalents   $    47,277   $       30,736



(1) Includes $75.0 million of current portion of long-term debt at June 30, 2013 and December 31, 2012 and $380.0 million and $325.0 million of borrowings outstanding under our revolving credit facility at June 30, 2013 and December 31, 2012, respectively.

During the six months ended June 30, 2013, we paid dividends of $8.4 million ($0.04 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, if necessary, borrowings under our revolving credit facility. We budget these capital and exploration expenditures based on our current estimate of future commodity prices and projected cash flows for the year.

The following table presents major components of capital and exploration expenditures:

                            Six Months Ended
                                June 30,
(In thousands)              2013        2012
Capital expenditures
Drilling and facilities   $ 506,210   $ 363,756
Leasehold acquisitions       39,047      47,399
Pipeline and gathering          263        (466 )
Other                             -       5,562
                            545,520     416,251
Exploration expense           8,553      20,245
Total                     $ 554,073   $ 436,496

For the full year of 2013, we plan to drill approximately 185 to 195 gross wells (155 to 165 net). Our 2013 drilling program includes between $1.1 billion to $1.2 billion in total planned capital and exploration expenditures. See "Overview" for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment along with our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. Except for the amended transportation agreements and two new drilling rig commitments described in Note 6 to the Condensed Consolidated Financial Statements included in this Form 10-Q, there have been no material changes to our contractual obligations described under "Transportation Agreements", "Drilling Rig Commitments" and "Lease Commitments" as disclosed in Note 8 in the Notes to Consolidated Financial Statements and the obligations described under "Contractual Obligations" in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our Form 10-K.


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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Form 10-K for further discussion of our critical accounting policies.

Recent Accounting Pronouncements

Effective January 1, 2013, we adopted the amended disclosure requirements prescribed in Accounting Standards Update (ASU) No. 2011-11, "Disclosures about Offsetting Assets and Liabilities" and ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities." This guidance impacted the disclosures associated with our commodity derivatives and did not impact our consolidated financial position, results of operations or cash flows.

Effective January 1, 2013, we adopted the amended disclosure requirements prescribed in ASU No. 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." This guidance impacted our disclosures associated with items reclassified from accumulated other comprehensive income /
(loss) and did not impact our consolidated financial position, results of operations or cash flows.

Results of Operations

Second Quarters of 2013 and 2012 Compared

We reported net income in the second quarter of 2013 of $89.1 million, or $0.42 per share, compared to $35.9 million, or $0.17 per share, in the second quarter of 2012. The increase in net income was primarily due to an increase in equivalent production and higher realized natural gas prices, partially offset by higher operating expenses and slightly lower crude oil prices.

Revenue, Price and Volume Variances



Below is a discussion of revenue, price and volume variances.



                                      Three Months Ended June 30,            Variance

Revenue Variances (In thousands)        2013               2012          Amount     Percent
Natural gas (1)                    $       368,391    $       201,393   $ 166,998       83%
Crude oil and condensate                    70,226             57,466      12,760       22%
Brokered natural gas                         8,244              5,149       3,095       60%
Other                                        2,819              1,991         828       42%



(1) Natural gas revenues exclude the unrealized loss of $0.3 million from the change in fair value of our derivatives not designated as hedges in 2012. There were no unrealized gains or losses in 2013.

                                                                                             Increase
                               Three Months Ended June 30,             Variance              (Decrease)

                                  2013              2012          Amount      Percent      (In thousands)
Price Variances
Natural gas (1)              $         4.06    $         3.39    $    0.67         20%    $         61,075
Crude oil and condensate
(2)                          $       101.39    $       102.61    $   (1.22 )       (1% )              (840 )

Total                                                                                     $         60,235
Volume Variances
Natural gas (Bcf)                      90.7              59.2         31.5         53%    $        105,923
Crude oil and condensate
(Mbbl)                                  693               560          133         24%              13,600

Total                                                                                     $        119,523



(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $1.18 per Mcf in 2012. There was no impact on the realized price from derivative instrument settlements in 2013.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $3.02 per Bbl in 2013 and decreased the price by $5.55 per Bbl in 2012.


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Natural Gas Revenues

The increase in natural gas revenues of $167.0 million, excluding the impact of the unrealized losses on derivative instruments discussed above, is primarily due to increased production and higher realized natural gas prices. The increased production was primarily a result of higher production in the Marcellus Shale associated with our drilling program and expanded infrastructure, partially offset by decreases in production primarily in Texas, Oklahoma and West Virginia due reduced natural gas drilling in these areas and normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $12.8 million is primarily due to increased production associated with our oil-focused drilling program in south Texas and Oklahoma, partially offset by slightly lower realized oil prices.

Brokered Natural Gas Revenue and Cost



                                                                                        Price and
                                   Three Months Ended                                     Volume
                                        June 30,                  Variance              Variances
                                    2013         2012        Amount      Percent      (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)              $     4.81    $    2.82    $    1.99         71%    $          3,414
Volume brokered (Mmcf)           x    1,714    x   1,827         (113 )       (6% )              (319 )

Brokered natural gas (In
thousands)                       $    8,244    $   5,149                             $          3,095

Brokered Natural Gas
Purchases
Purchase price ($/Mcf)           $     3.91    $    2.33    $    1.58         68%    $         (2,717 )
Volume brokered (Mmcf)           x    1,714    x   1,827         (113 )       (6% )               263

Brokered natural gas (In
thousands)                       $    6,704    $   4,250                             $         (2,454 )

Brokered natural gas margin
(In thousands)                   $    1,540    $     899                             $            641

The increase in brokered natural gas margin of $0.6 million is primarily a result of an increase in sales price that outpaced the increase in purchase price, partially offset by lower brokered volumes.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to revenue from the realized impact of cash settlements for derivative instruments designated as cash flow hedges and the net unrealized change in fair value of other financial derivative instruments:

                                           Three Months Ended
                                                June 30,
(In thousands)                              2013         2012

Cash Flow Hedges
Natural gas                              $     (272 )  $  69,732
Crude oil                                     2,094        3,110
Other Derivative Financial Instruments
Natural gas basis swaps                           -         (342 )
                                         $    1,822    $  72,500


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Operating and Other Expenses



                                       Three Months Ended June 30,               Variance
(In thousands)                           2013               2012            Amount       Percent
Operating and Other Expenses
Direct operations                   $        36,978             29,306    $    7,672          26%
Transportation and gathering                 52,648             33,139        19,509          59%
Brokered natural gas                          6,704              4,250         2,454          58%
Taxes other than income                      11,364             10,854           510           5%
Exploration                                   4,529             16,244       (11,715 )       (72% )
Depreciation, depletion and
amortization                                151,389            114,616        36,773          32%
General and administrative                   21,608             46,872       (25,264 )       (54% )

Total operating expense             $       285,220    $       255,281    $   29,939          12%

(Gain) / loss on sale of assets     $          (276 )  $       (67,703 )  $  (67,427 )      (100% )
Interest expense and other                   16,701             18,495        (1,794 )       (10% )
Income tax expense                           58,921             23,647        35,274         149%

Total costs and expenses from operations increased by $29.9 million, or 12%, in the second quarter of 2013 compared to the same period of 2012. The primary reasons for this fluctuation are as follows:

Direct operations increased $7.7 million largely due to higher operating costs primarily driven by increased production, including higher treating and disposal costs associated with an increase in produced water and more stringent pipeline quality requirements. In addition, we experienced higher plugging and abandonment costs associated with certain wells in south Texas and a slight increase in outside-operated and employee-related costs due to an increase in headcount.

Transportation and gathering increased $19.5 million due to higher throughput as a result of increased production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in the second half of 2012 primarily in northeast Pennsylvania and south Texas.

Brokered natural gas increased $2.5 million. See the preceding table titled "Brokered Natural Gas Revenue and Cost" for further analysis.

Exploration expense decreased $11.7 million due to an exploratory dry hole associated with our Brown Dense/Smackover exploratory well in Union County, Arkansas recorded in the second quarter of 2012. There were no dry holes recorded in the second quarter of 2013.

Depreciation, depletion and amortization increased $36.8 million, of which $55.4 million was due to higher equivalent production volumes for the second quarter of 2013 compared to the second quarter of 2012, partially offset by a decrease of $19.1 million due to a lower DD&A rate of $1.50 per Mcfe for the second quarter of 2013 compared to $1.71 per Mcfe for the second quarter of 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs.

General and administrative decreased $25.3 million primarily due to $13.3 million of lower pension expense associated with the liquidation of our pension plan that occurred in the second quarter of 2012, a $5.3 million decrease in legal and professional expenses and slightly lower stock-based compensation expense associated with the mark-to-market of our liability-based performance awards and supplemental employee incentive plan due to changes in our stock price for the second quarter 2013 compared to the second quarter of 2012.

(Gain) / Loss on Sale of Assets

The decrease of $67.4 million is primarily due to the gain on sale of certain of our Pearsall Shale undeveloped leaseholds in south Texas recognized in the second quarter of 2012. There were no significant gains or losses on sale of assets recognized in the second quarter of 2013.


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Interest Expense and Other

Interest expense and other decreased $1.8 million primarily due a to lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.2% during the second quarter of 2013 compared to approximately 3.4% during the second quarter of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based on daily balances of approximately $405.7 million during the second quarter of 2013 compared to approximately $293.7 million during the second quarter of 2012.

Income Tax Expense

Income tax expense increased $35.3 million primarily due to higher pretax income. The effective tax rate for the second quarter of 2013 and 2012 was 39.8% and 39.7%, respectively.

First Six Months of 2013 and 2012 Compared

We reported net income in the first six months of 2013 of $131.9 million, or $0.63 per share, compared to $54.3 million, or $0.26 per share, in the first six months of 2012. The increase in net income was primarily due to an increase in equivalent production and higher realized natural gas and crude oil prices partially offset higher operating expenses.

Revenue, Price and Volume Variances



Below is a discussion of revenue, price and volume variances.



                                      Six Months Ended June 30,            Variance
Revenue Variances (In thousands)        2013              2012         Amount     Percent
Natural gas (1)                    $      662,184    $      408,133   $ 254,051       62%
Crude oil and condensate                  135,881           107,447      28,434       26%
Brokered natural gas                       19,137            18,593         544        3%
Other                                       5,763             3,920       1,843       47%


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