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COG > SEC Filings for COG > Form 10-Q on 25-Apr-2014All Recent SEC Filings

Show all filings for CABOT OIL & GAS CORP

Form 10-Q for CABOT OIL & GAS CORP


25-Apr-2014

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, 2014 and 2013 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, 2013 (Form 10-K).

Overview

On an equivalent basis, our production for the three months ended March 31, 2014 increased by 34% compared to the three months ended March 31, 2013. For the three months ended March 31, 2014, we produced 119.9 Bcfe, or 1,331.8 Mmcfe per day, compared to 89.3 Bcfe, or 992.3 Mmcfe per day, for the three months ended March 31, 2013. Natural gas production increased by 30.6 Bcf, or 36%, to 115.8 Bcf for the first three months of 2014 compared to 85.2 Bcf for the first three months of 2013. This increase was primarily the result of higher production in the Marcellus Shale associated with our drilling program. Partially offsetting the production increase in the Marcellus Shale were decreases in production due to certain non-core asset dispositions in Texas and Oklahoma in the fourth quarter of 2013 and normal production declines in Texas and West Virginia. Crude oil/condensate/NGL production decreased by 5 Mbbls, or 1%, to 686 Mbbls in the first three months of 2014 from 691 Mbbls in the first three months of 2013. This decrease was primarily due to certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013, partially offset by higher production resulting from our oil-focused drilling program in south Texas.

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 2014 was $3.74 per Mcf, 8% higher than the $3.45 per Mcf price realized in the first three months of 2013. Our average realized crude oil price for the first three months of 2014 was $97.76 per Bbl, 6% lower than the $104.03 per Bbl price realized in the first three months of 2013. 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 three months of 2014, we drilled 27 gross wells (27.0 net) with a success rate of 100% compared to 32 gross wells (25.9 net) with a success rate of 97% for the comparable period of the prior year. Our total capital and exploration expenditures were $316.4 million for the three months ended March 31, 2014 compared to $253.5 million for the three months ended March 31, 2013. The increase in capital spending was the result of our Marcellus Shale horizontal drilling program in northeast Pennsylvania and our drilling program in the Eagle Ford Shale in south Texas. We allocate our planned program for capital and exploration expenditures among our various operating areas based on return expectations, availability of services and human resources. Our 2014 drilling program includes between $1.375 billion and $1.475 billion in capital and exploration expenditures and is expected to be funded by operating cash flow, existing cash and, if required, borrowings under our revolving 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, 2014 were from funds generated from the sale of natural gas and crude oil production (including the impact of realizations from our commodity derivatives) and net borrowings under our revolving 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 and changes in our production volumes and operating expenses. Prices for natural gas and crude oil have historically been volatile, including seasonal influences and demand; 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 revolving credit facility and liquidity available to meet our working capital requirements.

                                                           Three Months Ended
                                                               March 31,
(In thousands)                                              2014        2013
Cash flows provided by operating activities              $  255,378   $ 212,685
Cash flows used in investing activities                    (336,148 )  (260,933 )
Cash flows provided by financing activities                  82,801      37,969
Net increase / (decrease) in cash and cash equivalents   $    2,031   $ (10,279 )

Operating Activities. Net cash provided by operating activities in the first three months of 2014 increased by $42.7 million over the first three months of 2013. 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 other assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized natural gas prices, partially offset by the decrease in realized crude oil prices. Equivalent production volumes increased by 34% for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 as a result of higher natural gas production. Average realized natural gas prices increased by 8% and average realized crude oil prices decreased by 6% for the first three months of 2014 compared to the first three months of 2013.

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 $75.2 million for the first three months of 2014 compared to the first three months of 2013. The increase was due to $78.5 million of higher capital expenditures and an increase of $4.7 million in capital contributions associated with our equity method investments. Partially offsetting the increases was a decrease in restricted cash of $8.4 million related to funding of oil and gas lease acquisitions by our qualified intermediary during the first quarter of 2014 associated with our like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.

Financing Activities. Cash flows provided by financing activities increased by $44.8 million for the first three months of 2014 compared to the first three months of 2013. This increase was primarily due to $35.0 million of higher net borrowings and an increase of $13.9 million in tax benefits associated with our stock-based compensation, partially offset by a $4.1 million increase in dividend payments.

Effective April 15, 2014, the lenders under our revolving credit facility approved an increase in our borrowing base from $2.3 billion to $3.1 billion as part of the annual redetermination under the terms of the revolving credit facility. The commitments under the revolving credit facility remain unchanged at $1.4 billion. At March 31, 2014, we had $535.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 2.2% and $864.0 million available for future borrowings. See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further details.

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, existing cash on hand and availability under our revolving credit facility, we have the capacity to finance our spending plans 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)         2014            2013
Debt (1)                    $ 1,222,000   $    1,147,000
Stockholders' equity          2,268,791        2,204,602
Total capitalization        $ 3,490,791   $    3,351,602

Debt to capitalization              35%              34%

Cash and cash equivalents   $    25,431   $       23,400



(1) Includes $535.0 million and $460.0 million of borrowings outstanding under our revolving credit facility at March 31, 2014 and December 31, 2013, respectively.

During the three months ended March 31, 2014, we paid dividends of $8.3 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 expenditures, excluding any significant property acquisitions, with cash generated from operations and, when necessary, borrowings under our revolving credit facility. We budget these expenditures based on our projected cash flows for the year.

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

                            Three Months Ended
                                March 31,
(In thousands)               2014        2013
Capital Expenditures
Drilling and facilities   $  292,736   $ 230,049
Leasehold acquisitions        14,849      16,177
Pipeline and gathering           (34 )       108
Other                          2,377       3,094
                             309,928     249,428
Exploration expense            6,474       4,024
Total                     $  316,402   $ 253,452

For the full year of 2014, we plan to drill approximately 155 to 175 gross wells (150 to 170 net). In 2014, we plan to spend approximately $1.375 billion and $1.475 billion in total capital and exploration expenditures (excluding expected contributions of approximately $36.4 million to Constitution and approximately $0.4 million to Meade). See "Overview" for additional information regarding the current year drilling program. We will continue to assess the natural gas and crude oil price environment and 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 certain new and amended transportation agreements described in Note 8 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 and Gathering Agreements", "Drilling Rig Commitments" and "Lease Commitments" as disclosed in Note 9 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.

Results of Operations

First Quarters of 2014 and 2013 Compared

We reported net income in the first quarter of 2014 of $107.0 million, or $0.26 per share, compared to $42.8 million, or $0.10 per share, in the first quarter of 2013. The increase in net income was due to an increase in equivalent production and higher realized natural gas prices, partially offset by higher operating expenses and lower realized crude oil prices.

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)        2014               2013          Amount     Percent
Natural gas                        $       432,809    $       293,793   $ 139,016       47%
Crude oil and condensate                    59,144             65,655      (6,511 )    (10% )
Brokered natural gas                        13,153             10,893       2,260       21%
Other                                        4,697              2,944       1,753       60%




                                                                                              Increase
                                       Three Months Ended
                                           March 31,                   Variance              (Decrease)
                                       2014           2013        Amount      Percent      (In thousands)
Price Variances
Natural gas (1)                    $        3.74    $    3.45    $    0.29          8%    $         33,597
Crude oil and condensate (2)       $       97.76    $  104.03    $   (6.27 )       (6% )            (3,792 )
Total                                                                                     $         29,805
Volume Variances
Natural gas (Bcf)                          115.8         85.2         30.6         36%    $        105,419
Crude oil and condensate (Mbbl)              605          631          (26 )       (4% )            (2,719 )
Total                                                                                     $        102,700



(1) These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.61 per Mcf in 2014 and increased the price by $0.16 per Mcf in 2013.

(2) These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.36 per Bbl in 2014 and increased the price by $3.24 per Bbl in 2013.

Natural Gas Revenues

The increase in natural gas revenues of $139.0 million is due to higher production and higher realized natural gas prices. The increase in production was a result of our Marcellus Shale drilling program, partially offset by the decrease in production due to certain non-core asset dispositions in the Oklahoma and Texas in the fourth quarter of 2013 and lower production in Texas and West Virginia due normal production declines.

Crude Oil and Condensate Revenues

The decrease in crude oil and condensate revenues of $6.5 million is due to higher production associated with our oil-focused drilling program in south Texas, partially offset by the decrease in production primarily due to certain non-core asset dispositions in Texas and Oklahoma in the fourth quarter of 2013 and lower realized crude oil prices.


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Brokered Natural Gas Revenue and Cost



                                                                                         Price and
                                    Three Months Ended                                     Volume
                                        March 31,                  Variance              Variances
                                    2014          2013        Amount      Percent      (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)              $      4.90    $    3.55    $    1.35         38%    $          3,613
Volume brokered (Mmcf)           x     2,686    x   3,067         (381 )      (12% )            (1,353 )
Brokered natural gas (In
thousands)                       $    13,153    $  10,893                             $          2,260

Brokered Natural Gas
Purchases
Purchase price ($/Mcf)           $      4.42    $    2.74    $    1.68         61%    $         (4,513 )

Volume brokered (Mmcf) x 2,686 x 3,067 (381 ) (12% ) 1,042 Brokered natural gas (In
thousands) $ 11,860 $ 8,389 $ (3,471 )

Brokered natural gas margin
(In thousands) $ 1,293 $ 2,504 $ (1,211 )

The $1.2 million decrease in brokered natural gas margin is a result of an increase in purchase price that outpaced the increase in sales price and lower brokered volumes.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to operating revenues from the realized impact of cash settlements for derivative instruments designated as cash flow hedges:

Three Months Ended

                         March 31,
(In thousands)        2014         2013

Cash Flow Hedges
Natural gas        $   (70,557 ) $ 13,328
Crude oil                 (218 )    2,042
                   $   (70,775 ) $ 15,370

Operating and Other Expenses



                                      Three Months Ended March 31,              Variance
(In thousands)                          2014               2013            Amount       Percent
Operating and Other Expenses
Direct operations                  $        35,834    $        31,497    $    4,337          14%
Transportation and gathering                77,765             46,221        31,544          68%
Brokered natural gas                        11,860              8,389         3,471          41%
Taxes other than income                     13,044             11,687         1,357          12%
Exploration                                  6,474              4,024         2,450          61%
Depreciation, depletion and
amortization                               147,418            148,653        (1,235 )        (1% )
General and administrative                  21,636             35,704       (14,068 )       (39% )
Total operating expense            $       314,031    $       286,175    $   27,856          10%

(Gain) / loss on sale of assets    $         1,285    $            96    $    1,189       1,239%
Interest expense and other                  16,557             16,255           302           2%
Income tax expense                          70,899             27,935        42,964         154%

Total costs and expenses from operations increased by $27.9 million, or 10%, in the first quarter of 2014 compared to the same period of 2013. The primary reasons for this fluctuation are as follows:

Direct operations increased $4.3 million largely due to higher operating costs primarily driven by higher production, partially offset by lower costs due to the disposition of certain non-core assets in Oklahoma and Texas in the fourth


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quarter of 2013. Contributing to the increase are higher workover and employee-related costs, partially offset by lower plugging and abandonment costs. In addition, we experienced higher costs associated with oil separation and processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas.

Transportation and gathering increased $31.5 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements primarily in northeast Pennsylvania.

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

Taxes other than income increased $1.4 million due to higher drilling impact fees associated with our Marcellus Shale drilling activities and higher production taxes. Production taxes increased due to higher oil production in south Texas, offset by lower taxes as a result of the disposition of certain non-core assets in Oklahoma and Texas in the fourth quarter of 2013.

Exploration expense increased $2.5 million as a result of higher exploratory dry hole costs and higher employee related and other costs.

Depreciation, depletion and amortization decreased $1.2 million, of which $47.7 million was due to a lower DD&A rate of $1.17 per Mcfe for the first quarter of 2014 compared to $1.56 per Mcfe for the first quarter of 2013, offset by a $47.8 million due to higher equivalent production volumes. The lower DD&A rate was primarily due to higher production in areas with lower DD&A rates and the impact of the disposition of higher rate fields in Oklahoma and Texas in the fourth quarter of 2013. In addition, amortization of unproved properties decreased $1.5 million in the first quarter in 2014.

General and administrative decreased $14.1 million due to lower stock-based compensation expense of $15.5 million associated with the mark-to-market of our liability-based performance awards and supplemental employee incentive plan due to changes in our stock price during 2014 compared to 2013, partially offset by $1.5 million of higher employee related costs.

Income Tax Expense

Income tax expense increased $43.0 million primarily due to higher pretax income and a slightly higher effective tax rate. The effective tax rate for the first quarter of 2014 and 2013 was 39.8% and 39.5%, respectively.

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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