Exhibit 99.1
PRESS RELEASE
| CONTACT: | Mark Brewer | Danny Gibbons | ||||
| Investor Relations | SVP & CFO | |||||
| FOR IMMEDIATE RELEASE | investorrelations@wtoffshore.com | investorrelations@wtoffshore.com | ||||
| 713-297-8024 | 713-624-7326 |
W&T OFFSHORE REPORTS FOURTH QUARTER AND FULL-YEAR 2012 FINANCIAL RESULTS, OPERATIONS UPDATE AND YEAR END PROVED RESERVES
HOUSTON – February 26, 2013 – W&T Offshore, Inc. (NYSE: WTI) today announces financial and operational results for the fourth quarter and full year 2012, along with an operations update and year end proved reserves. Some of the highlights include:
| • | Increase in proved reserves in 2012 over 2011. Proved reserves as of December 31, 2012 were 117.5 million barrels of oil equivalent (“MMBoe”), or 705.1 billion cubic feet equivalent (“Bcfe”) of natural gas, with 47% crude oil, 13% natural gas liquids (“NGLs”), and 40% natural gas. Converted 50% of 2011 proved undeveloped reserves to proved developed. Proved developed crude oil reserves increased 51% over the prior year. |
| • | PV-10 value(1) of proved reserves at year end was $2.8 billion, with proved developed producing reserves accounting for approximately $1.7 billion. Year-end proved reserves do not include potential additions from pending results in the East Texas Star Prospect or the recent Big Bend discovery at Mississippi Canyon (“MC”) 698. |
| • | For the fourth quarter of 2012, production volumes averaged 49,007 Boe per day, or 294.0 MMcf of natural gas equivalent per day. Production volumes were split 37% oil, 12% NGLs and 51% natural gas. Average realized sales price was $100.31 per barrel for oil, $36.16 per barrel for NGLs and $3.58 per Mcf for natural gas. |
| • | Drilled four and completed three horizontal wells in the West Texas Permian Basin. Current production from the Yellow Rose field is 5,150 Boe per day gross, up over 100% from year ago levels. |
| • | Announced discovery at Mississippi Canyon block 698 Big Bend deepwater exploration well, which reached total depth in mid-November 2012 and logged over 150 feet of high quality oil pay in two Miocene reservoirs. |
| • | During the fourth quarter we completed 23 wells, including one well offshore in the Gulf of Mexico, two horizontal wells at our Star Prospect in East Texas, and 20 wells (three horizontal and 17 vertical) in the Permian Basin of West Texas. |
| • | Revenues for the fourth quarter were $237.1 million, with 2012 full year revenues of $874.5 million. |
| • | Net income and earnings per share for the fourth quarter and full year of 2012, excluding special items, were $19.7 million and $0.26 per share, and $88.4 million and $1.17 per share, respectively. |
W&T Offshore, Inc. • Nine Greenway Plaza, Suite 300 • Houston, Texas 77046 • 713-626-8525 • www.wtoffshore.com
| • | Adjusted EBITDA for the fourth quarter was $151.2 million and our adjusted EBITDA margin was 64%. For the full year, adjusted EBITDA was $542.3 million and the adjusted EBITDA margin was 62%. Net cash provided by operating activities for 2012 was $385.1 million. Capital expenditures and other investing activities for 2012 were $657.4 million, and we distributed $82.8 million in dividends on our common stock for the year. Dividends included our normal dividend of $0.08 per share per quarter and two special dividends. |
Tracy W. Krohn, W&T Offshore’s Chairman and Chief Executive Officer, stated, “In 2012 we successfully executed our capital plan, which was heavily weighted towards development and complemented with exploration projects to drive organic growth in 2013. We converted 50% of our 2011 proved undeveloped reserves to a proved developed status and increased our proved developed crude oil reserves by 51% in 2012. This allowed us to continue to take advantage of the on-going strength in oil prices and the premium we receive for our Gulf Coast production. Additionally, our high value reserves provide a cushion from potential ceiling test impairment issues.
“Our success at our Yellow Rose project in West Texas contributed to the addition of proved oil reserves in 2012. As we recently announced, due to the favorable initial results of our horizontal exploration wells, which tested the Wolfcamp formation, and the success of our down-spacing program to 40 acres on our vertical Wolfberry wells, we added significant proved oil reserves. We are proceeding with an active drilling and development program and have seven horizontal Wolfcamp wells and 20 vertical wells currently planned for 2013. We believe that our Yellow Rose project has the potential for a significant number of additional horizontal locations to develop crude oil from the Wolfcamp formation and possibly other formations beyond 2013.
“Some of our other 2012 exploration activities were executed in the latter part of the year with encouraging results. Our Star Prospect in East Texas is progressing well and we had encouraging results there from our fourth horizontal well. We are moving forward with plans to drill one or more additional exploration wells in our Star Prospect in 2013. No reserves were booked at year end 2012 for our Star Prospect. In 2013, our capital budget will be heavily focused on exploration activities both onshore and offshore to drive organic growth, which in turn will allow us to accentuate these activities with acquisitions. This provides greater flexibility in our growth strategy and will make us less reliant on acquisitions for expansion.
“Our acquisition activity in 2012 was extremely active in regards to the opportunities that we examined, but resulted in only one acquisition as we maintained the discipline to adhere to our acquisition criteria. However, that acquisition included 65 deepwater blocks that hold enormous upside with future drilling and joint venture opportunities. While we will continue to actively look for strategic acquisition opportunities that have upside, we have developed an inventory of exploration and development projects to provide solid reserve and production growth potential through the drill bit.
“Our $450 million capital budget for 2013, provides for organic growth and directs 63% of our capital to exploration drilling in 2013. Our enhanced exploration team working alongside our development group has created a portfolio of projects that are designed to better balance our high cash flow in our offshore projects with onshore reserves that have a longer reserve life and allow for reserves to be booked more quickly. We are pleased with the progress we are making to expand our operations onshore and to diversify our growth opportunities, and we believe that 2013 will be another solid year for W&T,” concluded Mr. Krohn.
2
Production, Revenues and Price: Production volumes for 2012 were higher than 2011, but came in lower than initial expectations due to tropical storm activity, significant third-party pipeline outages during the third and fourth quarter of 2012, as well as the sanding up of the MC 243 A-2 well shortly after Hurricane Isaac.
Revenues for the fourth quarter of 2012 were $237.1 million compared to $261.9 million in the fourth quarter of 2011. During the fourth quarter of 2012, we sold 1.7 million barrels of oil, 0.5 million barrels of NGLs and 13.7 Bcf of natural gas as compared to 1.6 million barrels of oil, 0.6 million barrels of NGLs and 14.4 Bcf of natural gas for the same period of 2011. In total, we sold 4.5 million Boe at an unhedged average realized sales price of $52.51 per Boe compared to 4.6 million Boe sold at an unhedged average realized sales price of $57.12 per Boe in the fourth quarter of 2011.
For the full year 2012, revenues were $874.5 million compared to $971.0 million for 2011. Revenues were lower in 2012 compared to 2011 solely as a result of lower commodity prices, slightly offset by a rise in production volumes. We sold 6.0 million barrels of oil, 2.1 million barrels of NGLs, and 53.8 Bcf of natural gas for the full year 2012 as compared to 6.1 million barrels of oil, 1.9 million barrels of NGLs, and 53.7 Bcf of natural gas for the full year 2011. Total sales for 2012 were 17.1 million Boe and our unhedged average realized sales price was $50.93 per Boe. Total sales for 2011 were 16.9 million Boe and our unhedged average realized sales price was $57.32 per Boe.
Net Income & EPS: Our operating results for the fourth quarter of 2012 resulted in net income of $16.7 million, or $0.21 per common share, compared to net income of $46.1 million, or $0.61 per common share for the same period in 2011. Net income for the fourth quarter of 2012, excluding special items, was $19.7 million, or $0.26 per common share. This compares to $50.1 million, or $0.67 per common share, reported for the fourth quarter of 2011, excluding special items. See the “Reconciliation of Net Income to Net Income Excluding Special Items” and related earnings per share, excluding special items in the table under “Non-GAAP Financial Information” at the back of this press release for a description of the special items.
Cash Flow from Operating Activities and Adjusted EBITDA: EBITDA and Adjusted EBITDA are non-GAAP measures and are defined in the “Non-GAAP Financial Measures” section “ at the back of this press release. Adjusted EBITDA for the full year 2012 was $542.3 million, compared to $646.5 million for 2011. Our Adjusted EBITDA margin was 62% for 2012 compared to 67% in 2011. Adjusted EBITDA and Adjusted EBITDA margin were lower in 2012 primarily due to lower average realized sales prices. Net cash provided by operating activities for 2012 was $385.1 million compared to $521.5 million for the same period of the prior year.
3
Lease Operating Expenses (“LOE”): For the fourth quarter of 2012, LOE, which includes base lease operating expenses, insurance, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was $61.9 million compared to $59.3 million in the fourth quarter of 2011. Base LOE increased $1.5 million in the quarter due to the acquisition of the properties from Newfield and the expanding well count at our Yellow Rose field, partially offset by higher processing fees received offshore and decreased transition service fees for an acquisition completed in 2011. Workover expenses were up $2.7 million due to a greater number of workovers (as a result of a greater number of wells) at our Yellow Rose field while facilities expenses were lower by $2.6 million as the 2011 period included transition service costs incurred on our Fairway field. Hurricane repairs were up $1.0 million for costs related to Hurricane Isaac.
For the full year 2012, LOE was $232.3 million compared to $219.2 million for 2011. Base lease operating expense rose by $10.3 million, workovers were up $6.8 million, facilities expenses were down $4.9 million, and hurricane repair expenses were up $0.9 million all when compared to 2011 full year numbers. The increase in base lease operating expense was primarily attributable to new properties acquired during 2011 and 2012. Increases in workovers were driven mainly by onshore operations reflecting a full year of operations in 2012 (and more wells in the field) versus a partial year in 2011. Facilities expense was lower due to 2011 reflecting work on several offshore facilities that did not reoccur in 2012.
Depreciation, depletion, amortization and accretion (“DD&A”): DD&A for the fourth quarter of 2012 was $104.3 million as compared to $86.9 million for the fourth quarter of 2011. For the full year 2012, DD&A was $356.2 million, up $27.4 million over full year 2011. The increase in DD&A was due in part to costs capitalized to the full cost pool from both the unevaluated pool and from increases in our ARO estimates. In addition, we incurred significant development capital expenditures throughout the year that converted proved undeveloped reserves into proved developed producing reserves, but did not lead to an overall increase in proved reserves. Finally, most of our reserve additions for 2012 occurred late in the year which impacts the quarterly nature of the DD&A calculation.
The Company has incurred $45.6 million and expects to incur an additional $5 million in costs related to removal of wreck associated with platforms damaged by Hurricane Ike in 2008. We believe that we have insurance coverage for such amounts and future reimbursements will serve to reduce our full cost pool, which will in turn reduce our DD&A rate and replenish our $50.6 million in cash expenditures.
Capital Expenditures Update: Our total capital expenditures for 2012 of $684.9 million, comprised of $479.3 million for oil and gas expenditures and $205.6 million for acquisitions. Capital expenditures exceeded our initial budget for 2012 as we were able to drill wells faster onshore than what we originally anticipated. Capital expenditures for oil and gas properties consisted of $137.1 million for exploration activities, $310.2 million for development activities, and $32.0 million for seismic, leasehold, and other costs. Acquisition costs were limited to the $205.6 million paid to acquire certain oil and gas leasehold interests from Newfield Exploration on October 5, 2012. The acquisition was composed of 78 federal offshore lease blocks in the Gulf of Mexico totaling approximately 432,700 gross acres. The acreage is
4
comprised of 65 blocks in the deepwater, six of which are producing, ten blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 61% natural gas, 36% oil and 3% NGLs, all of which were classified as proved developed. The acquisition was funded from cash on hand and our revolving bank credit facility.
In November 2012, the borrowing base for our revolving bank credit facility was increased to $725 million from the previous level of $575 million.
2013 Capital Expenditure Budget: In a news release on February 12, 2013, we announced our 2013 capital budget of $450 million and provided details of certain 2013 drilling projects. As reported, approximately 63% of the $450 million budget is expected to be for exploratory drilling to drive organic growth of both reserves and production, with the remaining 37% directed to oil-focused development activities. We anticipate allocating 63% of the 2013 budget to projects in the Gulf of Mexico, both on the shelf and in the deepwater, and 37% to projects onshore in Texas.
Operations Update:
Below is additional information supplementing the detailed operations update provided on February 12, 2013.
At our East Texas Star Project, our fourth horizontal well, McMahon A 28 #1H, was fracture stimulated and placed on flowback during late December. The results so far are encouraging and are in line with our expectations for the well. Prior to committing to a long term development plan, we are planning to drill at least one or more additional wells this year.
At our Yellow Rose Properties, current production is averaging approximately 4,840 Boe per day gross with a recent one day peak rate of 5,180 Boe per day. Approximately 80% of our Yellow Rose lease acreage is held by production. This is important as it will allow us to develop the field prudently and take advantage of the best opportunities in the field.
In Terry County we completed two horizontal wells including the State Travis Henson Unit #1H and the Holmes 23-4 Unit #1 H during the fourth quarter. Based on a review of all of our well results in Terry County and full cycle economics, we have decided not to pursue additional development of the area at this time.
Year-End 2012 Proved Reserves increased over 2011: Proved reserves as of December 31, 2012 were 117.5 MMBoe, or 705.1 Bcfe, with 47% crude oil, 13% NGLs, and 40% natural gas, compared to proved reserves at December 31, 2011 of 116.9 MMBoe or 701.1 Bcfe, with 44% crude oil, 15% NGLs, and 41% natural gas. The PV-10(1) value of proved reserves at year-end 2012 was $2.8 billion, excluding the effect of estimated asset retirement obligations (“ARO”), compared to the same PV-10 measure at year-end 2011 of $3.1 billion.
5
The PV-10 value of our proved developed reserves at the end of 2012 increased $462 million or 23% when compared to 2011. We replaced over 100% of our production in 2012, while proved developed oil reserves increased roughly 12 million barrels in 2012 versus 2011. In addition to the benefit of developing the previously booked PUDs, the Company has been able to classify more of its onshore acreage as held by production.
Our proved reserves are summarized below.
| As of December 31, 2012 | ||||||||||||||||||||||||||||
| Total Equivalent Reserves | ||||||||||||||||||||||||||||
| Classification of Proved Reserves | Oil (MMBbls) |
NGLs (MMBbls) |
Natural Gas (Bcf) |
Oil Equivalent (MMBoe) |
Natural Gas Equivalent (Bcfe) |
% of total reserves |
PV-10
(1) (Millions) |
|||||||||||||||||||||
| Proved developed producing |
24.7 | 8.9 | 173.9 | 62.6 | 375.4 | 53 | % | $ | 1,664 | |||||||||||||||||||
| Proved developed non-producing |
10.7 | 2.1 | 69.5 | 24.3 | 145.8 | 21 | % | 777 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Total proved developed |
35.3 | 11.0 | 243.4 | 86.9 | 521.2 | 74 | % | 2,441 | ||||||||||||||||||||
| Proved undeveloped |
19.5 | 4.2 | 41.6 | 30.6 | 183.9 | 26 | % | 379 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Total proved |
54.8 | 15.2 | 285.1 | 117.5 | 705.1 | 100 | % | $ | 2,820 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| 1) | In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2012 were determined to be economically producible under existing economic conditions, which requires the use of the unweighted arithmetic average of the first-day-of-the-month price for oil and gas for the period January 2012 through December 2012. Also note that the present value of our total proved reserves only, discounted at 10% (referred to as “PV-10”) is a non-GAAP financial measure. See “Non-GAAP Financial Measure” below. For 2012, proved reserves and PV-10 were calculated using average prices of $98.13 per Bbl for oil, $1.13 per gallon for natural gas liquids and $2.77 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials. The proved reserves and PV-10 for the 2011 period were calculated using average prices of $97.36 per Bbl for oil, $1.22 per gallon for natural gas liquids and $4.11 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials. |
Conference Call Information: W&T will hold a conference call to discuss our financial and operational results on Wednesday, February 27, 2013, at 10:00 a.m. Eastern Time. To participate, dial (480) 629-9835 a few minutes before the call begins. The call will also be broadcast live over the Internet from the Company’s website at www.wtoffshore.com. A replay of the conference call will be available approximately two hours after the end of the call until March 6, 2013, and may be accessed by calling (303) 590-3030 and using the pass code 4590116#.
About W&T Offshore
W&T Offshore, Inc. is 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 72 offshore fields in federal and state waters (69 producing and three fields capable of producing). W&T currently has under lease over 1.4 million gross acres including over 710,000 gross acres on the Gulf of Mexico Shelf, over 480,000 gross acres in the deepwater and over 221,000 gross acres onshore in Texas. A substantial majority of our daily production is derived from wells we operate offshore. For more information on W&T Offshore, please visit our website at www.wtoffshore.com.
6
Forward-Looking Statements
This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. No assurance can be given, however, that these events will occur. These statements are subject to risks and uncertainties that could cause actual results to differ materially including, among other things, market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, the success of our risk management activities, governmental regulations, uncertainties and other factors discussed in W&T Offshore’s Annual Report on Form 10-K for the year ended December 31, 2011 and subsequent Form 10-Q reports found at www.sec.gov or at our website at www.wtoffshore.com under the Investor Relations section.
7
W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Income
(Unaudited)
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In thousands, except per share data) | ||||||||||||||||
| Revenues |
$ | 237,146 | $ | 261,899 | $ | 874,491 | $ | 971,047 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating costs and expenses: |
||||||||||||||||
| Lease operating expenses |
61,910 | 59,305 | 232,260 | 219,206 | ||||||||||||
| Gathering, transportation costs and production taxes |
5,404 | 5,809 | 20,718 | 21,195 | ||||||||||||
| Depreciation, depletion, amortization and accretion |
104,338 | 86,869 | 356,232 | 328,786 | ||||||||||||
| General and administrative expenses |
19,224 | 20,061 | 82,017 | 74,296 | ||||||||||||
| Derivative (gain) loss |
(467 | ) | 8,919 | 13,954 | (1,896 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total costs and expenses |
190,409 | 180,963 | 705,181 | 641,587 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
46,737 | 80,936 | 169,310 | 329,460 | ||||||||||||
| Interest expense: |
||||||||||||||||
| Incurred |
19,859 | 15,480 | 63,268 | 52,393 | ||||||||||||
| Capitalized |
(3,375 | ) | (3,223 | ) | (13,274 | ) | (9,877 | ) | ||||||||
| Loss on extinguishment of debt |
— | — | — | 22,694 | ||||||||||||
| Other income |
5 | 62 | 215 | 84 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income before income tax expense |
30,258 | 68,741 | 119,531 | 264,334 | ||||||||||||
| Income tax expense |
13,588 | 22,676 | 47,547 | 91,517 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income |
$ | 16,670 | $ | 46,065 | $ | 71,984 | $ | 172,817 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Basic and diluted earnings per common share |
$ | 0.21 | $ | 0.61 | $ | 0.95 | $ | 2.29 | ||||||||
| Weighted average common shares outstanding |
74,470 | 74,079 | 74,354 | 74,033 | ||||||||||||
| Consolidated Cash Flow Information |
||||||||||||||||
| Net cash provided by operating activities |
$ | 33,648 | $ | 125,427 | $ | 385,137 | $ | 521,478 | ||||||||
| Capital expenditures and acquisitions |
372,491 | 99,222 | 684,863 | 719,026 | ||||||||||||
8
W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Operating Data
(Unaudited)
| Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| Net sales volumes: |
||||||||||||||||
| Oil (MBbls) |
1,672 | 1,578 | 6,033 | 6,073 | ||||||||||||
| NGL (MBbls) |
549 | 613 | 2,129 | 1,892 | ||||||||||||
| Oil and NGLs (MBbls) |
2,221 | 2,191 | 8,163 | 7,964 | ||||||||||||
| Natural gas (MMcf) |
13,728 | 14,359 | 53,825 | 53,743 | ||||||||||||
| Total oil and natural gas (MBoe) (1) |
4,509 | 4,584 | 17,133 | 16,921 | ||||||||||||
| Total oil and natural gas (MMcfe) (1) |
27,052 | 27,502 | 102,800 | 101,528 | ||||||||||||
| Average daily equivalent sales (MBoe/d) |
49.0 | 49.8 | 46.8 | 46.4 | ||||||||||||
| Average daily equivalent sales (MMcfe/d) |
294.0 | 298.9 | 280.9 | 278.2 | ||||||||||||
| Average realized sales prices (Unhedged): |
||||||||||||||||
| Oil ($/Bbl) |
$ | 100.31 | $ | 112.01 | $ | 104.35 | $ | 105.92 | ||||||||
| NGLs ($/Bbl) |
36.16 | 56.55 | 39.75 | 55.81 | ||||||||||||
| Oil and NGLs ($/Bbl) |
84.46 | 96.49 | 87.50 | 94.02 | ||||||||||||
| Natural gas ($/Mcf) |
3.58 | 3.51 | 2.94 | 4.12 | ||||||||||||
| Barrel of oil equivalent ($/Boe) |
52.51 | 57.12 | 50.93 | 57.32 | ||||||||||||
| Natural gas equivalent ($/Mcfe) |
8.75 | 9.52 | 8.49 | 9.55 | ||||||||||||
| Average realized sales prices (Hedged): (2) |
||||||||||||||||
| Oil ($/Bbl) |
$ | 99.89 | $ | 111.61 | $ | 103.08 | $ | 104.30 | ||||||||
| NGLs ($/Bbl) |
36.16 | 56.55 | 39.75 | 55.81 | ||||||||||||
| Oil and NGLs ($/Bbl) |
84.14 | 96.20 | 86.56 | 92.78 | ||||||||||||
| Natural gas ($/Mcf) |
3.58 | 3.51 | 2.94 | 4.12 | ||||||||||||
| Barrel of oil equivalent ($/Boe) |
52.36 | 56.98 | 50.48 | 56.74 | ||||||||||||
| Natural gas equivalent ($/Mcfe) |
8.73 | 9.50 | 8.41 | 9.46 | ||||||||||||
| Average per Boe ($/Boe): |
||||||||||||||||
| Lease operating expenses |
$ | 13.73 | $ | 12.94 | $ | 13.56 | $ | 12.95 | ||||||||
| Gathering and transportation costs and production taxes |
1.20 | 1.27 | 1.21 | 1.25 | ||||||||||||
| Depreciation, depletion, amortization and accretion |
23.14 | 18.95 | 20.79 | 19.43 | ||||||||||||
| General and administrative expenses |
4.26 | 4.38 | 4.79 | 4.39 | ||||||||||||
| Net cash provided by operating activities |
7.46 | 27.36 | 22.48 | 30.82 | ||||||||||||
| Adjusted EBITDA |
33.53 | 38.42 | 31.65 | 38.20 | ||||||||||||
| Average per Mcfe ($/Mcfe): |
||||||||||||||||
| Lease operating expenses |
$ | 2.29 | $ | 2.16 | $ | 2.26 | $ | 2.16 | ||||||||
| Gathering and transportation costs and production taxes |
0.20 | 0.21 | 0.20 | 0.21 | ||||||||||||
| Depreciation, depletion, amortization and accretion |
3.86 | 3.16 | 3.47 | 3.24 | ||||||||||||
| General and administrative expenses |
0.71 | 0.73 | 0.80 | 0.73 | ||||||||||||
| Net cash provided by operating activities |
1.24 | 4.56 | 3.75 | 5.14 | ||||||||||||
| Adjusted EBITDA |
5.59 | 6.40 | 5.28 | 6.37 | ||||||||||||
| (1) | Bcfe and MMBoe are determined using the 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. |
| (2) | Data for 2012 and 2011 includes the effects of our commodity derivative contracts that did not qualify for hedge accounting. |
9
W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(Unaudited)
| December 31, | December 31, | |||||||
| 2012 | 2011 | |||||||
| (In thousands, except share data) |
||||||||
| Assets | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 12,245 | $ | 4,512 | ||||
| Receivables: |
||||||||
| Oil and natural gas sales |
97,733 | 98,550 | ||||||
| Joint interest and other |
56,439 | 25,804 | ||||||
| Income taxes |
47,884 | — | ||||||
|
|
|
|
|
|||||
| Total receivables |
202,056 | 124,354 | ||||||
| Deferred income taxes |
267 | 2,007 | ||||||
| Prepaid expenses and other assets |
25,555 | 30,315 | ||||||
|
|
|
|
|
|||||
| Total current assets |
240,123 | 161,188 | ||||||
| Property and equipment – at cost: |
||||||||
| Oil and natural gas properties and equipment (full cost method, of which $123,503 at December 31, 2012 and $154,516 at December 31, 2011 were excluded from amortization) |
6,694,510 | 5,959,016 | ||||||
| Furniture, fixtures and other |
21,786 | 19,500 | ||||||
|
|
|
|
|
|||||
| Total property and equipment |
6,716,296 | 5,978,516 | ||||||
| Less accumulated depreciation, depletion and amortization |
4,655,841 | 4,320,410 | ||||||
|
|
|
|
|
|||||
| Net property and equipment |
2,060,455 | 1,658,106 | ||||||
| Restricted deposits for asset retirement obligations |
28,466 | 33,462 | ||||||
| Other assets |
19,943 | 16,169 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 2,348,987 | $ | 1,868,925 | ||||
|
|
|
|
|
|||||
| Liabilities and Shareholders’ Equity | ||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 123,885 | $ | 75,871 | ||||
| Undistributed oil and natural gas proceeds |
37,073 | 33,732 | ||||||
| Asset retirement obligations |
92,630 | 138,185 | ||||||
| Accrued liabilities |
20,755 | 29,705 | ||||||
| Income taxes |
266 | 10,392 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
274,609 | 287,885 | ||||||
| Long-term debt |
1,087,611 | 717,000 | ||||||
| Asset retirement obligations, less current portion |
291,423 | 255,695 | ||||||
| Deferred income taxes |
145,249 | 58,881 | ||||||
| Other liabilities |
8,908 | 4,890 | ||||||
| Commitments and contingencies |
— | — | ||||||
| Shareholders’ equity: |
||||||||
| Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,118,803 issued and 75,249,630 outstanding at December 31, 2012; 77,220,706 issued and 74,351,533 outstanding at December 31, 2011 |
1 | 1 | ||||||
| Additional paid-in capital |
396,186 | 386,920 | ||||||
| Retained earnings |
169,167 | 181,820 | ||||||
| Treasury stock, at cost |
(24,167 | ) | (24,167 | ) | ||||
|
|
|
|
|
|||||
| Total shareholders’ equity |
541,187 | 544,574 | ||||||
|
|
|
|
|
|||||
| Total liabilities and shareholders’ equity |
$ | 2,348,987 | $ | 1,868,925 | ||||
|
|
|
|
|
|||||
10
W&T OFFSHORE, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(Unaudited)
| Twelve Months Ended December 31, |
||||||||
| 2012 | 2011 | |||||||
| (In thousands) | ||||||||
| Operating activities: |
||||||||
| Net income |
$ | 71,984 | $ | 172,817 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation, depletion, amortization and accretion |
356,232 | 328,786 | ||||||
| Amortization of debt issuance costs |
2,575 | 2,010 | ||||||
| Loss on extinguishment of debt |
— | 22,694 | ||||||
| Share-based compensation |
12,398 | 9,710 | ||||||
| Derivative (gain) loss |
13,954 | (1,896 | ) | |||||
| Cash payments on derivative settlements |
(7,664 | ) | (9,873 | ) | ||||
| Deferred income taxes |
88,109 | 61,835 | ||||||
| Asset retirement obligation settlements |
(112,827 | ) | (59,958 | ) | ||||
| Changes in operating assets and liabilities |
(39,624 | ) | (4,647 | ) | ||||
|
|
|
|
|
|||||
| Net cash provided by operating activities |
385,137 | 521,478 | ||||||
|
|
|
|
|
|||||
| Investing activities: |
||||||||
| Acquisitions of property interests in oil and natural gas properties |
(205,550 | ) | (437,247 | ) | ||||
| Investment in oil and natural gas properties and equipment |
(479,313 | ) | (281,779 | ) | ||||
| Proceeds from sales of oil and natural gas properties and equipment |
30,453 | 15 | ||||||
| Purchases of furniture, fixtures and other |
(3,031 | ) | (3,660 | ) | ||||
|
|
|
|
|
|||||
| Net cash used in investing activities |
(657,441 | ) | (722,671 | ) | ||||
|
|
|
|
|
|||||
| Financing activities: |
||||||||
| Issuance of Senior Notes |
318,000 | 600,000 | ||||||
| Repurchase of Senior Notes |
— | (450,000 | ) | |||||
| Borrowings of long-term debt |
732,000 | 623,000 | ||||||
| Repayments of long-term debt |
(679,000 | ) | (506,000 | ) | ||||
| Dividends to shareholders |
(82,832 | ) | (58,756 | ) | ||||
| Repurchase premium and debt issuance costs |
(8,510 | ) | (32,288 | ) | ||||
| Other |
379 | 1,094 | ||||||
|
|
|
|
|
|||||
| Net cash provided by financing activities |
280,037 | 177,050 | ||||||
|
|
|
|
|
|||||
| Increase (decrease) in cash and cash equivalents |
7,733 | (24,143 | ) | |||||
| Cash and cash equivalents, beginning of period |
4,512 | 28,655 | ||||||
|
|
|
|
|
|||||
| Cash and cash equivalents, end of period |
$ | 12,245 | $ | 4,512 | ||||
|
|
|
|
|
|||||
11
W&T OFFSHORE, INC. AND SUBSIDIARIES
Non-GAAP Information
Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures are “Net Income Excluding Special Items,” “EBITDA” and “Adjusted EBITDA.” Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues. Our management uses these non-GAAP financial measures in its analysis of our performance. These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP performance measures which may be reported by other companies.
Reconciliation of Net Income to Net Income Excluding Special Items
“Net Income Excluding Special Items” does not include the unrealized derivative (gain) loss, litigation accruals, loss on extinguishment of debt, and associated tax effects. Net Income excluding special items is presented because the timing and amount of these items cannot be reasonably estimated and affect the comparability of operating results from period to period, and current periods to prior periods.
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2012 | 2011 | 2012 | 2011 | |||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||
| (Unaudited) | ||||||||||||||||
| Net income |
$ | 16,670 | $ | 46,065 | $ | 71,984 | $ | 172,817 | ||||||||
| Unrealized commodity derivative (gain) loss |
(1,172 | ) | 8,284 | 6,289 | (11,770 | ) | ||||||||||
| Loss on extinguishment of debt |
— | — | — | 22,694 | ||||||||||||
| Litigation accruals |
1,250 | — | 10,250 | — | ||||||||||||
| Income tax adjustment to statutory rate |
2,971 | (4,283 | ) | (78 | ) | (4,823 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income excluding special items |
$ | 19,719 | $ | 50,066 | $ | 88,445 | $ | 178,918 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Basic and diluted earnings per common share, excluding special items |
$ | 0.26 | $ | 0.67 | $ | 1.17 | $ | 2.37 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
12
Reconciliation of Net Income to Adjusted EBITDA
We define EBITDA as net income plus income tax expense, net interest expense, depreciation, depletion, amortization, and accretion. Adjusted EBITDA excludes the unrealized gain or loss related to our derivative contracts, loss on extinguishment of debt, and litigation accruals. We believe the presentation of EBITDA and Adjusted EBITDA provide useful information regarding our ability to service debt and to fund capital expenditures and help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures. We believe this presentation is relevant and useful because it helps our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures. EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity. EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to EBITDA and Adjusted EBITDA measures reported by other companies. In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use.
The following table presents a reconciliation of our consolidated net income to consolidated EBITDA and Adjusted EBITDA.
| Three Months Ended | Twelve Months Ended | |||||||||||||||
| December 31, | December 31, | |||||||||||||||
| 2012 |
2011 | 2012 | 2011 | |||||||||||||
| (In thousands) | ||||||||||||||||
| (Unaudited) | ||||||||||||||||
| Net income |
$ | 16,670 | $ | 46,065 | $ | 71,984 | $ | 172,817 | ||||||||
| Income tax expense |
13,588 | 22,676 | 47,547 | 91,517 | ||||||||||||
| Net interest expense |
16,479 | 12,195 | 49,979 | 42,432 | ||||||||||||
| Depreciation, depletion, amortization and accretion |
104,338 | 86,869 | 356,232 | 328,786 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| EBITDA |
151,075 | 167,805 | 525,742 | 635,552 | ||||||||||||
| Adjustments: |
||||||||||||||||
| Unrealized commodity derivative (gain) loss |
(1,172 | ) | 8,284 | 6,289 | (11,770 | ) | ||||||||||
| Loss on extinguishment of debt |
— | — | — | 22,694 | ||||||||||||
| Litigation accruals |
1,250 | — | 10,250 | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted EBITDA |
$ | 151,153 | $ | 176,089 | $ | 542,281 | $ | 646,476 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Adjusted EBITDA Margin |
64 | % | 67 | % | 62 | % | 67 | % | ||||||||
13