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

Show all filings for CABOT OIL & GAS CORP

Form 10-Q for CABOT OIL & GAS CORP


25-Jul-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 and six month periods ended June 30, 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 six months ended June 30, 2014 increased by 34% compared to the six months ended June 30, 2013. For the six months ended June 30, 2014, we produced 247.5 Bcfe, or 1,367.3 Mmcfe per day, compared to 184.5 Bcfe, or 1,019.6 Mmcfe per day, for the six months ended June 30, 2013. Natural gas production increased by 61.8 Bcf, or 35%, to 237.6 Bcf for the first six months of 2014 compared to 175.8 Bcf for the first six 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 in west Texas and Oklahoma due to certain non-core asset dispositions in the fourth quarter of 2013 and normal production declines in Texas and West Virginia. Crude oil/condensate/NGL production increased by 193 Mbbls, or 13%, to 1,647 Mbbls in the first six months of 2014 from 1,454 Mbbls in the first six months of 2013. This increase was due to higher production resulting from our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013.

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 2014 was $3.60 per Mcf, 5% lower than the $3.77 per Mcf price realized in the first six months of 2013. Our average realized crude oil price for the first six months of 2014 was $98.39 per Bbl, 4% lower than the $102.65 per Bbl price realized in the first six 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, crude oil and NGL 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.

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments are accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. As a result of these mark-to-market adjustments, we will likely experience volatility in our earnings from time to time due to commodity price volatility. Refer to "Impact of Derivative Instruments on Operating Revenues" below and Note 5 to the Condensed Consolidated Financial Statements for more information.

During the first six months of 2014, we drilled 76 gross wells (62.0 net) with a success rate of 100% compared to 83 gross wells (69.7 net) with a success rate of 96% for the comparable period of the prior year. Our total capital and exploration expenditures were $594.0 million for the six months ended June 30, 2014 compared to $554.1 million for the six months ended June 30, 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 $1.375 billion to $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 six months ended June 30, 2014 were from funds generated from the sale of natural gas and crude oil production 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.


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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.

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.

                                                Six Months Ended
                                                    June 30,
(In thousands)                                  2014        2013
Cash flows provided by operating activities   $ 584,948   $ 489,967
Cash flows used in investing activities        (612,504 )  (527,400 )
Cash flows provided by financing activities      49,766      53,974
Net increase in cash and cash equivalents     $  22,210   $  16,541

Operating Activities. Net cash provided by operating activities in the first six months of 2014 increased by $95.0 million over the first six months of 2013. This increase was primarily due to higher operating revenues partially offset by higher operating expenses (excluding non-cash expenses) and a decrease in working capital and other assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production, partially offset by the decrease in realized natural gas and crude oil prices. Equivalent production volumes increased by 34% for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 primarily as a result of higher natural gas production. Average realized natural gas prices decreased by 5% and average realized crude oil prices decreased by 4% for the first six months of 2014 compared to the first six months of 2013.

See "Results of Operations" for additional information relative to commodity price, production and operating expense fluctuations. 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 $85.1 million for the first six months of 2014 compared to the first six months of 2013. The increase was due to $93.6 million of higher capital expenditures and an increase of $18.0 million in capital contributions associated with our equity method investments. Partially offsetting the increases was a $28.1 million decrease in restricted cash related to the release of funds by our qualified intermediary due to a lapse in the statutory holding period and funding of oil and gas lease acquisitions during the first six months of 2014 associated with like-kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code.

Financing Activities. Cash flows provided by financing activities decreased by $4.2 million for the first six months of 2014 compared to the first six months of 2013. This decrease was primarily due to $9.0 million of lower net borrowings and an $8.3 million increase in dividend payments, partially offset by an increase of $13.0 million in tax benefits associated with our stock-based compensation.

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 agreement. The commitments under the revolving credit facility remain unchanged at $1.4 billion. At June 30, 2014, we had $506.0 million of borrowings outstanding under our revolving credit facility at a weighted-average interest rate of 1.9% and $893.0 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:



                             June 30,      December 31,
(Dollars in thousands)         2014            2013
Debt (1)                    $ 1,193,000   $    1,147,000
Stockholders' equity          2,401,939        2,204,602
Total capitalization        $ 3,594,939   $    3,351,602

Debt to capitalization              33%              34%

Cash and cash equivalents   $    45,610   $       23,400



(1) Includes $506.0 million and $460.0 million of borrowings outstanding under our revolving credit facility at June 30, 2014 and December 31, 2013, respectively.

During the six months ended June 30, 2014, we paid dividends of $16.7 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 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:

                            Six Months Ended
                                June 30,
(In thousands)              2014        2013
Capital expenditures
Drilling and facilities   $ 547,980   $ 501,331
Leasehold acquisitions       26,584      39,047
Pipeline and gathering          227         263
Other                         8,043       4,879
                            582,834     545,520
Exploration expense          11,150       8,553
Total                     $ 593,984   $ 554,073

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 between $1.375 billion and $1.475 billion in total capital and exploration expenditures (excluding expected contributions to our equity method investments of approximately $38.9 million). 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.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect the adoption of this guidance to have a material impact on our financial position or results of operations.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal year 2017 and can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect that adopting this guidance will have on our financial position, results of operations or cash flows.

Accounting for Derivative Instruments and Hedging Activities

Effective April 1, 2014, we elected to discontinue hedge accounting for our commodity derivatives on a prospective basis. Through March 31, 2014, we elected to designate our commodity derivatives as cash flow hedges for accounting purposes. Accordingly, the change in the fair value of derivatives designated as hedges that were effective was recorded to accumulated other comprehensive income (loss) in stockholders' equity in the Condensed Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges and the change in fair value and realized cash settlements of derivatives not designated as hedges are recorded as a component of operating revenues in gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

Results of Operations

Second Quarters of 2014 and 2013 Compared

We reported net income in the second quarter of 2014 of $118.4 million, or $0.28 per share, compared to $89.1 million, or $0.21 per share, in the second quarter of 2013. The increase in net income was due to an increase in operating revenues, partially offset by higher operating expenses and income taxes.

Revenue, Price and Volume Variances



Our revenues vary from year to year as a result of changes in realized commodity
prices and production volumes. Below is a discussion of revenue, price and
volume variances.



                                            Three Months Ended June 30,               Variance
Revenue Variances (In thousands)              2014               2013            Amount       Percent
Natural gas                              $       437,761    $       368,391    $   69,370          19%
Crude oil and condensate                          86,341             70,226        16,115          23%
Gain (loss) on derivative instruments             (2,329 )                -        (2,329 )      (100% )
Brokered natural gas                               8,140              8,244          (104 )        (1% )
Other                                              3,274              2,819           455          16%
                                         $       533,187    $       449,680    $   83,507          19%


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                                                                                                    Increase
                                     Three Months Ended June 30,             Variance              (Decrease)
                                       2014              2013           Amount      Percent      (In thousands)
Price Variances
Natural gas (1)                    $        3.59    $          4.06    $   (0.47 )      (12% )  $        (57,463 )
Crude oil and condensate (2)       $       99.36    $        101.39    $   (2.03 )       (2% )            (1,770 )
Total                                                                                           $        (59,233 )
Volume Variances
Natural gas (Bcf)                          121.8               90.7         31.1         34%    $        126,833
Crude oil and condensate (Mbbl)              869                693          176         25%              17,885
Total                                                                                           $        144,718



(1) These prices include the realized impact of derivative instrument settlements, which decreased the price by $0.18 per Mcf in 2014. 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 decreased the price by $0.73 per Bbl in 2014 and increased the price by $3.02 per Bbl in 2013.

Natural Gas Revenues

The increase in natural gas revenues of $69.4 million is due to higher production, partially offset by lower realized natural gas prices. The increase in production was a result of our Marcellus Shale drilling program, partially offset by a decrease in production in Oklahoma and west Texas as a result of certain non-core asset dispositions in the fourth quarter of 2013 and lower production in Texas and West Virginia due to normal production declines.

Crude Oil and Condensate Revenues

The increase in crude oil and condensate revenues of $16.1 million is due to higher production associated with our oil-focused drilling program in south Texas, partially offset by lower production associated with certain non-core asset dispositions in Oklahoma in the fourth quarter of 2013 and lower realized crude oil prices.

Gain (Loss) on Derivative Instruments

Effective April 1, 2014, we elected to discontinue hedge accounting on a prospective basis. Subsequent to April 1, 2014, our derivative instruments were accounted for on a mark-to-market basis with changes in fair value recognized currently in operating revenues in the Condensed Consolidated Statement of Operations. Gain (loss) on derivative instruments includes a $15.3 million loss related to the change in fair value of realized cash settlements of derivative instruments previously frozen in accumulated other comprehensive income (loss) and a $12.9 million unrealized mark-to-market gain on our commodity derivative instruments.

Impact of Derivative Instruments on Operating Revenues



The following table reflects the realized and unrealized impact of our
derivative instruments:



                                          Three Months Ended
                                               June 30,
(In thousands)                              2014        2013
Realized
Natural gas                             $    (22,320 ) $  (272 )
Crude oil and condensate                        (636 )   2,094
Gain (loss) on derivative instruments        (15,262 )       -
                                        $    (38,218 ) $ 1,822
Unrealized
Gain (loss) on derivative instruments         12,933         -
                                        $    (25,285 ) $ 1,822


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Brokered Natural Gas Revenue and Cost



                                                                                        Price and
                                  Three Months Ended                                      Volume
                                       June 30,                   Variance              Variances
                                  2014          2013         Amount      Percent      (In thousands)
Brokered Natural Gas Sales
Sales price ($/Mcf)            $     4.96    $     4.81    $     0.15          3%    $            242
Volume brokered (Mmcf)         x    1,642    x    1,714           (72 )       (4% )              (346 )
Brokered natural gas (In
thousands)                     $    8,140    $    8,244                              $           (104 )

Brokered Natural Gas
Purchases
Purchase price ($/Mcf)         $     4.28    $     3.91    $     0.37          9%    $           (609 )

Volume brokered (Mmcf) x 1,642 x 1,714 (72 ) (4% ) 282 Brokered natural gas (In
thousands) $ 7,031 $ 6,704 $ (327 )

Brokered natural gas margin
(In thousands) $ 1,109 $ 1,540 $ (431 )

The $0.4 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.

Operating and Other Expenses



                                       Three Months Ended June 30,               Variance
(In thousands)                           2014               2013            Amount       Percent
Operating and Other Expenses
Direct operations                   $        35,605    $        36,978    $   (1,373 )        (4% )
Transportation and gathering                 83,976             52,648        31,328          60%
Brokered natural gas                          7,031              6,704           327           5%
Taxes other than income                      12,816             11,364         1,452          13%
Exploration                                   4,676              4,529           147           3%
Depreciation, depletion and
amortization                                157,563            151,389         6,174           4%
General and administrative                   20,127             21,608        (1,481 )        (7% )
Total operating expense             $       321,794    $       285,220    $   36,574          13%

(Earnings) loss on equity method
investments                         $          (756 )  $          (290 )  $      466         161%
(Gain) loss on sale of assets                 1,496               (276 )      (1,772 )      (642% )
Interest expense                             16,334             16,991          (657 )        (4% )
Income tax expense                           75,899             58,921        16,978          29%

Total costs and expenses from operations increased by $36.6 million, or 13%, in the second quarter of 2014 compared to the same period of 2013. The primary reasons for this fluctuation are as follows:

Direct operations decreased $1.4 million largely due to lower costs associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013. Partially offsetting these decreases were higher operating costs as a result of higher production and an increase in costs associated with oil processing and related fuel charges as a result of more stringent oil pipeline quality requirements in south Texas.

Transportation and gathering increased $31.3 million due to higher throughput as a result of higher production, slightly higher transportation rates and the commencement of various transportation and gathering agreements in late 2013 and during the first half of 2014.

Brokered natural gas increased $0.3 million. See the preceding table titled "Brokered Natural Gas Revenue and Cost" for further analysis.

Taxes other than income increased $1.5 million due to $1.2 million higher production taxes and $0.6 million higher drilling impact fees associated with our Marcellus Shale drilling activities. Production taxes increased due to higher oil


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production in south Texas, partially offset by lower taxes associated with certain non-core assets in Oklahoma and west Texas that were sold in the fourth quarter of 2013.

Depreciation, depletion and amortization increased $6.2 million, of which $48.6 million was due to higher equivalent production volumes, offset by $38.5 million due to a lower DD&A rate of $1.20 per Mcfe for the second quarter of 2014 compared to $1.50 per Mcfe for the second quarter of 2013. The lower DD&A rate was primarily due to lower costs of reserve additions associated with our Marcellus drilling program and the impact of the disposition of higher rate . . .

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