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WTI > SEC Filings for WTI > Form 10-Q on 8-Nov-2013All Recent SEC Filings

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Form 10-Q for W&T OFFSHORE INC


8-Nov-2013

Quarterly Report


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

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 ("the "Exchange Act"),which involve risks, uncertainties and assumptions.
If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A "Risk Factors" and market risks are discussed in Item 7A "Quantitative and Qualitative Disclosures About Market Risk" of our Annual Report on Form 10-K for the year ended December 31, 2012 and may be discussed or updated from time to time in subsequent reports filed with the SEC. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.
We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to "W&T," "we," "us," "our" and the "Company" refer to W&T Offshore, Inc. and its consolidated subsidiaries.

Overview

We are an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and onshore in both the Permian Basin of West Texas and in East Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 67 producing offshore fields in federal and state waters (60 producing and seven fields capable of producing). We currently have under lease approximately 1.3 million gross acres, including approximately 0.6 million gross acres on the Gulf of Mexico Shelf, approximately 0.5 million gross acres in the deepwater and approximately 0.2 million gross acres onshore in Texas. A substantial majority of our daily production is derived from wells we operate offshore. In managing our business, we are concerned primarily with maximizing return on shareholders' equity. To accomplish this primary goal, we focus on profitably increasing production and finding oil and gas reserves at a favorable cost. We strive to grow our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for the nine months ended September 30, 2013 were comprised of approximately 40.7% oil and condensate, 11.9% NGLs and 47.4% natural gas, determined using the energy equivalency ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent ("Mcfe") for oil, NGLs and natural gas may differ significantly. In the nine months ended September 30, 2013, revenues from the sale of oil and NGLs made up 81.3% of our total revenues compared to 82.6% in the same period of 2012 with the decrease attributable to higher natural gas prices during the 2013 period.
For the nine months ended September 30, 2013, our combined total production of oil, condensate, NGLs and natural gas was approximately 1.6% higher on a Mcfe basis than during the same period in 2012, and our total revenues were 16.0% higher in the nine months ended September 30, 2013, driven primarily by higher oil production and higher natural gas prices. See section Results of Operations-Nine months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012 for additional information on our revenues and production.

In October 2012, we acquired from Newfield certain oil and gas leasehold interests in the Gulf of Mexico. The operating results of the Newfield Properties are included in our results of operations and income statement for the period ended September 30, 2013. The results for the period ended September 30, 2012 do not include the Newfield Properties' operations as this period precedes the acquisition date.

During the nine months ended September 30, 2013, our average realized oil sales price continued at historically high levels, but were slightly lower than those realized in the same period of 2012. Two comparable oil price benchmarks are the unweighted average daily posted spot price of WTI crude oil, which increased 2.1% from the comparable period, and the unweighted average daily posted spot price of Brent crude oil, which decreased 3.4% from the comparable period. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from offshore Gulf


of Mexico, which is comprised of various crudes including Light Louisiana Sweet, Heavy Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through September 2013, these various crudes sold at a premium, and sometimes a significant premium, relative to WTI. During the nine months ended September 30, 2013, premiums for Light Louisiana Sweet crude and Heavy Louisiana Sweet crude ranged between $4.00 and $22.00 per barrel higher than WTI, with premiums from July 2013 to September 2013 being in the low end of the range at $4.00 to $9.00 per barrel as the price of WTI increased relative to Brent. During the nine months ended September 30, 2012, premiums for Light Louisiana Sweet crude and Heavy Louisiana Sweet crude ranged between $10.00 and $22.00 per barrel. The average premium spread prior to 2011 was approximately $2.00 to $3.00 per barrel. Our offshore oil production competes with foreign-sourced crude oil, which is priced primarily based on the spot price of Brent.

The infrastructure to move crude oil within the United States has seen a major change over the past few years. A number of pipelines have been built and completed, reversed flowed, or expanded to move crude oil from Cushing, Oklahoma (a major crude oil storage hub). Transportation capacity has also been added in major producing regions like the Permian Basin to move crude oil to the U.S. Gulf Coast rather than to Cushing. Both of these events have helped relieve the excess crude oil that built up in Cushing, which in turn allowed WTI pricing to increase relative to Brent. Not only is pipeline capacity increasing, but rail receiving capacity on the East Coast has expanded considerably and is expected to continue to increase. Rail receiving capacity on the Gulf Coast is also expanding, but not at the same rate as the East Coast, as mostly pipeline capacity is being added to serve that market. The expanded infrastructure to deliver crude oil to domestic refineries by pipelines and rail has put market pressure to contract the spread of Brent to WTI, as the price of Brent has decreased and the price of WTI has increased in 2013 as compared to 2012. The spread between Brent and WTI widened more recently due to crude oil inventory increases in the U.S. due to both increased imports and increased domestic production. Spreads are expected to remain volatile, but absolute levels could continue to be more narrow due to the reasons enumerated above.

Oil prices are affected by world events, such as political unrest in the Middle East, the threat of hostilities, demand changes in various countries and world economic growth. Thus, crude oil prices will likely continue to be volatile.
For the nine months ended September 30, 2013, WTI crude oil prices ranged from $87.00 to $111.00 per barrel and Brent crude oil prices ranged from $97.00 to $119.00 per barrel. The U.S. Energy Information Administration ("EIA") estimates that the average WTI crude spot price was $94.00 per barrel in 2012 and will be $99.00 per barrel in 2013 and $96.00 per barrel in 2014. EIA estimates the average Brent crude oil spot price was $112.00 per barrel in 2012 and projects the average price to be $108.00 per barrel and $102.00 per barrel in 2013 and 2014, respectively. EIA expects world-wide supply and consumption for oil and liquids fuels to be fairly equal for 2013 and 2014, resulting in minor inventory withdrawals or builds.

Our average realized NGLs sale prices decreased 18.8% during the nine months ended September 30, 2013 compared to the same period of 2012. According to industry sources, increased domestic NGLs production has been the primary factor affecting price realizations. During the nine months ended September 30, 2013, prices for domestic ethane and propane, two common NGL components, decreased 33% and 10%, respectively, from the comparable period in 2012 and other domestic NGLs prices decreased between 0% and 21%. As long as ethane and propane inventories continue to be high and NGLs production continues to be high, we would expect prices for NGLs to be weak. In addition, as long as the crude to natural gas price ratio remains wide (as measured on a six to one energy equivalency), the production of NGLs may continue to be high relative to historical norms and would, in turn, suggest downward price pressure on the price of ethane and to some extent propane. Many natural gas processing facilities are re-injecting ethane back into the natural gas stream after processing due to excess ethane supplies. This in turn has increased natural gas supplies and negatively impacted natural gas pricing.


Prices for natural gas in the U.S. have improved during the nine months ended September 30, 2013 compared to the prior period largely due to above-average storage withdrawals in response to the colder winter weather, lower net imports from Canada and higher industrial demand. Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During the nine months ended September 30, 2013, the average realized sales price for our natural gas production increased 37.5% from the comparable period in 2012 to $3.74 per Mcf. A comparable benchmark is the Henry Hub unweighted average daily posted spot price, which increased 45.3% from the comparable period. Although the price has increased significantly on a percentage basis, the price is still weak from an overall economic standpoint and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels building during the injection season,
(iii) natural gas continuing to be produced as a by-product in conjunction with the high level of oil drilling, (iv) increasing availability of liquefied natural gas, (v) production efficiency gains being achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling and production techniques and (vi) re-injecting ethane into the natural gas stream as indicated above, which increases the natural gas supply. Per EIA, natural gas working inventories at the end of the 2013 injection season (end of October 2013) is expected to be about 3% below the record high level of last year levels of 3,929 billion cubic feet. EIA expects the Henry Hub natural gas spot price, which averaged $2.75 per British thermal unit (MMBtu) in 2012, will average $3.68 per MMBtu in 2013 and $3.91 per MMBtu in 2014. EIA projects U.S. supply to be higher than consumption for both 2013 and 2014. According to Baker Hughes, the U.S. natural gas rig count decreased from 809 rigs at the beginning of 2012 to 437 by the end of September of 2012. The natural gas rig count continued to decline for the remainder of 2012 and started the year 2013 at 431 rigs. The rig count continued to decrease further and by the end of September 2013, the rig count had decreased to 378 rigs. Despite the decline in rigs drilling specifically for natural gas, the U.S. has experienced a year over year increase in natural gas production due to the many factors enumerated above. EIA projects the percentage of electricity fueled by natural gas to be 27.4% in 2013 compared to 30.4% in 2012, and to further decline to 26.7% in 2014 based on the relative expected price of natural gas compared to the expected price of coal. Industry sources have indicated that a natural gas price above $4.50 per Mcf will probably cause even more power producers to switch back to coal from natural gas, which in effect creates limits to how far natural gas prices can rise until such time as demand for natural gas increases from other sources.

Should prices decline for oil, NGLs and natural gas in the future, it would negatively impact our future oil, NGLs and natural gas revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, reductions in proved reserves, issues with financial ratio compliance, and a reduction of the borrowing base associated with our Credit Agreement, depending on the severity of such declines. If any of these events were to occur and were significant, it may limit the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry.

Many changes in laws, regulations, guidance, interpretations and policy continue to be proposed and issued in our industry. The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years. The most significant regulation changes in recent years are regulations related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. Also, the regulations have changed related to plugging and abandonment of offshore wells and related infrastructure considerably, driving up both the time and cost to perform the work. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time.


Results of Operations

The following tables set forth selected financial and operating data for the
periods indicated (all values are net to our interest unless indicated
otherwise):





                                                     Three Months Ended                                                 Nine Months Ended
                                                     September 30, (1)                                                  September 30, (1)
                                    2013             2012           Change            %              2013             2012            Change               %
                                                                      (In thousands, except percentages and per share data)
Financial:
Revenues:
Oil                              $  184,087       $  138,034       $  46,053           33.4 %     $  550,329       $  461,846       $   88,483           19.2 %
NGLs                                 16,505           12,468           4,037           32.4 %         50,631           64,793          (14,162 )        (21.9 )%
Natural gas                          43,588           35,054           8,534           24.3 %        136,520          109,174           27,346           25.0 %
Other                                   375              390             (15 )         (3.8 )%         1,680            1,532              148            9.7 %
Total revenues                      244,555          185,946          58,609           31.5 %        739,160          637,345          101,815           16.0 %
Operating costs and expenses:
Lease operating expenses             67,346           53,411          13,935           26.1 %        194,935          170,349           24,586           14.4 %
Production taxes                      1,807            1,353             454           33.6 %          5,375            4,174            1,201           28.8 %
Gathering and transportation          3,611            2,810             801           28.5 %         12,663           11,140            1,523           13.7 %
Depreciation, depletion,
amortization
and accretion                       104,143           77,462          26,681           34.4 %        312,911          251,894           61,017           24.2 %
General and administrative           20,024                            1,333            7.1 %         60,979                            (1,814 )         (2.9 )%
expenses                                              18,691                                                           62,793
Derivative loss                      15,659           24,659          (9,000 )        (36.5 )%         6,186           14,421           (8,235 )        (57.1 )%
Total costs and expenses            212,590          178,386          34,204           19.2 %        593,049          514,771           78,278           15.2 %
Operating income                     31,965            7,560          24,405          322.8 %        146,111          122,574           23,537           19.2 %
Interest expense, net of amounts
capitalized                          18,800           11,408           7,392           64.8 %         56,620           33,510           23,110           69.0 %
Other income                          9,062              202           8,860            N/A            9,075              210            8,865            N/A
Income (loss) before income tax
expense                              22,227           (3,646 )        25,873            N/A           98,566           89,274            9,292           10.4  %
Income tax expense (benefit)          8,033           (2,175 )        10,208            N/A           35,358           33,959            1,399            4.1 %
Net income (loss)                $   14,194       $   (1,471 )     $  15,665            N/A       $   63,208       $   55,315       $    7,893           14.3 %

Basic and diluted earnings
(loss) per
  common share                   $     0.19       $    (0.02 )     $    0.21            N/A       $     0.83       $     0.73       $     0.10           13.7 %

(1) In the fourth quarter of 2012, we acquired the Newfield Properties.

N/A = percentage change not applicable


                                                                 Three Months Ended                                               Nine Months Ended
                                                                 September 30, (1)                                                September 30, (1)
                                                2013             2012           Change            %              2013             2012           Change            %
Operating:
Net sales volumes:
Oil (MBbls)                                       1,725            1,371             354           25.8 %          5,226            4,361             865           19.8 %
NGLs (MBbls)                                        494              451              43            9.5 %          1,520            1,581             (61 )         (3.9 )%
Natural gas (MMcf)                               11,924           11,401             523            4.6 %         36,486           40,097          (3,611 )         (9.0 )%
Total natural gas and oil (MBoe) (2)              4,207            3,722             485           13.0 %         12,828           12,625             203            1.6 %
Total natural gas and oil (MMcfe) (2)            25,241           22,331           2,910           13.0 %         76,967           75,749           1,218            1.6 %

Average daily equivalent sales (Boe/d) (2)       45,727           40,454           5,273           13.0 %         46,989           46,076             913            2.0 %
Average daily equivalent sales (Mcfe/d) (2)     274,364          242,723          31,641           13.0 %        281,932          276,455           5,477            2.0 %

Average realized sales prices:
Oil ($/Bbl)                                  $   106.70       $   100.68       $    6.02            6.0 %     $   105.30       $   105.89       $   (0.59 )         (0.6 )%
NGLs ($/Bbl)                                      33.39            27.66            5.73           20.7 %          33.30            40.99           (7.69 )        (18.8 )%
Natural gas ($/Mcf)                                3.66             3.07            0.59           19.2 %           3.74             2.72            1.02           37.5 %
Oil equivalent ($/Boe) (2)                        58.04            49.86            8.18           16.4 %          57.49            50.36            7.13           14.2 %
Natural gas equivalent ($/Mcfe) (2)                9.67             8.31            1.36           16.4 %           9.58             8.39            1.19           14.2 %

Average per Mcfe ($/Mcfe) (2):
Lease operating expenses                     $     2.67       $     2.39       $    0.28           11.7 %     $     2.53       $     2.25       $    0.28           12.4 %
Gathering and transportation                       0.14             0.13            0.01            7.7 %           0.16             0.15            0.01            6.7 %
Production costs                                   2.81             2.52            0.29           11.5 %           2.69             2.40            0.29           12.1 %
Production taxes                                   0.07             0.06            0.01           16.7 %           0.07             0.06            0.01           16.7 %
Depreciation, depletion, amortization and
accretion                                          4.13             3.47            0.66           19.0 %           4.07             3.33            0.74           22.2 %
General and administrative expenses                0.79             0.84           (0.05 )         (6.0 )%          0.79             0.83           (0.04 )         (4.8 )%
                                             $     7.80       $     6.89       $    0.91           13.2 %     $     7.62       $     6.62       $    1.00           15.1 %

Total number of wells drilled (gross):
Offshore                                              3                1               2          200.0 %              6                3               3          100.0
Onshore                                              10               18              (8 )        (44.4 )%            33               55             (22 )        (40.0 )%

Total number of productive wells drilled
(gross):
Offshore                                              3                1               2          200.0 %              5                3               2           66.7 %
Onshore                                              10               18              (8 )        (44.4 )%            33               55             (22 )        (40.0 )%

(1) In the fourth quarter of 2012, we acquired the Newfield Properties.

(2) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

Volume measurements:
Boe-barrel of oil equivalent                MMcf - million cubic feet
                                            MMcfe - million cubic feet
Boe/d-barrel of oil equivalent per day      equivalent
MBbls-thousand barrels for crude oil,       Mcfe/d - thousand cubic feet
condensate or NGLs                          equivalent per day
MBoe-thousand barrels of oil equivalent

N/A = percentage change not applicable


Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

Revenues. Total revenues increased $58.6 million to $244.6 million for the third quarter of 2013 as compared to the same period in 2012. Oil revenues increased $46.1 million, NGLs revenues increased $4.0 million, natural gas revenues increased $8.5 million and other revenues were flat. The oil revenue increase was attributable to a 25.8% increase in sales volumes and a 6.0% increase in the average realized sales price to $106.70 per barrel for the third quarter of 2013 from $100.68 per barrel for the prior year period. The NGLs revenue increase was attributable to a 20.7% increase in the average realized sales price to $33.39 per barrel for the third quarter of 2013 from $27.66 per barrel for the prior year period and an increase of 9.5% in sales volumes from the comparable period. The increase in natural gas revenue resulted from a 19.2% increase in the average realized natural gas sales price to $3.66 per Mcf in the third quarter of 2013 from $3.07 per Mcf for the prior year period and a 4.6% increase in sales volumes from the comparable period. Production for all commodities was positively impacted by production at Ship Shoal 349, onshore properties in West Texas and the Newfield Properties acquired in 2012. Production was negatively impacted for all commodities from natural production declines and from production deferrals affecting various fields in the third quarter of 2013. The production deferrals were attributable to third-party pipeline outages, platform maintenance, and various operational issues. We estimate production deferrals were 4.7 Bcfe during the third quarter of 2013. Specifically, production at Mississippi Canyon 506 "Wrigley" continues to be deferred as a result of maintenance at Shell's Cognac platform and related pipelines. Also, production was deferred at our Fairway field due to well and maintenance issues and a turnaround at our Yellowhammer plant. During the third quarter of 2012, we experienced production deferrals primarily due to Hurricane Isaac and various pipeline outages.

Revenues from oil and liquids as a percent of our total revenues were 82.0% for the third quarter of 2013 compared to 80.9% for the prior year period. NGLs realized sales prices as a percent of oil realized prices increased to 31.3% for the third quarter of 2013 compared to 27.5% for the comparable period.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance premiums, workovers and maintenance on our facilities, increased $13.9 million to $67.3 million in the third quarter of . . .

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