W&T Offshore Reports Second Quarter 2014 Financial Results, Operations Update, An Increase In Its 2014 Capital Budget And 2014 Production And Expense Guidance
PR Newswire Association LLC |
- In
August 2014 , theU.S. Environmental Protection Agency ("EPA ") lifted the suspension and proposed debarment, and removed the statutory disqualification, previously imposed onW&T Offshore, Inc by theEPA . - Increasing the 2014 capital expenditure budget by
$185 million to$635 million which includes, among other things, three additional deepwater wells and acquisitions already completed. - Our wholly-owned subsidiary,
W & T Energy VI, LLC , completed the acquisition of exploration and production properties in the deepwater of theGulf of Mexico fromWoodside Energy (USA) Inc. , which included a 20% non-operated working interest in the producing Neptune Field (Atwater Valley blocks 574, 575 and 618 along with an interest in the associated tension leg platform) and all of its interest in 24 deepwater exploration blocks. - In
June 2014 , theU.S. Court of Appeals for the Fifth Circuit ruled in favor of W&T as we sought insurance recovery for our Removal of Wreck costs associated with damage resulting from Hurricane Ike. The underwriters subsequently requested a rehearing which was denied. The Company now expects to recover in excess of$46 million from the insurance underwriters. - In
May 2014 , we commenced drilling the Mississippi Canyon Block 782 "Dantzler" No. 2, a deepwater exploration well with the intent to identify additional field reserves beyond the significant discovery made by the Dantzler No. 1 well in 2013. We hold a 20% non-operated working interest inDantzler . - We drilled two additional horizontal wells testing the Wolfcamp "B" formation at our
Yellow Rose field in thePermian Basin of West Texas. Completion of those wells is underway. During the second quarter, we completed 11 vertical wells and one horizontal well. For the second quarter of 2014, production from the field averaged 4,379 Boe per day gross (3,375 Boe per day net to our interest). - At the end of the quarter, we were drilling two offshore shelf wells which were the A-16 at Ship Shoal 349 "Mahogany" and the A-2 ST at East Cameron 321. The EC 321 ST was successful and we are currently completing the well.
- Production for the second quarter of 2014 averaged 48,300 barrels of oil equivalent ("Boe") per day (54% oil and liquids), and our average realized sales price was
$99.92 per barrel for oil,$39.98 per barrel for natural gas liquids ("NGLs") and$4.62 per thousand cubic feet ("Mcf") for natural gas. - Revenues for the second quarter of 2014 were
$263.0 million compared to$235.4 million in the second quarter of 2013. Oil and NGLs made up 78% of second quarter revenues. - Net income for the second quarter of 2014, excluding special items, was
$18.3 million and earnings were$0.24 per share. This represents an increase of 30.5% and 33.3%, respectively, over the second quarter of 2013. - Adjusted EBITDA for the second quarter was
$175.7 million , up$34.8 million over the second quarter of 2013 and the Adjusted EBITDA margin for the second quarter increased to 67%, up from 60% in the second quarter of 2013. For the first six months of 2014, our Adjusted EBITDA was$343.7 million , an increase of$30.3 million over the first half of 2013. Our Adjusted EBITDA margin was 66% for the first six months of 2014 compared to 63% for the second quarter of 2013. - Paid regular quarterly dividend of
$0.10 per share during the second quarter.
Production, Revenues and Price: For the second quarter of 2014, total production volumes were up 1.6 billion cubic feet equivalent ("Bcfe") or 6.6% (273,000 Boe) compared to 2013 with oil, natural gas and NGLs volumes all up over 2013. Production increases and higher oil volumes came from increased production from several fields including Mahogany and Matterhorn and from acquisition activities that brought production from the deepwater Medusa field (acquired in the fourth quarter of 2013) into our portfolio. Production volumes were not as robust as they could have been as we continue to be impacted by production deferrals, which for the second quarter were estimated at 564,400 Boe or 3.39 billion cubic feet ("Bcf") equivalent. Our most significant production issues being the continued shut-in at the non-operated
Revenues for the second quarter of 2014 were
Adjusted EBITDA for the second quarter of 2014 was
At
In
Lease Operating Expenses ("LOE"): LOE, which includes base LOE, insurance premiums, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was
Depreciation, depletion, amortization and accretion ("DD&A"): DD&A, including accretion for asset retirement obligation, was
General and Administrative Expenses ("G&A"): G&A was
Derivatives: For the second quarter of 2014 our net derivative loss was
Income Taxes: Income tax expense was
Net Income & EPS: Net income for the second quarter of 2014 was
Capital Expenditures Update: Our capital expenditures for the second quarter of 2014 were
We have increased our capital expenditure budget for 2014 to
OPERATIONS UPDATE
Offshore
The Neptune field is in the
The Dantzler No.1 well was a major discovery in 2013 and a second well, the Dantzler No. 2, has commenced drilling with the intent to identify additional field reserves and prove up additional productive acreage beyond what was identified in last year's highly successful No. 1 well. Production from the
The A-5 well was drilled in the eastern portion of the Matterhorn field and brought on line in the first quarter this year producing over 1,200 Boe per day. The well was drilled as a water injection well but discovered over 200 feet of net vertical oil pay and was brought on line as an oil producer. We will be converting the well to its original intended purpose in the third quarter, which will serve to increase pressure in the reservoir and ultimately increase the reserve life and overall production from the field. A well similar to this in another larger reservoir is currently under study for the western portion of the field.
Our ownership in the Medusa field was acquired in late 2013. Current daily production net to W&T is approximately 900 Boe and is 85% oil. There are current plans to drill one to two new exploratory wells in the field with the first well expected to spud in late third or early fourth quarter of 2014 with the second well to follow thereafter.
Development at Big Bend continues and first production from this 2012 discovery is still slated for the back half of 2015. Big Bend is located in over 7,000 feet of water and has the gross (100%) resource potential of 30 to 65 MMBoe (P75 – P25 case).
Ship Shoal 349 "Mahogany" Field (100% WI) (Shelf):
During the second quarter, the A-15 well was brought on production and achieved a peak production rate of approximately 1,075 Boe per day (83% liquids). The well had logged over 65 feet of measured depth pay in the "P" sand. In May, the A-6 well was successfully recompleted in the "N" sand. In early June, the A-16 well was spud and is targeting the "M", "N", and "O" sands logged in the A-14 well (that was completed in the newly discovered "T" sand). Production from the Mahogany field averaged 8,220 barrels per day, up from 6,988 barrels per day in the second quarter last year and is a significant contributor to the increase in revenues and production this year over last year.
East Cameron 321 Field (100% WI) (Shelf)
The EC321 field is situated 97 miles off the
East Cameron 338 Field (100% WI) (Shelf)
A recompletion operation was conducted on the A-3 well and placed back on line at a rate substantially above expectations. The well reached a peak rate in excess of 1,300 barrels per day in the later part of June and is still flowing approximately 1,000 barrels per day currently.
Onshore West Texas Permian basin
During the second quarter, we completed 12 wells at our
Our latest horizontal Wolfcamp "B" wells are emphasizing frac and cost optimization strategies. Our second and third operated Wolfcamp "B" horizontal wells, the Chablis 13H and the Chablis 10H, have both been drilled from the same pad (development and cost optimization) and are also testing two different frac designs on these wells from the same pad as we continue to drive development optimizations. These two wells were just recently frac'd and are currently in flowback, have already cut oil and are being equipped with artificial lift in early August. We expect peak rates from these wells in the coming weeks to months and this program is anticipated to begin setting the stage for a continuous and expanded program into 2015.
Additionally, we have just drilled a third horizontal bench ("Lower Spraberry") in our
We are also encouraged by the active and successful well results surrounding our West Texas acreage holdings by offset operators. We continue to expand and capitalize on adding value through JV (Joint Venture) arrangements with offset lease holders to synergistically optimize our collective holdings and to leverage capital efficiencies. We expect to continue our trend of onshore JV arrangements through 2014 and into 2015, depending on the opportunities that arise. Some of those expected JV's may also target newer horizontal benches as well.
Third Quarter and Full Year 2014 Outlook:
Our guidance for the third quarter and full year 2014 is provided in the table below and represents the Company's best estimate of the range of likely future results. It is affected by the factors described below in "Forward-Looking Statements." Our third quarter of 2014 production guidance includes known production outages, particularly at Matterhorn due to a shut in of a third party pipeline for an integrity test and for potential tropical storm downtime (approximately 1.5 Bcfe for storm downtime). We are also expecting an increase in LOE with planned workovers at three different offshore fields and a general increase in facility maintenance. The summer is normally a busier time for offshore work as the weather is typically better. One of the workovers relates to a field that we have increased our working interest in and are taking over operations. Once the well returns to service we anticipate additional production and an incremental increase in proved reserves.
Estimated Production |
Third Quarter |
Prior Full-Year |
Revised Full-Year |
|
Oil and NGLs (MMBbls) |
1.9 – 2.1 |
8.7 – 8.9 |
No change |
|
Natural gas (Bcf) |
9.4 – 10.4 |
47.0 – 48.4 |
No change |
|
Total (Bcfe) |
21.1 – 23.3 |
99.0 – 102.0 |
No change |
|
3.5 – 3.9 |
16.5 – 17.0 |
No change |
||
Operating Expenses |
Third Quarter |
Prior Full-Year 2014 |
Revised Full-Year 2014 |
|
Lease operating expenses |
$78– |
|
|
|
Gathering, transportation & production taxes |
$7 – |
|
|
|
General and administrative |
$23 – |
|
|
|
Income tax rate (100% deferred) |
36.5% |
37% |
36.5% |
Conference Call Information: W&T will hold a conference call to discuss our financial and operational results on
About
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
|
||||||||||||||
Condensed Consolidated Statements of Income (Loss) |
||||||||||||||
(Unaudited) |
||||||||||||||
Three Months Ended |
Six Months Ended |
|||||||||||||
|
|
|||||||||||||
2014 |
2013 |
2014 |
2013 |
|||||||||||
(In thousands, except per share data) |
||||||||||||||
Revenues |
$ |
262,994 |
$ |
235,383 |
$ |
517,510 |
$ |
494,605 |
||||||
Operating costs and expenses: |
||||||||||||||
Lease operating expenses |
61,765 |
68,248 |
117,384 |
127,590 |
||||||||||
Gathering, transportation costs and production taxes |
5,827 |
6,388 |
13,115 |
12,621 |
||||||||||
Depreciation, depletion, amortization and accretion</p> |
128,236 |
99,896 |
251,542 |
208,767 |
||||||||||
General and administrative expenses |
19,682 |
19,868 |
43,270 |
40,955 |
||||||||||
Derivative (gain) loss |
13,079 |
(12,840) |
20,571 |
(9,473) |
||||||||||
Total costs and expenses |
228,589 |
181,560 |
445,882 |
380,460 |
||||||||||
Operating income |
34,405 |
53,823 |
71,628 |
114,145 |
||||||||||
Interest expense: |
||||||||||||||
Incurred |
21,454 |
21,536 |
42,912 |
42,770 |
||||||||||
Capitalized |
(2,159) |
(2,532) |
(4,231) |
(4,964) |
||||||||||
Income before income tax expense |
15,110 |
34,819 |
32,947 |
76,339 |
||||||||||
Income tax expense |
5,273 |
12,423 |
11,921 |
27,325 |
||||||||||
Net income |
$ |
9,837 |
$ |
22,396 |
$ |
21,026 |
$ |
49,014 |
||||||
Basic and diluted earnings per common share |
$ |
0.13 |
$ |
0.29 |
$ |
0.28 |
$ |
0.64 |
||||||
Weighted average common shares outstanding |
75,605 |
75,223 |
</td> |
75,581 |
75,215 |
|||||||||
Consolidated Cash Flow Information |
||||||||||||||
Net cash provided by operating activities |
$ |
152,560 |
$ |
127,528 |
$ |
271,050 |
$ |
297,362 |
||||||
Capital expenditures and acquisitions |
170,976 |
162,587 |
266,043 |
299,213 |
|
||||||||||||
Condensed Operating Data |
||||||||||||
(Unaudited) |
||||||||||||
Three Months Ended |
||||||||||||
|
Variance |
|||||||||||
2014 |
2013 |
Variance |
Percentage(2) |
|||||||||
Net sales volumes: |
||||||||||||
Oil (MBbls) |
1,856 |
1,657 |
199 |
12.0% |
||||||||
NGL (MBbls) |
514 |
491 |
23 |
4.7% |
||||||||
Oil and NGLs (MBbls) |
2,370 |
2,148 |
222 |
10.3% |
||||||||
Natural gas (MMcf) |
12,150 |
11,842 |
308 |
2.6% |
||||||||
Total oil and natural gas (MBoe)(1) |
4,395 |
4,122 |
273 |
6.6% |
||||||||
Total oil and natural gas (MMcfe)(1) |
26,371 |
24,733 |
1,638 |
6.6% |
||||||||
Average daily equivalent sales (MBoe/d) |
48.3 |
45.3 |
3.0 |
6.6% |
||||||||
Average daily equivalent sales (MMcfe/d) |
289.8 |
271.8 |
18.0 |
6.6% |
||||||||
Average realized sales prices: |
||||||||||||
Oil ($/Bbl) |
$ |
99.92 |
$ |
101.78 |
$ |
(1.86) |
-1.8% |
|||||
NGLs ($/Bbl) |
39.98 |
32.17 |
7.81 |
24.3% |
||||||||
Oil and NGLs ($/Bbl) |
86.91 |
85.87 |
1.04 |
1.2% |
||||||||
Natural gas ($/Mcf) |
4.62 |
4.22 |
0.40 |
9.5% |
||||||||
Barrel of oil equivalent ($/Boe) |
59.63 |
56.88 |
2.75 |
4.8% |
||||||||
Natural gas equivalent ($/Mcfe) |
9.94 |
9.48 |
0.46 |
4.9% |
||||||||
Average per Boe ($/Boe): |
||||||||||||
Lease operating expenses |
$ |
14.05 |
$ |
16.56 |
$ |
(2.51) |
-15.2% |
|||||
Gathering and transportation costs and production taxes |
1.33 |
1.55 |
(0.22) |
-14.2% |
||||||||
Depreciation, depletion, amortization and accretion |
29.18 |
24.23 |
4.95 |
20.4% |
||||||||
General and administrative expenses |
4.48 |
4.82 |
(0.34) |
-7.1% |
||||||||
Net cash provided by operating activities |
34.71 |
30.94 |
3.77 |
12.2% |
||||||||
Adjusted EBITDA |
39.98 |
34.18 |
5.80 |
17.0% |
||||||||
Average per Mcfe ($/Mcfe): |
||||||||||||
Lease operating expenses |
$ |
2.34 |
$ |
2.76 |
$ |
(0.42) |
-15.2% |
|||||
Gathering and transportation costs and production taxes |
0.22 |
0.26 |
(0.04) |
-15.4% |
||||||||
Depreciation, depletion, amortization and accretion |
4.86 |
4.04 |
0.82 |
20.3% |
||||||||
General and administrative expenses |
0.75 |
0.80 |
(0.05) |
-6.3% |
||||||||
Net cash provided by operating activities |
5.79 |
5.16 |
0.63 |
12.2% |
||||||||
Adjusted EBITDA |
6.66 |
5.70 |
0.96 |
16.8% |
(1) |
MMcfe and MBoe 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) |
Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data. |
|
||||||||||||
Condensed Operating Data |
||||||||||||
(Unaudited) |
||||||||||||
Six Months Ended |
||||||||||||
|
Variance |
|||||||||||
2014 |
2013 |
Variance |
Percentage(2) |
|||||||||
Net sales volumes: |
||||||||||||
Oil (MBbls) |
3,588 |
3,501 |
87 |
2.5% |
||||||||
NGL (MBbls) |
1,038 |
1,026 |
12 |
1.2% |
||||||||
Oil and NGLs (MBbls) |
4,626 |
4,527 |
99 |
2.2% |
||||||||
Natural gas (MMcf) |
24,768 |
24,562 |
206 |
0.8% |
||||||||
Total oil and natural gas (MBoe)(1) |
8,754 |
8,621 |
133 |
1.5% |
||||||||
Total oil and natural gas (MMcfe)(1) |
52,521 |
51,726 |
795 |
1.5% |
||||||||
Average daily equivalent sales (MBoe/d) |
48.4 |
47.6 |
0.8 |
1.7% |
||||||||
Average daily equivalent sales (MMcfe/d) |
290.2 |
285.8 |
4.4 |
1.5% |
||||||||
Average realized sales prices: |
||||||||||||
Oil ($/Bbl) |
$ |
99.26 |
$ |
104.61 |
$ |
(5.35) |
-5.1% |
|||||
NGLs ($/Bbl) |
39.11 |
33.26 |
5.85 |
17.6% |
||||||||
Oil and NGLs ($/Bbl) |
85.77 |
88.43 |
(2.66) |
-3.0% |
||||||||
Natural gas ($/Mcf) |
4.82 |
3.78 |
1.04 |
27.5% |
||||||||
Barrel of oil equivalent ($/Boe) |
58.97 |
57.22 |
1.75 |
3.1% |
||||||||
Natural gas equivalent ($/Mcfe) |
9.83 |
9.54 |
0.29 |
3.0% |
||||||||
Average per Boe ($/Boe): |
||||||||||||
Lease operating expenses |
$ |
13.41 |
$ |
14.80 |
$ |
(1.39) |
-9.4% |
|||||
Gathering and transportation costs and production taxes |
1.50 |
1.46 |
0.04 |
2.7% |
||||||||
Depreciation, depletion, amortization and accretion |
28.73 |
24.22 |
4.51 |
18.6% |
||||||||
General and administrative expenses |
4.94 |
4.75 |
0.19 |
4.0% |
||||||||
Net cash provided by operating activities |
30.96 |
34.49 |
(3.53) |
-10.2% |
||||||||
Adjusted EBITDA |
39.27 |
36.36 |
2.91 |
8.0% |
||||||||
Average per Mcfe ($/Mcfe): |
||||||||||||
Lease operating expenses |
$ |
2.23 |
$ |
2.47 |
$ |
(0.24) |
-9.7% |
|||||
Gathering and transportation costs and production taxes |
0.25 |
0.24 |
0.01 |
4.2% |
||||||||
Depreciation, depletion, amortization and accretion |
4.79 |
4.04 |
0.75 |
18.6% |
||||||||
General and administrative expenses |
0.82 |
0.79 |
0.03 |
3.8% |
||||||||
Net cash provided by operating activities |
5.16 |
5.75 |
(0.59) |
-10.3% |
||||||||
Adjusted EBITDA |
6.54 |
6.06 |
0.48 |
7.9% |
(1) |
MMcfe and MBoe 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) |
Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data. |
|
|||||||
Condensed Consolidated Balance Sheets |
|||||||
(Unaudited) |
|||||||
|
</td> |
|
|||||
2014 |
2013 |
||||||
(In thousands, except |
|||||||
share data) |
|||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
23,847 |
$ |
15,800 |
|||
Receivables: |
|||||||
Oil and natural gas sales |
94,417 |
96,752 |
|||||
Joint interest and other |
26,584 |
27,984 |
|||||
Income taxes |
120 |
3,120 |
|||||
Total receivables |
121,121 |
127,856 |
|||||
Prepaid expenses and other assets |
38,644 |
29,946 |
|||||
Total current assets |
183,612 |
173,602 |
|||||
Property and equipment – at cost: |
|||||||
Oil and natural gas properties and equipment (full cost method, of which |
|||||||
|
|||||||
amortization) |
7,628,208 |
7,339,097 |
|||||
Furniture, fixtures and other |
21,660 |
21,431 |
|||||
Total property and equipment |
7,649,868 |
7,360,528 |
|||||
Less accumulated depreciation, depletion and amortization |
5,326,074 |
5,084,704 |
|||||
Net property and equipment |
2,323,794 |
2,275,824 |
|||||
Restricted deposits for asset retirement obligations |
23,723 |
37,421 |
|||||
Other assets |
18,643 |
20,455 |
|||||
Total assets |
$ |
2,549,772 |
$ |
2,507,302 |
|||
Liabilities and Shareholders' Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
140,495 |
$ |
145,212 |
|||
Undistributed oil and natural gas proceeds |
39,202 |
42,107 |
|||||
Asset retirement obligations |
69,923 |
77,785 |
|||||
Accrued liabilities |
31,299 |
28,000 |
|||||
Total current liabilities |
280,919 |
293,104 |
|||||
Long-term debt |
1,224,262 |
1,205,421 |
|||||
Asset retirement obligations, less current portion |
287,680 |
276,637 |
|||||
Deferred income taxes |
189,902 |
178,142 |
|||||
Other liabilities |
13,622 |
13,388 |
|||||
Commitments and contingencies |
- |
- |
|||||
Shareholders' equity: |
|||||||
Common stock, |
|||||||
issued and 75,656,558 outstanding at |
|||||||
75,591,699 outstanding at |
1 |
1 |
|||||
Additional paid-in capital |
410,642 |
403,564 |
|||||
Retained earnings |
166,911 |
161,212 |
|||||
Treasury stock, at cost |
(24,167) |
(24,167) |
|||||
Total shareholders' equity |
553,387 |
540,610 |
|||||
Total liabilities and shareholders' equity |
$ |
2,549,772 |
$ |
2,507,302 |
|
||||||||
Condensed Consolidated Statements of Cash Flows |
||||||||
(Unaudited) |
||||||||
Six Months Ended |
||||||||
|
||||||||
2014 |
2013 |
|||||||
(In thousands) |
||||||||
Operating activities: |
||||||||
Net income |
$ |
21,026 |
$ |
49,014 |
||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation, depletion, amortization and accretion |
251,542 |
208,767 |
||||||
Amortization of debt issuance costs and premium |
366 |
910 |
||||||
Share-based compensation |
7,644 |
4,950 |
||||||
Derivative loss (gain) |
20,571 |
(9,473) |
||||||
Cash payments on derivative settlements (realized) |
(14,310) |
(2,310) |
||||||
Deferred income taxes |
11,921 |
23,726 |
||||||
Asset retirement obligation settlements |
(30,338) |
(32,886) |
||||||
Changes in operating assets and liabilities |
2,628 |
54,664 |
||||||
Net cash provided by operating activities |
271,050 |
297,362 |
||||||
Investing activities: |
||||||||
Acquisitions of property interests in oil and natural gas properties |
(53,363) |
- |
||||||
Investment in oil and natural gas properties and equipment |
(212,680) |
(299,213) |
||||||
Purchases of furniture, fixtures and other |
(1,715) |
(981)</span> |
||||||
Net cash used in investing activities |
(267,758) |
(300,194) |
||||||
Financing activities: |
||||||||
Borrowings of long-term debt |
220,000 |
252,000 |
||||||
Repayments of long-term debt |
(200,000) |
(239,000) |
||||||
Dividends to shareholders |
(15,129) |
(12,795) |
||||||
Other |
(116) |
(342) |
||||||
Net cash provided by (used in) financing activities |
4,755 |
(137) |
||||||
Increase (decrease) in cash and cash equivalents |
8,047 |
(2,969) |
||||||
Cash and cash equivalents, beginning of period |
15,800 |
12,245 |
||||||
Cash and cash equivalents, end of period |
$ |
23,847 |
$ |
9,276 |
Non-GAAP Information
Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in
Reconciliation of Net Income to Net Income Excluding Special Items
"Net Income Excluding Special Items" does not include the derivative loss (gain) 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 |
Six Months Ended |
||||||||||
|
|
||||||||||
2014 |
2013 |
2014 |
2013 |
||||||||
Net income |
$ |
9,837 |
$ |
22,396 |
$ |
21,026 |
$ |
49,014 |
|||
Derivative loss (gain) |
13,079 |
(12,840) |
20,571 |
(9,473) |
|||||||
Income tax adjustment for above items at statutory rate |
(4,578) |
4,494 |
(7,200) |
3,316 |
|||||||
Net income excluding special items |
$ |
18,338 |
$ |
14,050 |
$ |
34,397 |
$ |
42,857 |
|||
Basic and diluted earnings per common share, excluding special items |
$ |
0.24 |
$ |
0.18 |
$ |
0.45 |
$ |
0.56 |
|||
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 loss (gain) related to our derivative contracts. We believe the presentation of EBITDA and Adjusted EBITDA provides useful information regarding our ability to service debt and to fund capital expenditures. We believe this presentation is relevant and useful because it helps our investors understand our operating performance and makes 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. Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues.
The following table presents a reconciliation of our consolidated net income to consolidated EBITDA and Adjusted EBITDA along with our Adjusted EBITDA margin.
Three Months Ended |
Six Months Ended |
||||||||||
|
|
||||||||||
2014 |
2013 |
2014 |
2013 |
||||||||
Net income |
$ |
9,837 |
$ |
22,396 |
$ |
21,026 |
$ |
49,014 |
|||
Income tax expense |
5,273 |
12,423 |
11,921 |
27,325 |
|||||||
Net interest expense |
19,295 |
19,013 |
38,685 |
37,815 |
|||||||
Depreciation, depletion, amortization and accretion |
128,236 |
99,896 |
251,542 |
208,767 |
|||||||
EBITDA |
162,641 |
153,728 |
323,174 |
322,921 |
|||||||
Adjustments: |
|||||||||||
Derivative loss (gain) |
13,079</p> |
(12,840) |
20,571 |
(9,473) |
|||||||
Adjusted EBITDA |
$ |
175,720 |
$ |
140,888 |
$ |
343,745 |
$ |
313,448 |
|||
Adjusted EBITDA Margin |
67% |
60% |
66% |
63% |
CONTACT: |
|
|
|
SVP & CFO |
|
713-529-6600 |
713-624-7326 |
SOURCE
Wordcount: | 6012 |
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