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

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Form 10-Q for CABOT OIL & GAS CORP


26-Apr-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 month periods ended March 31, 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 three months ended March 31, 2013 increased by 50% compared to the three months ended March 31, 2012. For the three months ended March 31, 2013, we produced 89.3 Bcfe, or 992.3 Mmcfe per day, compared to 59.7 Bcfe, or 655.7 Mmcfe per day, for three months ended March 31, 2012. Natural gas production increased by 28.8 Bcf, or 51%, to 85.2 Bcf for the first three months of 2013 compared to 56.4 Bcf for the first three 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 153 Mbbls, or 28%, from 538 Mbbls in the first three months of 2012 to 691 Mbbls in the first three months of 2013. This increase was primarily the result of increased production resulting from our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in 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 three months of 2013 was $3.45 per Mcf, 5% lower than the $3.65 per Mcf price realized in the first three months of 2012. Our average realized crude oil price for the first three months of 2013 was $104.03 per Bbl, 8% higher than the $96.67 per Bbl price realized in the first three 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 crude oil and natural gas reserves at economical costs are critical to our long-term success.

During the first three months of 2013, we drilled 32 gross wells (25.9 net) with a success rate of 97% compared to 31 gross wells (23.4 net) with a success rate of 100% for the comparable period of the prior year. For the three months ended March 31, 2013, our total capital and exploration spending was $253.5 million compared to $192.1 million for the three months ended March 31, 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 170 to 180 gross wells (130 to 145 net). Our 2013 drilling program includes between $950.0 million and $1.0 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 three months ended March 31, 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


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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.

Our working capital is also substantially influenced by 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.

                                                           Three Months Ended
                                                               March 31,
(In thousands)                                              2013        2012
Cash flows provided by operating activities              $  212,685   $ 131,780
Cash flows used in investing activities                    (260,933 )  (187,267 )
Cash flows provided by financing activities                  37,969      57,904
Net (decrease) / increase in cash and cash equivalents   $  (10,279 ) $   2,417

Operating Activities. Net cash provided by operating activities in the first three months of 2013 increased by $80.9 million over the first three 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 crude oil prices partially offset by lower realized natural gas prices. Equivalent production volumes increased by 50% for the three months ended March 31, 2013 compared to the three months ended March 31, 2012. Average realized crude oil prices increased by 8% while average realized natural gas prices decreased by 5% for the first three months of 2013 compared to the first three 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 $73.7 million for the first three months of 2013 compared to the first three months of 2012. The increase was primarily due an increase of $71.6 million in capital expenditures and $1.3 million of capital contributions associated with our equity method investment in Constitution Pipeline Company, LLC (Constitution). This increase was partially offset by a decrease of $0.8 million in proceeds from sale of assets.

Financing Activities. Cash flows provided by financing activities decreased by $19.9 million for the first three months of 2013 compared to the first three months of 2012. This decrease was primarily due to $22.0 million of lower net borrowings ($67.0 million increase in repayments of debt offset by $45.0 million increase in borrowings), partially offset by an increase of $2.1 million in tax benefits associated with our stock-based compensation.

At March 31, 2013, we had $365.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.3% and $534.0 million available for future borrowings. 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.

We were in compliance with all restrictive financial covenants in both the revolving credit facility and senior notes as of March 31, 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:



                             March 31,     December 31,
(Dollars in thousands)         2013            2012

Debt (1)                    $ 1,127,000   $    1,087,000
Stockholders' equity          2,123,214        2,131,447
Total capitalization        $ 3,250,214   $    3,218,447

Debt to capitalization              35%              34%

Cash and cash equivalents   $    20,457   $       30,736



(1) Includes $75.0 million of current portion of long-term debt at March 31, 2013 and December 31, 2012 and $365.0 million and $325.0 million of borrowings outstanding under our revolving credit facility at March 31, 2013 and December 31, 2012, respectively.

During the three months ended March 31, 2013, we paid dividends of $4.2 million ($0.02 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:

                            Three Months Ended
                                March 31,
(In thousands)               2013        2012
Capital expenditures
Drilling and facilities   $  233,143   $ 173,368
Leasehold acquisitions        16,177      15,147
Pipeline and gathering           108        (428 )
                             249,428     188,087
Exploration expense            4,024       4,001
Total                     $  253,452   $ 192,088

For the full year of 2013, we plan to drill approximately 170 to 180 gross wells (130 to 145 net). Our 2013 drilling program includes between $950.0 million to $1.0 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. 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

First Quarters of 2013 and 2012 Compared

We reported net income in the first quarter of 2013 of $42.8 million, or $0.20 per share, compared to $18.3 million, or $0.09 per share, in the first quarter of 2012. The increase in net income was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices and higher operating expenses.

Revenue, Price and Volume Variances



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



                                      Three Months Ended March 31,           Variance
Revenue Variances (In thousands)        2013               2012          Amount    Percent
Natural gas (1)                    $       293,793    $       206,740   $ 87,053       42%
Crude oil and condensate                    65,655             49,981     15,674       31%
Brokered natural gas                        10,893             13,444     (2,551 )    (19% )
Other                                        2,944              1,929      1,015       53%



(1) Natural gas revenues exclude the unrealized gain of $42,000 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 March 31,            Variance              (Decrease)
                                        2013              2012          Amount      Percent      (In thousands)
Price Variances
Natural gas (1)                    $          3.45    $        3.65    $   (0.20 )       (5% )  $        (17,142 )
Crude oil and condensate (2)       $        104.03    $       96.67    $    7.36          8%               4,643
Total                                                                                           $        (12,499 )
Volume Variances
Natural gas (Bcf)                             85.2             56.4         28.8         51%    $        104,195
Crude oil and condensate (Mbbl)                631              517          114         22%              11,031
Total                                                                                           $        115,226



(1) These prices include the realized impact of derivative instrument settlements, which increased the price by $0.16 per Mcf in 2013 and by $1.00 per Mcf in 2012.

(2) These prices include the realized impact of derivative instrument settlements, which increased the price by $3.24 per Bbl in 2013 and decreased the price by $2.57 per Bbl in 2012.


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Natural Gas Revenues

The increase in natural gas revenues of $87.1 million, excluding the impact of the unrealized losses discussed above, is primarily due to increased production partially offset by lower 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 and normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $15.7 million is primarily due to increased production associated with our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in Oklahoma, coupled with higher realized oil prices.

Brokered Natural Gas Revenue and Cost



                                                                                       Price and
                                  Three Months Ended                                     Volume
                                       March 31,                 Variance              Variances
                                   2013          2012       Amount      Percent      (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)             $      3.55    $   4.06    $   (0.51 )      (13% )  $         (1,560 )
Volume brokered (Mmcf)          x     3,067    x  3,311         (244 )       (7% )              (991 )
Brokered natural gas (In
thousands)                      $    10,893    $ 13,444                             $         (2,551 )

Brokered Natural Gas
Purchases
Purchase price ($/Mcf)          $      2.74    $   3.59    $   (0.85        (24% )  $          2,608
Volume brokered (Mmcf)          x     3,067    x  3,311         (244         (7% )               875
Brokered natural gas (In
thousands)                      $     8,389    $ 11,872                             $          3,483

Brokered natural gas margin
(In thousands)                  $     2,504    $  1,572                             $            932

The increased brokered natural gas margin of $0.9 million is primarily a result a decrease in purchase price that outpaced the decrease in sales 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
                                               March 31,
(In thousands)                              2013         2012

Cash Flow Hedges
Natural gas                              $    13,328   $ 56,996
Crude oil                                      2,042     (1,326 )
Other Derivative Financial Instruments
Natural gas basis swaps                            -         42
                                         $    15,370   $ 55,712


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Operating and Other Expenses



                                      Three Months Ended March 31,              Variance
(In thousands)                          2013               2012            Amount       Percent
Operating and Other Expenses
Direct operations                  $        31,497    $        27,320    $    4,177          15%
Transportation and gathering                46,221             30,258        15,963          53%
Brokered natural gas                         8,389             11,872        (3,483 )       (29% )
Taxes other than income                     11,687             18,583        (6,896 )       (37% )
Exploration                                  4,024              4,001            23           1%
Depreciation, depletion and
amortization                               148,653            110,357        38,296          35%
General and administrative                  35,704             22,549        13,155          58%
Total operating expense            $       286,175    $       224,940    $   61,235          27%

(Gain) / loss on sale of assets    $            96    $           535    $     (439 )       (82% )
Interest expense and other                  16,255             16,917          (662 )        (4% )
Income tax expense                          27,935             11,426        16,509         144%

Total costs and expenses from operations increased by $61.2 million, or 27%, in the first quarter of 2013 compared to the same period of 2012. The primary reasons for this fluctuation are as follows:

Direct operations increased $4.2 million largely due to higher operating costs primarily driven by increased production. Contributing to the increase are higher employee related costs, partially offset by decreased workover activity.

Transportation and gathering increased $16.0 million due to higher throughput due to an increase in production and higher transportation rates, coupled with the commencement of various transportation and gathering agreements throughout 2012 primarily in northeast Pennsylvania and south Texas.

Brokered natural gas decreased $3.5 million. See the preceding table titled "Brokered Natural Gas Revenue and Cost" for further analysis.

Taxes other than income decreased $6.9 million primarily due to lower impact fees associated with our Marcellus Shale production. The first quarter of 2012 included the initial assessment of impact fees associated with 2011 and prior period wells.

Depreciation, depletion and amortization increased $38.3 million, of which $49.9 million was due to higher equivalent production volumes for the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012, partially offset by a decrease of $10.7 million due to a lower DD&A rate of $1.56 per Mcfe for the quarter ended March 31, 2013 compared to $1.68 Mfce for the quarter ended March 31, 2012. The lower DD&A rate was primarily due to lower cost of reserve additions associated with our 2013 and 2012 drilling programs. The increase in depreciation and depletion was partially offset by a decrease in amortization of unproved properties of $1.1 million.

General and administrative increased $13.2 million primarily due to $17.0 million of higher stock-based compensation expense associated with the mark-to-market of our liability-based performance awards and our supplemental employee incentive plan due to changes in our stock price for the first quarter 2013 compared to the first quarter of 2012, partially offset by $6.2 million of lower pension expense associated with the liquidation of our pension plan that occurred in the second quarter of 2012.

Interest Expense and Other

Interest expense and other decreased $0.7 million primarily due a to lower weighted-average effective interest rate on our revolving credit facility borrowings of approximately 2.3% during the first quarter of 2013 compared to approximately 4.0% during the first quarter of 2012, partially offset by an increase in weighted-average borrowings under our revolving credit facility based


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on daily balances of approximately $361.6 million during the first quarter of 2013 compared to approximately $235.4 million during the first quarter of 2012.

Income Tax Expense

Income tax expense increased $16.5 million primarily due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the first quarter of 2013 and 2012 was 39.5% and 38.4%, respectively. The increase in the effective rate in 2013 was due to an increase in estimated state tax liabilities.

Forward-Looking Information

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict," "may," "should," "could," "will" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See "Risk Factors" in Item 1A of the Form 10-K for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

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