Exhibit 99.1
|
|
|
NEWS RELEASE |
FOR IMMEDIATE RELEASE
VENOCO, INC. ANNOUNCES 2nd QUARTER 2013 FINANCIAL
AND OPERATIONAL RESULTS
23% Increase in Daily Oil Production Over Q2 2012;
Net Income of $41.2 million;
Adjusted EBITDA Up 20% Over Q1 2013
DENVER, COLORADO, August 2, 2013 /Marketwire/ — Venoco, Inc. (“Venoco” or the “company”) today reported financial and operational results for the second quarter 2013. The company reported net income of $41.2 million for the quarter on total revenues of $82.4 million.
Adjusted Earnings, which adjusts for unrealized derivative gains and losses and certain other items, were $15.1 million for the quarter up from $4.8 million in the first quarter of 2013. Adjusted EBITDA was $48.6 million in the second quarter of 2013, compared to $40.4 million in the first quarter. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income/loss.
Highlights include the following:
· Production of 897 thousand barrels of oil equivalent (MBOE) for the quarter, or 9,852 BOE per day (BOE/d).
· Daily oil volumes in the second quarter of 2013 were up 4% over the first quarter 2013 and up 23% over second quarter 2012.
Sacramento Basin Sale Update
Effective December 31, 2012, the company sold all of its producing properties in the Sacramento Basin as well as its prospective onshore Monterey acreage in the San Joaquin basin, excluding the Sevier field, to an unrelated third party for $250 million, subject to
customary post-closing adjustments. Portions of the proceeds from the sale were held in escrow pending receipt of consents regarding the transfer of ownership of certain assets. As of May 1, all proceeds have been released from escrow and received by Venoco.
Second Quarter Production
Production in the second quarter of 2013 was 9,852 BOE/d compared to 9,501 BOE/d in the first quarter of 2013 and 7,944 BOE/d in the second quarter of 2012, both of which are pro forma for the sale of the Sacramento Basin assets. Daily oil production in the second quarter of 2013 of 9,363 Bbls/d was up 4% compared to 9,011Bbls/d in the first quarter of 2013, primarily as a result of production from the company’s 3242-4RD well at South Ellwood, which was completed late in the first quarter of 2013. Second quarter 2013 oil production was up 23% over oil production of 7,604 Bbls/d in the second quarter of 2012, primarily as a result of successful drilling at the company’s South Ellwood and West Montalvo fields during 2012 and first half of 2013.
“The 3242-4RD well at South Ellwood was placed on production in late February and produced at a rate that averaged approximately 1,500 BOE per day gross in March. Now that the production has stabilized, the well appears to have settled in at around 800 to 850 BOE per day gross, which makes for a highly economic well,” stated Ed O’Donnell, Venoco’s CEO. “With respect to our West Montalvo and Beverly Hills fields, we experienced mechanical issues on multiple wells in June, which continued into July and resulted in lower production from the fields in the latter part of the second quarter. The majority of these issues have now been resolved and the fields are back up and operating at the levels we expect.”
The following table details the company’s daily production by region (BOE(1)/d):
|
|
|
Quarter Ended |
|
Six Months Ended |
| ||||||
|
Region |
|
6/30/12 |
|
3/31/13 |
|
6/30/13 |
|
6/30/2012 |
|
6/30/2013 |
|
|
Southern California |
|
7,944 |
|
9,501 |
|
9,852 |
|
7,699 |
|
9,678 |
|
|
Sacramento Basin(2) |
|
9,136 |
|
1,127 |
|
— |
|
9,554 |
|
560 |
|
|
Total |
|
17,080 |
|
10,628 |
|
9,852 |
|
17,253 |
|
10,238 |
|
(1) Barrel of oil equivalent (BOE) is calculated using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
(2) First quarter 2013 production from the Sacramento Basin relates to properties that were held in escrow pending the receipt of consents regarding the transfer of ownership. As of May 1, 2013, title to all properties included in the sale on December 31, 2012 has been transferred to the purchaser.
Second Quarter Costs
Venoco’s second quarter 2013 lease operating expenses of $19.97 per BOE were up from $19.36 per BOE in the first quarter of 2013 and $12.93 per BOE in the second quarter of 2012. Pro forma for the sale of the Sacramento Basin properties, second quarter 2013 LOE was down from $21.05 per BOE in the first quarter of 2013, and down from $22.73 per BOE in the second quarter of 2012.
Venoco’s second quarter G&A costs, excluding going private related costs and non-cash share-based compensation, was $10.32 per BOE compared to $13.14 per BOE in the first quarter of 2013 and $5.15 per BOE in the second quarter of 2012. Excluding production from the Sacramento Basin properties, Venoco’s per barrel G&A costs, excluding the costs outlined above, were $14.71 per BOE in the first quarter of 2013 and $11.09 per BOE in the second quarter of 2012. On a pro forma basis, G&A costs in the second quarter of 2013 were lower than the first quarter of 2013 due primarily to lower personnel related costs as a result of the sale of our Sacramento Basin properties.
The following table details the company’s operating costs on a per BOE basis (BOE/d):
|
|
|
Quarter Ended |
|
Six Months Ended |
| |||||||||||
|
UNAUDITED (per BOE) |
|
6/30/12 |
|
3/31/13 |
|
6/30/13 |
|
6/30/12 |
|
6/30/13 |
| |||||
|
Lease Operating Expenses |
|
$ |
12.93 |
|
$ |
19.36 |
|
$ |
19.97 |
|
$ |
14.19 |
|
$ |
19.67 |
|
|
Property and Production Taxes |
|
3.41 |
|
1.18 |
|
1.57 |
|
2.20 |
|
1.37 |
| |||||
|
DD&A Expense |
|
13.65 |
|
12.09 |
|
13.83 |
|
13.84 |
|
12.94 |
| |||||
|
G&A Expense (1) |
|
5.15 |
|
13.14 |
|
10.32 |
|
5.26 |
|
11.78 |
| |||||
(1) Net of amounts capitalized and excluding non-cash share-based compensation costs and costs related to the going-private transaction. See the end of this release for a reconciliation of G&A per BOE.
Capital Investment Second Quarter 2013
Venoco’s second quarter capital expenditures for exploration, development and other spending were $22 million, including $14 million for drilling and rework activities, $2 million for facilities, and the remaining $6 million for land, seismic and capitalized G&A.
In the second quarter of 2013, the company spent $21 million or 95% of its capital expenditures on its Southern California legacy fields, primarily at the South Ellwood field. During the quarter, the company drilled the 3242-15RD well in the South Ellwood field, which bottoms near the eastern boundary of the lease. The well was completed in early July and is still in the process of de-watering. During this process, the well has averaged more than 1,000 gross BOE/d over the last 10 days. The first two wells that were drilled to the same general location were the 3242-12RD (completed in June 2012) and the 3242-4RD (completed in February 2013). The combined gross production from these two wells during July was more than 3,200 BOE/d. After drilling the 3242-15RD well, Venoco returned to drilling the 3242-19 well, which was suspended earlier in the year. This well targets a probable location in a new fault block north of the existing South Ellwood field. Drilling of the well was finished in July and the well is expected to be completed by mid-August. In addition to the completion costs for the 3242-19 well, the company will incur capital expenditures in the second half of 2013 to upgrade the power cable to Platform Holly, which will be completed in the fourth quarter.
Additionally, during the quarter, the company spud its first well for the year at the West Montalvo field, with the well expected to be completed in early August. The drilling
program at the field was delayed by about two months due to the unavailability of the drilling rig. As a result of the delay to the drilling program, the company now expects to spud a total of four wells and complete three wells at West Montalvo during 2013.
In the second quarter of 2013, the company had relatively minimal onshore Monterey capital expenditures of $1 million or 5% of its total second quarter capital expenditures.
2013 Guidance
The following summarizes the company’s 2013 guidance:
· Production: 10,000 – 10,500 BOE/d
· Capital Budget: $90 - $100 million
· Lease Operating Expenses: $20.50 – $21.50 per BOE
· General & Administrative Expenses (excluding non-cash charges related to share-based compensation): $11.00 – $11.50 per BOE
· Production & Property Taxes: $1.80 - $2.20 per BOE
· DD&A: $12.50 – $13.50 per BOE
Earnings Conference Call
Venoco will host a conference call to discuss results Friday, August 2, 2013 at 11:00 a.m. Eastern time (9 a.m. Mountain). The conference call will be webcast and those wanting to listen may do so by using a link on the Investor Relations page of the company’s website at http://www.venocoinc.com. Those wanting to participate in the Q & A portion can call (877) 474-9506 and use conference code 60258542. International participants can call (857) 244-7559 and use the same conference code.
A replay of the conference call will be available for one week by calling (888) 286-8010 or, for international callers, (617) 801-6888, and using passcode 50233910. The replay will also be available on the Venoco website for 30 days.
About the Company
Venoco is an independent energy company primarily engaged in the acquisition, exploitation and development of oil and natural gas properties primarily in California. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms and operates several onshore properties in Southern California.
Forward-looking Statements
Statements made in this news release relating to Venoco’s future production, reserves, expenses, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions
and the company’s future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, and pipeline curtailments by third parties. The company’s exploration and development activities with respect to our projects are subject to numerous operating, geological and other risks and may not be successful. All forward-looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on risks and uncertainties that may affect the company’s operations and financial performance, and the forward-looking statements made herein, is available in the company’s filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.
References to reserve estimates other than proved are by their nature more uncertain than estimates of proved reserves, and are subject to substantially greater risk of not actually being realized by the company. Initial and test results from a well may not be indicative of the well’s longer-term performance.
For further information, please contact Kevin Hehn, Investor Relations, (303) 583-1612; http://www.venocoinc.com; E-Mail investor@venocoinc.com.
Source: Venoco, Inc.
/////
OIL AND NATURAL GAS PRODUCTION AND PRICES
|
|
|
Quarter Ended |
|
Quarter Ended |
|
Six Months Ended |
| ||||||||||||||||||
|
UNAUDITED |
|
3/31/13 |
|
6/30/13 |
|
% Change |
|
6/30/12 |
|
6/30/13 |
|
% Change |
|
6/30/12 |
|
6/30/13 |
|
% Change |
| ||||||
|
Production Volume: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Oil (MBbls) (1) |
|
811 |
|
852 |
|
5 |
% |
692 |
|
852 |
|
23 |
% |
1,333 |
|
1,663 |
|
25 |
% | ||||||
|
Natural Gas (MMcf) |
|
873 |
|
267 |
|
-69 |
% |
5,174 |
|
267 |
|
-95 |
% |
10,842 |
|
1,140 |
|
-89 |
% | ||||||
|
MBOE |
|
957 |
|
897 |
|
-6 |
% |
1,554 |
|
897 |
|
-42 |
% |
3,140 |
|
1,853 |
|
-41 |
% | ||||||
|
Daily Average Production Volume: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Oil (Bbls/d) |
|
9,011 |
|
9,363 |
|
4 |
% |
7,604 |
|
9,363 |
|
23 |
% |
7,324 |
|
9,188 |
|
25 |
% | ||||||
|
Natural Gas (Mcf/d) |
|
9,700 |
|
2,934 |
|
-70 |
% |
56,857 |
|
2,934 |
|
-95 |
% |
59,571 |
|
6,298 |
|
-89 |
% | ||||||
|
BOE/d |
|
10,628 |
|
9,852 |
|
-7 |
% |
17,080 |
|
9,852 |
|
-42 |
% |
17,253 |
|
10,238 |
|
-41 |
% | ||||||
|
Oil Price per Barrel Produced (in dollars): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Realized price before hedging |
|
$ |
99.71 |
|
$ |
93.46 |
|
-6 |
% |
$ |
100.38 |
|
$ |
93.46 |
|
-7 |
% |
$ |
99.55 |
|
$ |
96.51 |
|
-3 |
% |
|
Realized hedging gain (loss) |
|
(10.79 |
) |
(1.78 |
) |
-84 |
% |
(9.56 |
) |
(1.78 |
) |
-81 |
% |
(7.73 |
) |
(6.17 |
) |
-20 |
% | ||||||
|
Net realized price |
|
$ |
88.92 |
|
$ |
91.68 |
|
3 |
% |
$ |
90.82 |
|
$ |
91.68 |
|
1 |
% |
$ |
91.82 |
|
$ |
90.34 |
|
-2 |
% |
|
Natural Gas Price per Mcf (in dollars): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Realized price before hedging |
|
$ |
3.71 |
|
$ |
4.58 |
|
23 |
% |
$ |
2.38 |
|
$ |
4.58 |
|
92 |
% |
$ |
2.58 |
|
$ |
3.91 |
|
52 |
% |
|
Realized hedging gain (loss) |
|
— |
|
— |
|
— |
|
0.47 |
|
— |
|
-100 |
% |
0.55 |
|
— |
|
-100 |
% | ||||||
|
Net realized price |
|
$ |
3.71 |
|
$ |
4.58 |
|
23 |
% |
$ |
2.85 |
|
$ |
4.58 |
|
61 |
% |
$ |
3.13 |
|
$ |
3.91 |
|
25 |
% |
|
Expense per BOE (in dollars): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Lease operating expenses |
|
$ |
19.36 |
|
$ |
19.97 |
|
3 |
% |
$ |
12.93 |
|
$ |
19.97 |
|
54 |
% |
$ |
14.19 |
|
$ |
19.67 |
|
39 |
% |
|
Production and property taxes |
|
$ |
1.18 |
|
$ |
1.57 |
|
33 |
% |
$ |
3.41 |
|
$ |
1.57 |
|
-54 |
% |
$ |
2.20 |
|
$ |
1.37 |
|
-38 |
% |
|
Transportation expenses |
|
$ |
0.04 |
|
$ |
0.05 |
|
25 |
% |
$ |
0.17 |
|
$ |
0.05 |
|
-71 |
% |
$ |
1.49 |
|
$ |
0.04 |
|
-97 |
% |
|
Depreciation, depletion and amortization |
|
$ |
12.09 |
|
$ |
13.83 |
|
14 |
% |
$ |
13.65 |
|
$ |
13.83 |
|
1 |
% |
$ |
13.84 |
|
$ |
12.94 |
|
-7 |
% |
|
General and administrative (2) |
|
$ |
15.65 |
|
$ |
11.57 |
|
-26 |
% |
$ |
6.35 |
|
$ |
11.57 |
|
82 |
% |
$ |
7.08 |
|
$ |
13.68 |
|
93 |
% |
|
Interest expense |
|
$ |
19.70 |
|
$ |
19.40 |
|
-2 |
% |
$ |
10.22 |
|
$ |
19.40 |
|
90 |
% |
$ |
10.06 |
|
$ |
19.57 |
|
95 |
% |
(1) Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on pipeline inventories, oil pipeline sales nominations, and prior to February 2012, the timing of barge deliveries and oil in tanks.
(2) Net of amounts capitalized.
- more -
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
Quarter Ended |
|
Quarter Ended |
|
Six Months Ended |
| ||||||||||||
|
UNAUDITED ($ in thousands) |
|
3/31/13 |
|
6/30/13 |
|
6/30/12 |
|
6/30/13 |
|
6/30/12 |
|
6/30/13 |
| ||||||
|
REVENUES: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Oil and natural gas sales |
|
$ |
85,959 |
|
$ |
81,449 |
|
$ |
80,936 |
|
$ |
81,449 |
|
$ |
164,324 |
|
$ |
167,408 |
|
|
Other |
|
1,304 |
|
910 |
|
1,563 |
|
910 |
|
3,538 |
|
2,214 |
| ||||||
|
Total revenues |
|
87,263 |
|
82,359 |
|
82,499 |
|
82,359 |
|
167,862 |
|
169,622 |
| ||||||
|
EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Lease operating expense |
|
18,531 |
|
17,914 |
|
20,093 |
|
17,914 |
|
44,543 |
|
36,445 |
| ||||||
|
Property and production taxes |
|
1,127 |
|
1,407 |
|
5,302 |
|
1,407 |
|
6,917 |
|
2,534 |
| ||||||
|
Transportation expense |
|
38 |
|
45 |
|
257 |
|
45 |
|
4,669 |
|
83 |
| ||||||
|
Depletion, depreciation and amortization |
|
11,572 |
|
12,406 |
|
21,213 |
|
12,406 |
|
43,467 |
|
23,978 |
| ||||||
|
Accretion of asset retirement obligation |
|
656 |
|
615 |
|
1,450 |
|
615 |
|
2,841 |
|
1,271 |
| ||||||
|
General and administrative |
|
14,975 |
|
10,375 |
|
9,869 |
|
10,375 |
|
22,230 |
|
25,350 |
| ||||||
|
Total expenses |
|
46,899 |
|
42,762 |
|
58,184 |
|
42,762 |
|
124,667 |
|
89,661 |
| ||||||
|
Income from operations |
|
40,364 |
|
39,597 |
|
24,315 |
|
39,597 |
|
43,195 |
|
79,961 |
| ||||||
|
FINANCING COSTS AND OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
Interest expense |
|
18,854 |
|
17,401 |
|
15,880 |
|
17,401 |
|
31,591 |
|
36,255 |
| ||||||
|
Amortization of deferred loan costs |
|
1,113 |
|
906 |
|
585 |
|
906 |
|
1,154 |
|
2,019 |
| ||||||
|
Loss on extinguishment of debt |
|
21,297 |
|
— |
|
— |
|
— |
|
— |
|
21,297 |
| ||||||
|
Commodity derivative realized (gains) losses |
|
14,617 |
|
5,132 |
|
(6,786 |
) |
5,132 |
|
(47,882 |
) |
19,749 |
| ||||||
|
Commodity derivative unrealized (gains) losses and amortization of derivative premiums |
|
(11,274 |
) |
(25,083 |
) |
90 |
|
(25,083 |
) |
71,724 |
|
(36,357 |
) | ||||||
|
Total financing costs and other |
|
44,607 |
|
(1,644 |
) |
9,769 |
|
(1,644 |
) |
56,587 |
|
42,963 |
| ||||||
|
Income (loss) before taxes |
|
(4,243 |
) |
41,241 |
|
14,546 |
|
41,241 |
|
(13,392 |
) |
36,998 |
| ||||||
|
Income tax provision (benefit) |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
| ||||||
|
Net income (loss) |
|
$ |
(4,243 |
) |
$ |
41,241 |
|
$ |
14,546 |
|
$ |
41,241 |
|
$ |
(13,392 |
) |
$ |
36,998 |
|
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
|
UNAUDITED ($ in thousands) |
|
12/31/12 |
|
6/30/13 |
| ||
|
ASSETS |
|
|
|
|
| ||
|
Cash and cash equivalents |
|
$ |
53,818 |
|
$ |
3,516 |
|
|
Accounts receivable |
|
108,356 |
|
26,694 |
| ||
|
Inventories |
|
5,101 |
|
5,344 |
| ||
|
Other current assets |
|
4,448 |
|
2,833 |
| ||
|
Commodity derivatives |
|
153 |
|
2,128 |
| ||
|
Total current assets |
|
171,876 |
|
40,515 |
| ||
|
Net property, plant and equipment |
|
648,602 |
|
633,712 |
| ||
|
Total other assets |
|
25,603 |
|
20,977 |
| ||
|
TOTAL ASSETS |
|
$ |
846,081 |
|
$ |
695,204 |
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
| ||
|
Accounts payable and accrued liabilities |
|
$ |
57,315 |
|
$ |
40,677 |
|
|
Interest payable |
|
27,862 |
|
21,326 |
| ||
|
Current maturities of long-term debt |
|
104,494 |
|
— |
| ||
|
Commodity derivatives |
|
20,607 |
|
2,359 |
| ||
|
Share based compensation |
|
10,424 |
|
15,305 |
| ||
|
Total current liabilities |
|
220,702 |
|
79,667 |
| ||
|
LONG-TERM DEBT |
|
849,190 |
|
828,145 |
| ||
|
COMMODITY DERIVATIVES |
|
20,287 |
|
3,137 |
| ||
|
ASSET RETIREMENT OBLIGATIONS |
|
41,119 |
|
34,626 |
| ||
|
SHARE BASED COMPENSATION |
|
10,441 |
|
8,298 |
| ||
|
Total liabilities |
|
1,141,739 |
|
953,873 |
| ||
|
Total stockholders’ equity |
|
(295,658 |
) |
(258,669 |
) | ||
|
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
$ |
846,081 |
|
$ |
695,204 |
|
GAAP RECONCILIATIONS
Adjusted Earnings and Adjusted EBITDA
In addition to net income (loss) determined in accordance with GAAP, we have provided in this release our Adjusted Earnings and Adjusted EBITDA for recent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAP financial measures that we use as supplemental measures of our performance.
We define Adjusted Earnings as net income (loss) before the effects of the items listed in the table below. We calculate the tax effect of reconciling items by re-performing our period-end tax calculation excluding the reconciling items from earnings. The difference between this calculation and the tax expense/benefit recorded for the period results in the tax effect disclosed below. We believe that Adjusted Earnings facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to our ongoing operations. Adjusted Earnings should not be considered a substitute for net income (loss) as reported in accordance with GAAP.
We define Adjusted EBITDA as net income (loss) before the effects of the items listed in the table below. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.
We present Adjusted Earnings and Adjusted EBITDA because we consider them to be important supplemental measures of our performance. Neither Adjusted Earnings nor Adjusted EBITDA is a measurement of our financial performance under GAAP and neither should be considered as an alternative to net income (loss), operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted Earnings or Adjusted EBITDA amounts shown are comparable to similarly named measures disclosed by other companies.
|
|
|
Quarter Ended |
|
Six Months Ended |
| |||||||||||
|
UNAUDITED ($ in thousands) |
|
6/30/12 |
|
3/31/13 |
|
6/30/13 |
|
6/30/12 |
|
6/30/13 |
| |||||
|
Adjusted Earnings Reconciliation |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Net Income |
|
$ |
14,546 |
|
$ |
(4,243 |
) |
$ |
41,241 |
|
$ |
(13,392 |
) |
$ |
36,998 |
|
|
Plus: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Unrealized commodity (gains) losses |
|
(2,134 |
) |
(12,223 |
) |
(26,101 |
) |
61,705 |
|
(38,324 |
) | |||||
|
Going private related costs |
|
852 |
|
— |
|
— |
|
3,480 |
|
— |
| |||||
|
Loss on extinguishment of debt |
|
— |
|
21,297 |
|
— |
|
— |
|
21,297 |
| |||||
|
Tax effects |
|
— |
|
— |
|
— |
|
— |
|
— |
| |||||
|
Adjusted Earnings |
|
$ |
13,264 |
|
$ |
4,831 |
|
$ |
15,140 |
|
$ |
51,793 |
|
$ |
19,971 |
|
|
|
|
Quarter Ended |
|
Six Months Ended |
| |||||||||||
|
UNAUDITED ($ in thousands) |
|
6/30/12 |
|
3/31/13 |
|
6/30/13 |
|
6/30/12 |
|
6/30/13 |
| |||||
|
Adjusted EBITDA Reconciliation |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Net income |
|
$ |
14,546 |
|
$ |
(4,243 |
) |
$ |
41,241 |
|
$ |
(13,392 |
) |
$ |
36,998 |
|
|
Interest expense |
|
15,880 |
|
18,854 |
|
17,401 |
|
31,591 |
|
36,255 |
| |||||
|
DD&A |
|
21,213 |
|
11,572 |
|
12,406 |
|
43,467 |
|
23,978 |
| |||||
|
Accretion of asset retirement obligation |
|
1,450 |
|
656 |
|
615 |
|
2,841 |
|
1,271 |
| |||||
|
Amortization of deferred loan costs |
|
585 |
|
1,113 |
|
906 |
|
1,154 |
|
2,019 |
| |||||
|
Loss on extinguishment of debt |
|
— |
|
21,297 |
|
— |
|
— |
|
21,297 |
| |||||
|
Non-cash share-based compensation expense |
|
1,208 |
|
2,401 |
|
1,122 |
|
2,748 |
|
3,523 |
| |||||
|
Going private related costs |
|
852 |
|
— |
|
— |
|
3,480 |
|
— |
| |||||
|
Amortization of derivative premiums |
|
2,224 |
|
949 |
|
1,018 |
|
10,019 |
|
1,967 |
| |||||
|
Unrealized commodity derivative (gains) losses |
|
(2,134 |
) |
(12,223 |
) |
(26,101 |
) |
61,705 |
|
(38,324 |
) | |||||
|
Adjusted EBITDA |
|
$ |
55,824 |
|
$ |
40,376 |
|
$ |
48,608 |
|
$ |
143,613 |
|
$ |
88,984 |
|
We also provide per BOE G&A expenses excluding costs associated with the going-private transaction and non-cash share-based compensation charges. We believe that these non-GAAP measures are useful in that the items excluded do not represent cash expenses directly related to our ongoing operations. These non-GAAP measures should not be viewed as an alternative to per BOE G&A expenses as determined in accordance with GAAP.
|
|
|
Quarter Ended |
|
Six Months Ended |
| |||||||||||
|
UNAUDITED ($ in thousands, except per BOE amounts) |
|
6/30/12 |
|
3/31/13 |
|
6/30/13 |
|
6/30/12 |
|
6/30/13 |
| |||||
|
G&A per BOE Reconciliation |
|
|
|
|
|
|
|
|
|
|
| |||||
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
|
G&A expense |
|
$ |
9,869 |
|
$ |
14,975 |
|
$ |
10,375 |
|
$ |
22,230 |
|
$ |
25,350 |
|
|
Less: |
|
|
|
|
|
|
|
|
|
|
| |||||
|
Non-cash share-based compensation expense |
|
(1,018 |
) |
(2,401 |
) |
(1,122 |
) |
(2,238 |
) |
(3,523 |
) | |||||
|
Going private related costs |
|
(852 |
) |
— |
|
— |
|
(3,480 |
) |
— |
| |||||
|
G&A Expense Excluding Non-Cash Share-Based Comp and Going Private Costs |
|
7,999 |
|
12,574 |
|
9,253 |
|
16,512 |
|
21,827 |
| |||||
|
MBOE |
|
1,554 |
|
957 |
|
897 |
|
3,140 |
|
1,853 |
| |||||
|
G&A Expense per BOE Excluding Non-Cash Share-Based Comp and Going Private Costs |
|
$ |
5.15 |
|
$ |
13.14 |
|
$ |
10.32 |
|
$ |
5.26 |
|
$ |
11.78 |
|
|
MBOE excluding Sacramento Basin production |
|
721 |
|
855 |
|
— |
|
1,401 |
|
1,752 |
| |||||
|
G&A Expense per BOE Excluding Non-Cash Share-Based Comp and Going Private Costs-Excluding Sacramento Basin Production |
|
$ |
11.09 |
|
$ |
14.71 |
|
$ |
10.32 |
|
$ |
11.79 |
|
$ |
12.46 |
|
- end -