EXHIBIT 99.2
As described in its Current Report on Form 8-K filed with the Securities and Exchange Commission on January 28, 2014, the Company has updated operating results for all periods covered in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (as filed with the Securities and Exchange Commission on May 2, 2013) (the “2012 Form 10-K”), in order to reflect the retrospective reclassification of results for its Oman operations in discontinued operations. The Management’s Discussion and Analysis that follows revises the information included in the 2012 Form 10-K in order to reflect this retrospective reclassification and should be read in conjunction with the updated financial statements and schedules included as exhibits to the Current Report on Form 8-K filed on January 28, 2014.
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Operations
We had a net loss attributable to Harvest of $12.2 million, or $(0.33) per diluted share, for the year ended December 31, 2012 compared to net income attributable to Harvest of $56.0 million, or $1.64 per diluted share, for the year ended December 31, 2011. Net loss attributable to Harvest for the year ended December 31, 2012 includes $8.8 million of exploration expense, $2.9 of impairment expense, $0.7 million of dry hole costs and net equity income from Petrodelta’s operations of $67.8 million. Net income attributable to Harvest for the year ended December 31, 2011 includes $12.0 million of exploration expense, $3.3 million of impairment expense, $40.0 million of dry hole costs and net equity income from Petrodelta’s operations of $73.5 million. As discussed further below under “Block 64 EPSA Project-Oman,” all activities associated with our Oman operations have been terminated and therefore have been reflected as discontinued operations on the statement of operations.
Restatement of Prior Period Financial Statements
The following tables have been retrospectively reclassified to present the results of the Company’s Oman operations, which were terminated in May 2013, as discontinued operations.
In connection with the preparation of our Annual Report on Form 10-K for the year ended December 31, 2012, we concluded that there were errors in previously filed financial statements. In the course of our review, management determined that (a) certain warrants issued in 2010 in connection with our $60 million term loan facility (the “Warrants”) were improperly valued at inception and improperly classified as equity instruments rather than liability instruments. As a result of the improper classification of the Warrants, (b) the debt discount and associated interest expense related to the amortization of the debt discount was understated for all periods in which the associated debt was outstanding, and (c) the consolidated statement of operations and comprehensive income (loss) for each reporting period was misstated by the omission of the changes in fair value of the Warrants as a liability instrument. Additionally, (d) certain exploration overhead was incorrectly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed, and (e) certain leasehold maintenance and other costs were improperly capitalized to oil and gas properties, which under the successful efforts method of accounting should have been expensed. Finally, (f) advances to equity affiliate were improperly classified as an operating activity rather than an investing activity and (g) certain costs were improperly classified as an investing activity rather than an operating activity on the consolidated statement of cash flows. Such errors impacted annual periods ended December 31, 2010 and 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012, and September 30, 2012.
As a result of the errors related to the Warrants described above, loss on extinguishment of debt was understated for the year ended December 31, 2011 and the quarters ended June 30, 2011, September 30, 2011 and December 31, 2011.
Additionally, an error was identified in the calculation of earnings (loss) per diluted share for the year ended December 31, 2011 and the three and six months ended June 30, 2011, and an additional error was identified related to the improper expensing of costs associated with debt conversions that should have been recorded to equity for the quarters ended March 31, 2012 and September 30, 2012.
We have restated our segment footnote information to reflect the applicable errors stated above and (a) reclassify noncontrolling interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense. Such errors impacted annual periods ended December 31, 2010 and 2011 and quarterly periods ended March 31, 2011, June 30, 2011, September 30, 2011, December 31, 2011, March 31, 2012, June 30, 2012 and September 30, 2012. We also restated our financial statement schedule to reflect adjustments to the balance sheet related to income taxes for the years ended December 31, 2010 and 2011.
In assessing the severity of the errors, management determined that the errors were material to the consolidated financial statements for the years ended December 31, 2011 and 2010 and quarterly information for all quarters in 2011 and the first, second and third quarters of 2012. In addition to the errors described above, we made corrections for previously identified immaterial errors and errors affecting classification within the consolidated statement of operations and comprehensive income (loss) related to impairment of oil and gas properties and income taxes and the consolidated balance sheets related to income taxes.
The audited financial statements, related notes and analyses for the years ended December 31, 2011 and 2010 were retrospectively restated for the errors described above in our Annual Report on Form 10-K filed May 2, 2013. We amended our Quarterly Reports on Form 10-Q/A for each of the quarterly periods shortly after the filing of this Annual Report on Form 10-K.
The following tables set forth the effect of the adjustments described above on the consolidated statements of operations and comprehensive income (loss), the consolidated statements of cash flows and the consolidated statements of stockholders’ equity for the years ended December 31, 2011 and 2010, and the consolidated balance sheet as of December 31, 2011.
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Consolidated Statements of Operations and Comprehensive Income (Loss)
December 31, 2011 | December 31, 2010 | |||||||||||||||||||||||||||||||||||||||
As Previously Reported | Adjustment | As RESTATED | Discontinued Operations | Currently Reported | As Previously Reported | Adjustment | As RESTATED | Discontinued Operations | Currently Reported | |||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||||||
Depreciation and amortization | $ | 462 | $ | — | $ | 462 | $ | (23 | ) | $ | 439 | $ | 484 | $ | — | $ | 484 | $ | (17 | ) | $ | 467 | ||||||||||||||||||
Exploration expense(a) | 13,690 | (1,125 | ) | 12,565 | (615 | ) | 11,950 | 8,016 | 313 | 8,329 | (1,239 | ) | 7,090 | |||||||||||||||||||||||||||
Impairment of oil and gas properties(f) | — | 3,335 | 3,335 | — | 3,335 | — | — | — | — | — | ||||||||||||||||||||||||||||||
Dry hole costs | 49,676 | — | 49,676 | (9,673 | ) | 40,003 | — | — | — | — | — | |||||||||||||||||||||||||||||
General and administrative | 22,474 | — | 22,474 | (1,046 | ) | 21,428 | 25,903 | — | 25,903 | (686 | ) | 25,217 | ||||||||||||||||||||||||||||
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Total expenses | 86,302 | 2,210 | 88,512 | (11,357 | ) | 77,155 | 34,403 | 313 | 34,716 | (1,942 | ) | 32,774 | ||||||||||||||||||||||||||||
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Loss from operations | (86,302 | ) | (2,210 | ) | (88,512 | ) | 11,357 | (77,155 | ) | (34,403 | ) | (313 | ) | (34,716 | ) | 1,942 | (32,774 | ) | ||||||||||||||||||||||
Other non-operating income (expense) | ||||||||||||||||||||||||||||||||||||||||
Investment earnings and other | 665 | — | 665 | — | 665 | 557 | — | 557 | — | 557 | ||||||||||||||||||||||||||||||
Unrealized gain (loss) on warrant derivatives(b) | — | 9,786 | 9,786 | — | 9,786 | — | 344 | 344 | — | 344 | ||||||||||||||||||||||||||||||
Interest expense(c) | (5,336 | ) | (1,823 | ) | (7,159 | ) | — | (7,159 | ) | (2,689 | ) | (1,098 | ) | (3,787 | ) | — | (3,787 | ) | ||||||||||||||||||||||
Loss on extinguishment of debt(d) | (9,682 | ) | (3,450 | ) | (13,132 | ) | — | (13,132 | ) | — | — | — | — | — | ||||||||||||||||||||||||||
Other non-operating expense | (1,375 | ) | — | (1,375 | ) | — | (1,375 | ) | (3,952 | ) | — | (3,952 | ) | — | (3,952 | ) | ||||||||||||||||||||||||
Loss on exchange rates | (146 | ) | — | (146 | ) | 14 | (132 | ) | (1,588 | ) | — | (1,588 | ) | 10 | (1,578 | ) | ||||||||||||||||||||||||
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(15,874 | ) | 4,513 | (11,361 | ) | 14 | (11,347 | ) | (7,672 | ) | (754 | ) | (8,426 | ) | 10 | (8,416 | ) | ||||||||||||||||||||||||
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Loss from Continuing Operations Before Income taxes | (102,176 | ) | 2,303 | (99,873 | ) | 11,371 | (88,502 | ) | (42,075 | ) | (1,067 | ) | (43,142 | ) | 1,952 | (41,190 | ) | |||||||||||||||||||||||
Income tax expense (benefit)(g) | 820 | 237 | 1,057 | — | 1,057 | (184 | ) | — | (184 | ) | — | (184 | ) | |||||||||||||||||||||||||||
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Loss from Continuing Operations | (102,996 | ) | 2,066 | (100,930 | ) | 11,371 | (89,559 | ) | (41,891 | ) | (1,067 | ) | (42,958 | ) | 1,952 | (41,006 | ) | |||||||||||||||||||||||
Net Income from Equity Affiliate | 73,451 | — | 73,451 | — | 73,451 | 66,291 | — | 66,291 | — | 66,291 | ||||||||||||||||||||||||||||||
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Net Income (Loss) from Continuing Operations | (29,545 | ) | 2,066 | (27,479 | ) | 11,371 | (16,108 | ) | 24,400 | (1,067 | ) | 23,333 | 1,952 | 25,285 | ||||||||||||||||||||||||||
Income (Loss) from Discontinued Operations | 97,616 | — | 97,616 | (11,371 | ) | 86,245 | 3,712 | — | 3,712 | (1,952 | ) | 1,760 | ||||||||||||||||||||||||||||
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Net Income | 68,071 | 2,066 | 70,137 | — | 70,137 | 28,112 | (1,067 | ) | 27,045 | — | 27,045 | |||||||||||||||||||||||||||||
Less: Net Income Attributable to Noncontrolling Interest | 14,177 | — | 14,177 | — | 14,177 | 12,670 | — | 12,670 | — | 12,670 | ||||||||||||||||||||||||||||||
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Net Income (Loss) Attributable To Harvest | $ | 53,894 | $ | 2,066 | $ | 55,960 | $ | — | $ | 55,960 | $ | 15,442 | $ | (1,067 | ) | $ | 14,375 | $ | — | $ | 14,375 | |||||||||||||||||||
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Net Income (Loss) Attributable to Harvest Per Common Share: | ||||||||||||||||||||||||||||||||||||||||
Basic | $ | 1.58 | $ | 0.06 | $ | 1.64 | $ | — | $ | 1.64 | $ | 0.46 | $ | (0.03 | ) | $ | 0.43 | $ | — | $ | 0.43 | |||||||||||||||||||
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Diluted(e) | $ | 1.37 | $ | 0.27 | $ | 1.64 | $ | — | $ | 1.64 | $ | 0.42 | $ | (0.03 | ) | $ | 0.39 | $ | — | $ | 0.39 | |||||||||||||||||||
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Comprehensive income (loss) | $ | 53,894 | $ | 2,066 | $ | 55,960 | $ | — | $ | 55,960 | $ | 15,442 | $ | (1,067 | ) | $ | 14,375 | $ | — | $ | 14,375 | |||||||||||||||||||
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(a) | For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $2,210 thousand offset by a reclassification from exploration expense to impairment of oil and gas properties of $3,335 thousand for amounts that were erroneously classified as exploration expense. For 2010, relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than as exploration expense. |
(b) | Represents change in fair value of the Warrants for the period. Such Warrants were previously erroneously classified as equity and were, therefore, not marked to market at the end of each reporting period. |
(c) | The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair value calculation. The corrected fair value of the Warrants at inception exceeds the original valuation by $3,878 thousand. As a result of this change in the fair value of the Warrants, the original discount allocated to the debt was understated by approximately $3,878 thousand; therefore, the additional amortization of the discount on debt, which is a component of interest expense, was understated for each period the debt was outstanding. For 2011, income tax expense of $237 thousand was improperly classified as interest expense. |
(d) | As noted in (c) above, the correction in the fair value of the Warrants and its classification as a liability resulted in an increased discount on debt which also impacted the resulting loss on extinguishment of debt originally recorded in May 2011 when the debt was retired. |
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(e) | In addition to the impact on EPS related to the adjustments described in (a) through (d) above and (f) and (g) below, diluted EPS has been adjusted to reflect an error in the calculation of the weighted average common shares outstanding for dilutive EPS as of December 31, 2011. The weighted average common shares utilized for the calculation of diluted EPS was erroneously 39,339 thousand rather than 34,117 thousand. |
(f) | Reclassification of impairment of oil and gas properties expense in 2011 of $3,335 thousand that was previously erroneously presented as exploration expense. |
(g) | Represents income tax improperly classified as interest expense. |
Consolidated Balance Sheets
December 31, 2011 | ||||||||||||
As Previously Reported | Adjustment | As RESTATED | ||||||||||
(in thousands) | ||||||||||||
Deferred income taxes(a) | $ | 2,628 | $ | (2,628 | ) | $ | — | |||||
Oil and gas properties(b) | 65,671 | (3,216 | ) | 62,455 | ||||||||
Total assets(a)(b) | 513,047 | (5,844 | ) | 507,203 | ||||||||
Accrued interest payable(g) | 1,372 | (396 | ) | 976 | ||||||||
Other current liabilities(a)(g) | 4,835 | (2,203 | ) | 2,632 | ||||||||
Income taxes payable(g) | 718 | (29 | ) | 689 | ||||||||
Warrant derivative liability(c) | — | 4,870 | 4,870 | |||||||||
Total liabilities(a)(c)(g) | 65,592 | 2,242 | 67,834 | |||||||||
Additional paid in capital(d) | 236,192 | (8,392 | ) | 227,800 | ||||||||
Retained earnings(e) | 193,283 | 306 | 193,589 | |||||||||
Total Harvest shareholders’ equity(f) | 363,777 | (8,086 | ) | 355,691 | ||||||||
Total equity(f) | 447,455 | (8,086 | ) | 439,369 |
(a) | Relates to a deferred tax asset that was erroneously reported gross of the related liability. |
(b) | Relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense. |
(c) | Relates to the reclassification of the Warrants out of additional paid in capital to warrant derivative liabilities. The fair value of the Warrants was not appropriately determined at inception because certain features of the Warrants were not originally considered in the fair value calculation. Thus, the correction of the error to record the Warrants as a liability does not agree to the correction of the error removing the Warrants from equity. Additionally, the Warrants were not properly marked to market at the end of each period. The warrant derivative liability was valued at $15,000 thousand at inception with subsequent reductions in fair value of $344 thousand in 2010 and $9,786 thousand in 2011. |
(d) | Relates to the reversal of the amount recorded to equity at inception for the Warrants of $11,122 thousand and the reversal of the amount removed from additional paid in capital of $2,730 thousand when a portion of the Warrants were redeemed by the Company. In May 2011, additional paid in capital was debited for $2,730 thousand for the reversal of the original fair value of such warrants which was an error as they did not qualify for equity classification. |
(e) | Relates to (a) net increase in expense in 2010 and 2011 related to exploration expense of $2,523 thousand (inclusive of the reclassification of exploration expense to impairment of oil and gas properties of $3,335 thousand), (b) net increase in unrealized gain on warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011 (e) net increase in income tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010. |
(f) | Relates to reclassification of the Warrants as described in (d) above plus the impact of retained earnings described in (e) above. |
(g) | Represents other current liabilities that were improperly classified as interest payable and income taxes payable. |
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Consolidated Statements of Cash Flows
December 31, 2011 | December 31, 2010 | |||||||||||||||||||||||
As Previously Reported | Adjustment | As RESTATED | As Previously Reported | Adjustment | As RESTATED | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Net cash used in operating activities(a)(b) | $ | (52,737 | ) | $ | (2,506 | ) | $ | (55,243 | ) | $ | (5,296 | ) | $ | (2,830 | ) | $ | (8,126 | ) | ||||||
Net cash provided by (used in) investing activities(a)(b) | 109,710 | 2,506 | 112,216 | (59,061 | ) | 2,830 | (56,231 | ) | ||||||||||||||||
Net cash provided by (used in) financing activities | (56,730 | ) | — | (56,730 | ) | 90,743 | — | 90,743 | ||||||||||||||||
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Net increase in cash and cash equivalents | 243 | — | 243 | 26,386 | — | 26,386 | ||||||||||||||||||
Cash and cash equivalents at beginning of year | 58,703 | — | 58,703 | 32,317 | — | 32,317 | ||||||||||||||||||
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Cash and cash equivalents at end of year | $ | 58,946 | $ | — | $ | 58,946 | $ | 58,703 | $ | — | $ | 58,703 | ||||||||||||
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(a) | For 2011, relates to the $2,288 thousand of lease maintenance costs, exploration overhead and $900 thousand of certain investment costs that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $(682) thousand were previously erroneously classified as an operating activity rather than an investing activity. |
(b) | For 2010, relates to $167 thousand of lease maintenance costs and $(558) thousand of certain investment costs that were improperly classified as an investing activity rather than an operating activity. In addition, Advances to Equity Affiliates of $3,221 thousand were improperly classified as an operating activity rather than an investing activity. |
In addition to the above, we have restated the Consolidated Statements of Stockholder’s Equity to reflect the reclassification of the Warrants from equity to warrant derivative liability and to restate the January 1, 2010 beginning balances to reflect cumulative adjustments related to the previously described errors that affect periods prior to the year ended December 31, 2010 as follows:
Common Shares Issued | Common Stock | Additional Paid-in Capital | Retained Earnings | Treasury Stock | Non- Controlling Interest | Total Equity | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Balance at January 1, 2010 as originally reported | 39,495 | $ | 395 | $ | 213,337 | $ | 123,947 | $ | (65,383 | ) | $ | 56,831 | $ | 329,127 | ||||||||||||||
Adjustments(a) | — | — | — | (693 | ) | — | — | (693 | ) | |||||||||||||||||||
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Balance at January 1, 2010 as RESTATED | 39,495 | $ | 395 | $ | 213,337 | $ | 123,254 | $ | (65,383 | ) | $ | 56,831 | $ | 328,434 | ||||||||||||||
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(a) | Relates to lease maintenance costs that were erroneously capitalized as oil and gas properties rather than expensed prior to January 1, 2010 (the “Beginning Retained Earnings Adjustment”). |
Common Shares Issued | Common Stock | Additional Paid-in Capital | Retained Earnings | Treasury Stock | Non- Controlling Interest | Total Equity | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Balance at December 31, 2010 as originally reported | 40,103 | $ | 401 | $ | 230,362 | $ | 139,389 | $ | (65,543 | ) | $ | 69,501 | $ | 374,110 | ||||||||||||||
Adjustments(a)(b) | — | — | (11,122 | ) | (1,760 | ) | — | — | (12,882 | ) | ||||||||||||||||||
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Balance at December 31, 2010 as RESTATED | 40,103 | $ | 401 | $ | 219,240 | $ | 137,629 | $ | (65,543 | ) | $ | 69,501 | $ | 361,228 | ||||||||||||||
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(a) | The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability. |
(b) | The adjustment to retained earnings relates to (a) lease maintenance costs of $313 thousand that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense, (b) the reduction in the fair value of the Warrants for the year ended December 31, 2010 of $344 thousand, additional amortization of debt of $1,098 thousand resulting from the increased discount allocated to the debt, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized to oil and gas properties rather than expensed to exploration expenses prior to January 1, 2010. |
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Common Shares Issued | Common Stock | Additional Paid-in Capital | Retained Earnings | Treasury Stock | Non- Controlling Interest | Total Equity | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||
Balance at December 31, 2011 as originally reported | 40,625 | $ | 406 | $ | 236,192 | $ | 193,283 | $ | (66,104 | ) | $ | 83,678 | $ | 447,455 | ||||||||||||||
Adjustments(a)(b) | — | — | (8,392 | ) | 306 | — | — | (8,086 | ) | |||||||||||||||||||
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Balance at December 31, 2011 as RESTATED | 40,625 | $ | 406 | $ | 227,800 | $ | 193,589 | $ | (66,104 | ) | $ | 83,678 | $ | 439,369 | ||||||||||||||
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(a) | The adjustment to additional paid-in capital relates to the reclassification of the Warrants from equity to warrant derivative liability of $11,122 thousand offset by an error recorded in 2011 for $2,730 thousand for the reversal of the original fair value of certain Warrants that did not qualify for equity classification. |
(b) | The adjustment to retained earnings relates to (a) net increase in 2010 and 2011 expense related to exploration expense of $2,523 thousand that was erroneously capitalized as oil and gas properties rather than expensed as exploration expense (includes consideration of reclassification between exploration expense and impairment of oil and gas properties), (b) net increase in unrealized gain on warrant derivatives of $10,130 thousand for cumulative 2010 and 2011, (c) net increase in interest expense of $2,921 thousand cumulative for 2010 and 2011, (d) net increase in loss on extinguishment of debt of $3,450 thousand for 2011, (e) net increase in income tax expense of $237 thousand for income taxes improperly classified as interest expense, offset by a reduction to retained earnings of $693 thousand prior to January 1, 2010 for adjustments to leasehold maintenance costs that were improperly capitalized rather than expensed prior to January 1, 2010. |
In addition to the above, we have restated Operating Segments to reflect the errors stated above and (a) reclassify noncontrolling interest from United States segment to Venezuela segment, (b) eliminate intrasegment receivables erroneously reported gross of related intrasegment payable, and (c) eliminate intrasegment revenue erroneously reported gross of related intrasegment expense.
December 31, 2011 | December 31, 2010 | |||||||||||||||||||||||||||||||||||||||
As Previously Reported | Adjustments | As Restated | Discontinued Operations | Currently Reported | As Previously Reported | Adjustments | As Restated | Discontinued Operations | Currently Reported | |||||||||||||||||||||||||||||||
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Segment Income (Loss) Attributable to Harvest | ||||||||||||||||||||||||||||||||||||||||
Venezuela(a) | $ | 69,577 | $ | (14,603 | ) | $ | 54,974 | $ | — | $ | 54,974 | $ | 62,177 | $ | (13,019 | ) | $ | 49,158 | $ | — | $ | 49,158 | ||||||||||||||||||
Indonesia(b) | (44,800 | ) | (2,888 | ) | (47,688 | ) | — | (47,688 | ) | (7,108 | ) | 843 | (6,265 | ) | — | (6,265 | ) | |||||||||||||||||||||||
Gabon(c) | (5,743 | ) | (2,245 | ) | (7,988 | ) | — | (7,988 | ) | (543 | ) | (1,099 | ) | (1,642 | ) | — | (1,642 | ) | ||||||||||||||||||||||
Oman(d) | (11,325 | ) | (535 | ) | (11,860 | ) | 11,860 | — | (1,934 | ) | (305 | ) | (2,239 | ) | 2,239 | — | ||||||||||||||||||||||||
United States(e) | (51,431 | ) | 22,337 | (29,094 | ) | (489 | ) | (29,583 | ) | (40,862 | ) | 12,513 | (28,349 | ) | (287 | ) | (28,636 | ) | ||||||||||||||||||||||
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Net income (loss) from continuing operations | (43,722 | ) | 2,066 | (41,656 | ) | 11,371 | (30,285 | ) | 11,730 | (1,067 | ) | 10,663 | 1,952 | 12,615 | ||||||||||||||||||||||||||
Discontinued operations | 97,616 | — | 97,616 | (11,371 | ) | 86,245 | 3,712 | — | 3,712 | (1,952 | ) | 1,760 | ||||||||||||||||||||||||||||
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Net income (loss) attributable to Harvest | $ | 53,894 | $ | 2,066 | $ | 55,960 | $ | — | $ | 55,960 | $ | 15,442 | $ | (1,067 | ) | $ | 14,375 | $ | — | $ | 14,375 | |||||||||||||||||||
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(a) | Relates to reclassification of noncontrolling interest from United States segment to Venezuela segment and elimination of intrasegment revenue erroneously reported gross of intrasegment expense. |
(b) | For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $1,505 thousand and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense of $1,383 thousand. For 2010, relates to elimination of intrasegment revenue erroneously reported gross of related intrasegment expense. |
(c) | For 2011, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $415 thousand and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense of $1,830 thousand. For 2010, relates to lease maintenance costs and exploration overhead costs that were erroneously capitalized as oil and gas properties rather than expensed as exploration expense of $313 thousand and elimination of intrasegment revenue erroneously reported gross of related intrasegment expense of $786 thousand. |
(d) | Relates to elimination of intrasegment revenue erroneously reported gross of related intrasegment expense. |
(e) | Relates to the impact of (a) through (d) above. |
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December 31, 2011 | ||||||||||||||||||||
As Previously Reported | Adjustment | As RESTATED | Discontinued Operations | Currently Reported | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
Operating Segment Assets | ||||||||||||||||||||
Venezuela | $ | 348,802 | $ | — | $ | 348,802 | $ | — | $ | 348,802 | ||||||||||
Indonesia(a) | 65,165 | (50,572 | ) | 14,593 | — | 14,593 | ||||||||||||||
Gabon(a) | 119,273 | (63,768 | ) | 55,505 | — | 55,505 | ||||||||||||||
Oman(a) | 20,980 | (13,828 | ) | 7,152 | (7,152 | ) | — | |||||||||||||
United States(a) | 137,531 | 122,325 | 259,856 | — | 259,856 | |||||||||||||||
Discontinued operations | — | — | — | 7,152 | 7,152 | |||||||||||||||
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691,751 | (5,843 | ) | 685,908 | — | 685,908 | |||||||||||||||
Intersegment eliminations | (178,704 | ) | (1 | ) | (178,705 | ) | — | (178,705 | ) | |||||||||||
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Total Assets | $ | 513,047 | $ | (5,844 | ) | $ | 507,203 | $ | — | $ | 507,203 | |||||||||
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(a) | Relates to elimination of intrasegment receivables erroneously reported gross of related intrasegment payable. |
Venezuela
Harvest Vinccler’s and Petrodelta’s functional and reporting currency is the U.S. Dollar. They do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Venezuela Bolivars (“Bolivars”) (4.30 Bolivars per U.S. Dollar). However, during the year ended December 31, 2012, Harvest Vinccler exchanged approximately $1.5 million (2011: $1.2 million) through the Sistema de Transacciones con Títulos en Moneda Extranjera (“SITME”) and received an average exchange rate of 5.16 Bolivars (2011: 5.19 Bolivars) per U.S. Dollar. Harvest Vinccler currently does not have any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate. Petrodelta does not have, and has not had, any Bolivars pending government approval for settlement for U.S. Dollars at the official exchange rate or the SITME exchange rate.
The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. At December 31, 2012, the balances in Harvest Vinccler’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 6.2 million Bolivars and 5.7 million Bolivars, respectively. At December 31, 2012, the balances in Petrodelta’s Bolivar denominated monetary assets and liabilities accounts that are exposed to exchange rate changes are 277.2 million Bolivars and 2,646.2 million Bolivars, respectively.
On February 8, 2013, the Venezuelan government published in the Official Gazette the Exchange Agreement No. 14 which establishes new exchange rates for the Bolivar/U.S. Dollar currencies that became effective February 9, 2013. The exchange rate established in the Agreement is 6.30 Bolivars per U.S. Dollar. The Exchange Agreement also announced the elimination of SITME effective February 8, 2013. All exchanges of Bolivars must now transact through the Central Bank. As a result of the February 2013 devaluation, Harvest Vinccler estimates the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta estimates the impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities.
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On May 7, 2012, the Organic Law on Employment, Male and Female Workers (“Labor Law”) was published in the Official Gazette. The Labor Law has 554 Articles divided into ten Titles and heavily favors employees over employers. The Labor Law’s purpose is to regulate the relations between workers and employers. In August 2012, the labor contract between PDVSA and the labor union was signed. The new labor contract awarded salary increases to both union and non-union labor retroactive to December 2011. The new labor contract increased the effect of the Labor Law on Petrodelta by increasing the salaries on which the Labor Law benefits are calculated. Per the actuarial study that PDVSA commissioned, the effect of the Labor Law on Petrodelta’s business was $3.8 million ($1.2 million net to our 32 percent interest) for the year ended December 31, 2012. The Labor Law had no impact to Harvest Vinccler.
Petrodelta
SeeItem 1. Business, Operations, Petrodelta, Share Purchase Agreement (“SPA”).
Petrodelta’s shareholders intend that the company be self-funding and rely on internally-generated cash flow to fund operations. Petrodelta’s 2012 capital budget was expected to be approximately $401.9 million with a significant portion of that total related to infrastructure costs to support the further development of the Temblador and El Salto fields.
Petrodelta began 2012 with three drilling rigs, but PDVSA relocated one rig to another operation. Currently, Petrodelta is operating three drilling rigs and two workover rigs and is continuing with infrastructure enhancement projects in the El Salto and Temblador fields. A pipeline is currently under construction between the Isleño field and the main production facility at Uracoa. Isleño production is currently being trucked to Uracoa. Petrodelta has received two new drilling rigs. The first drilling rig is currently waiting on repairs and is expected to start drilling operations in the Isleño field in the first quarter of 2013. The second drilling rig has been mobilized and is expected to start drilling operations in the Temblador field in the first quarter of 2013. Petrodelta was notified that it will relocate a current operating rig to another operation with the old rig being replaced with a new rig which arrived in February 2013. These rigs result in an expected five working drilling rigs in 2013.
During the year ended December 31, 2012, Petrodelta drilled and completed 12 development wells compared to 15 development wells, one successful appraisal well and two water injector wells in the year ended December 31, 2011. Petrodelta delivered approximately 13.2 MBls of oil and 2.2 billion cubic feet (“Bcf”) of natural gas, averaging 36,979 barrels of oil equivalent (“BOE”) per day during the year ended December 31, 2012 compared to deliveries of 11.4 MBls of oil and 2.3 Bcf of natural gas, averaging 32,240 BOE per day during the year ended December 31, 2011.
Petrodelta’s Proved reserves, net to our 32 percent interest, are 38.4 MMBOE at December 31, 2012. Petrodelta’s Probable reserves, net to our 32 percent interest, are 61.8 MMBOE at December 31, 2012. Petrodelta’s Possible reserves, net to our 32 percent interest, are 104.4 MMBOE. Proved plus Probable reserves at 100.2 MMBOE, after accounting for current year production, are virtually unchanged from last year. SeeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies – Reserves for a definition of proved, probable and possible reserves and a discussion of the uncertainty related to such reserve estimates.
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Certain operating statistics for the years ended December 31, 2012, 2011, and 2010 for the Petrodelta fields operated by Petrodelta are set forth below. This information is provided at 100 percent.
December 31, | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Thousand barrels of oil sold | 13,172 | 11,390 | 8,561 | |||||||||
Million cubic feet of gas sold | 2,171 | 2,266 | 2,204 | |||||||||
Total thousand barrels of oil equivalent | 13,534 | 11,768 | 8,928 | |||||||||
Average price per barrel | $ | 95.91 | $ | 98.52 | $ | 70.57 | ||||||
Average price per thousand cubic feet | $ | 1.54 | $ | 1.54 | $ | 1.54 | ||||||
Cash operating costs ($millions)(a) | $ | 121.0 | $ | 77.2 | $ | 44.7 | ||||||
Capital expenditures ($millions) | $ | 184.2 | $ | 137.5 | $ | 98.7 |
(a) | SeeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Years Ended December 31, 2012 and 2011, Equity in Earnings from Equity Affiliates. |
Under Petrodelta’s Sales Contract, crude oil delivered from the Petrodelta fields to PPSA is priced with reference to Merey 16 published prices, weighted for different markets and adjusted for variations in gravity and sulphur content, commercialization costs and distortions that may occur given the reference price and prevailing market conditions. Merey 16 published prices are quoted and sold in U.S. Dollars. Natural gas delivered from the Petrodelta Fields to PDVSA is priced at $1.54 per thousand cubic feet. PPSA is obligated to make payment to Petrodelta in U.S. Dollars in the case of payment for crude oil and natural gas liquids delivered. Natural gas deliveries are paid in Bolivars, but the pricing for natural gas is referenced to the U.S. Dollar.
Production from the Petrodelta fields, except the El Salto field, flows through Petrodelta’s pipelines into PDVSA’s EPT-1 storage facility. Prior to October 2011, El Salto production was trucked to the EPT-1 storage facility and combined with the other Petrodelta fields’ production. Beginning October 2011, production from the El Salto field flows through PDVSA’s EPM-1 transfer point at PDVSA Morichal. Currently, the El Salto production flows through COMOR transfer point, a new transfer point for Petrodelta, at PDVSA Morichal.
When the Sales Contract was executed, Petrodelta was producing only one type of crude, Merey 16. The official pricing formula applied to the Merey 16 by MENPET is used for the sales of Petrodelta crude oil with quality close to 16 degrees API to represent actual quality delivered. Beginning in October 2011, MENPET determined that Petrodelta’s production flowing through the COMOR transfer point was a heavier type of crude, Boscan. The official pricing formula applied to Boscan by MENPET is used for the sales of Petrodelta crude oil with quality close to 10 degrees API to represent actual quality delivered.
Since Petrodelta was producing only Merey 16 when the Sales Contract was executed, the Boscan gravity and sulphur correction factors and crude pricing formula are not included in the Sales Contract. However, under the Sales Contract, PPSA is obligated to receive all of Petrodelta’s production. All production deliveries for all of Petrodelta’s fields have been certified by MENPET and acknowledged by PPSA. All pricing factors to be used in the Merey 16 and Boscan pricing formulas have been provided by and certified by MENPET to Petrodelta.
Since the Sales Contract provides for only one crude pricing formula, the Sales Contract had to be amended to include the Boscan pricing formula to allow Petrodelta to invoice PPSA for El Salto crude oil deliveries. From October 1, 2011 through June 30, 2012, Petrodelta used the Boscan pricing formula as published in the Official Gazette on January 11, 2007 to record revenue from El Salto field deliveries. Petrodelta subsequently received from PDVSA Trade and Supply a draft amendment to the Sales Contract. The pricing formula in the draft amendment was used to record revenue for El Salto field deliveries from July 1, 2012 through December 31, 2012, and revenue for El Salto field deliveries for October 1, 2011 through June 30, 2012 was revised to reflect the pricing formula in the draft amendment. The only item included in the draft amendment is the Boscan pricing formula to be used in invoicing El Salto crude oil deliveries. All other terms and conditions of the Sales Contract remain in force. On January 28, 2013, Petrodelta’s board of directors endorsed the amendment to the Sales Contract. The amendment has to be approved by CVP’s board of directors and HNR Finance’s board of directors. Once these approvals are received, the amendment to the Sales Contract will be executed and PPSA will be invoiced for the deliveries.
At December 31, 2012, El Salto deliveries, net of royalties, covering the delivery months of October 2011 through December 2012 totaled approximately 4.0 MBls (1.3 MBls net to our 32 percent interest). The draft
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amendment to the Sales Contract pricing formula for Boscan based upon the deliveries and factors certified by MENPET, results in revenue for these deliveries of $352.7 million ($112.9 million net to our 32 percent interest). As of December 31, 2012, these deliveries for El Salto remain uninvoiced to PPSA.
InItem 1A. Risk Factors, we disclosed that PDVSA’s failure to timely pay contractors, including Petrodelta, was having an adverse effect on Petrodelta. We have advanced certain costs on behalf of Petrodelta. These costs include consultants in engineering, drilling, operations and seismic interpretation, and employee salaries and related benefits for Harvest employees seconded into Petrodelta. Currently, we have three employees seconded into Petrodelta. Costs advanced are invoiced on a monthly basis to Petrodelta. We are considered a contractor to Petrodelta, and as such, we are also experiencing the slow payment of invoices. During the year ended December 31, 2012, we advanced Petrodelta $0.5 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Advances to equity affiliate has increased $0.4 million, to a balance of $2.8 million, during the year ended December 31, 2012. During the year ended December 31, 2011, we advanced Petrodelta $0.8 million for continuing operations costs, and Petrodelta repaid $0.1 million of the advances. Although payment is slow, payments continue to be received. Petrodelta and Petrodelta’s board have not indicated that the advances are not payable, nor that they will not be paid. As a Petrodelta contractor, Harvest Vinccler assessed the possibility of recording an allowance for doubtful accounts on its receivable from Petrodelta. After considering many factors, including the slow but continuous payments received from Petrodelta, Harvest Vinccler determined that an allowance for doubtful accounts is not required; however, at December 31, 2012, Harvest Vinccler reclassified $2.1 million of the Advances to Affiliate to a long-term receivable due to slow payment and age of the advances.
We are unable to provide an indication of when PDVSA will become and remain current in its payment obligations. However, we believe that PDVSA’s debt will not disappear completely in the short term, but the risk of contractor work stoppage is minimal due to PDVSA guaranteeing payments as publicly stated by top officials. Increased costs due to PDVSA’s debt financing are already imbedded in current contractor’s rates.
Petrodelta’s 2012 proposed capital expenditures were expected to be approximately $401.9 million and included a planned drilling program to utilize two rigs to drill both development and appraisal wells for maintaining production capacity, the continued appraisal of the substantial resource base in the El Salto field and further drilling in the Isleño field. It also included engineering work for production facilities required for the full development of the El Salto and Temblador fields. Due to insufficient monetary support and contractual adherence by PDVSA, Petrodelta incurred only $184.2 million of its 2012 proposed capital expenditures.
As of May 2, 2013, the 2013 budget for Petrodelta had not yet been approved by its shareholders. Since Petrodelta only executed approximately 45.8 percent of its 2012 planned capital expenditures primarily due to insufficient monetary support and contractual adherence by PDVSA, it is possible that PDVSA will not provide the support required to execute Petrodelta’s proposed 2013 budget. Should PDVSA continue in insufficient monetary support and contractual adherence of Petrodelta, underinvestment in the development plan may lead to continued under-performance. However, Petrodelta’s 2013 proposed budget includes a planned drilling program to utilize five rigs to drill both development and appraisal wells for maintaining production capacity and the continued appraisal of the substantial resource base in the El Salto, Temblador and Isleño fields. It also includes engineering work for continued infrastructure enhancement projects in El Salto and Temblador.
In April 2011, the Venezuelan government published in the Official Gazette the amended Windfall Profits Tax. In February 2013, the Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary prices (under $80 per barrel) and exorbitant prices (over $100 per barrel), and levels in-between, to the Venezuelan government. The amended Windfall Profits Tax is deductible for Venezuelan income tax purposes. During the year ended December 31, 2012, Petrodelta recorded $291.4 million for the amended Windfall Profits Tax (2011: $237.6 million).
One section of the Windfall Profits Tax states that royalties paid to Venezuela are capped at $70 per barrel, but the cap on royalties has not been defined as being applicable to in-cash, in-kind, or both. In October 2011, Petrodelta received instructions from PDVSA that royalties, whether paid in-cash or in-kind, should be reported at $70 per barrel (royalty barrels x $70). The difference between the $70 royalty cap and the current oil price is to be reflected on the income statement as a reduction in oil sales. For the year ended December 31, 2012, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $113.7 million ($36.4 million net to our 32 percent interest). For the year ended December 31, 2011, the reduction to oil sales due to the $70 cap applied to all royalty barrels was $85.0 million ($27.2 million net to our 32 percent interest).
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Per our interpretation of the Windfall Profits Tax, the $70 cap on royalty barrels should only be applied to the 3.33 percent royalty which Petrodelta pays in cash. With assistance from Petrodelta, we have recalculated Petrodelta’s oil sales and royalties to apply the current oil price to its total barrels produced and to the 30 percent royalty paid in-kind and applied the $70 cap to the 3.33 percent royalty paid in cash for the years ended December 31, 2012 and 2011. For the year ended December 30, 2012, net oil sales (oil sales less royalties) are slightly higher, $11.4 million ($3.6 million net to our 32 percent interest). For the year ended December 31, 2011, net oil sales are slightly higher, $8.5 million ($2.7 million net to our 32 percent interest) under this method than the method advised by PDVSA and the method of applying the current oil price to total barrels produced and to total royalty barrels.
Another section of the amended Windfall Profits Tax for which Petrodelta is waiting for clarity relates to an exemption of this tax that can be granted by the Ministry of the People’s Power for Petroleum and Mining (“MENPET”) for the incremental production of projects and grass root developments until the specific investments are recovered. This exemption has to be considered and approved in a case by case basis by MENPET. We believe several of the fields operated by Petrodelta may qualify for the exemption from the amended Windfall Profits Tax. We are waiting for clarification from MENPET on the definitions of incremental production and grass roots developments, as well as guidance on the process for applying for the exemption.
The Venezuelan government published in the Official Gazette an amendment to the Windfall Profits Tax with an effective date of February 20, 2013. The amended Windfall Profits Tax establishes new levels for contribution of extraordinary and exorbitant prices to the Venezuelan government. Extraordinary prices are considered to be equal to or lower than $80 per barrel, and exorbitant prices are considered to be over $80 per barrel. The amended Windfall Profits tax also sets a new royalty cap per barrel of $80. Contributions for extraordinary prices are 20 percent to be applied to the difference between the price fixed by the Venezuela budget for the relevant fiscal year (set at $55 per barrel for 2013) and $80 per barrel. Contributions for exorbitant prices are (1) 80 percent when the average price of the VEB exceeds $80 per barrel but is less than $100 per barrel; (2) 90 percent when the average price of the VEB equals or exceeds $100 per barrel but is less than $110 per barrel; and (3) 95 percent when the average price of the VEB equals or exceeds $110 per barrel.
On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). Petrodelta shareholder approval of the dividend was received on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, as of May 2, 2013, this dividend has not been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the uncertainty in the timing of payment. There is uncertainty with respect to the timing of the receipt of this dividend and whether future dividends will be declared or paid. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected or facts and circumstances surrounding our investment change, our results of operations and investment in Petrodelta could be adversely impacted.
The Organic Law on Sports, Physical Activity and Physical Education (“Sports Law”) was published in the Official Gazette on August 23, 2011. The purpose of the Sports Law is to establish the public service nature of physical education and the promotion, organization and administration of sports and physical activity. Funding of the Sports Law is by contributions made by companies or other public or private organizations that perform economic activities for profit in Venezuela. The contribution is one percent of annual net or accounting profit and is not deductible for income tax purposes. Per the Sports Law, contributions are to be calculated on an after-tax basis. However, CVP has instructed Petrodelta to calculate the contribution on a before-tax basis contrary to the Sports Law. For the year ended December 31, 2012, this method of calculation overstates the liability for the Sports Law contribution by $2.5 million ($0.8 million net to our 32 percent interest). We have adjusted for the overaccrual of the Sports Law in the December 31, 2012 Net Income from Equity Affiliate.
Petrodelta’s results and operating information is more fully described inItem 15. Exhibits and Financial Statement Schedules, Notes to the Consolidated Financial Statements, Note 13 – Investment in Equity Affiliates – Petrodelta, S.A.
Diversification
We have broadened our strategy from our primary focus on Venezuela to identify, access and integrate hydrocarbon assets to include organic growth through exploration in basins globally with proven hydrocarbon systems. We seek to leverage our Venezuelan experience as well as our recently expanded business development and technical platform to create a diversified resource base. With the addition of technical resources through the
11
opening of our London and Singapore offices, we have made significant investments to provide the necessary foundation and global reach required for an organic growth focus. Our organic growth is focused on undeveloped or underdeveloped fields, field redevelopments and exploration. While exploration has become a larger part of our overall portfolio, we generally restrict ourselves to basins with known hydrocarbon systems and favorable risk-reward profiles. Exploration will be technically driven with a low entry cost and high resource potential that provides sustainable growth.
Budong-Budong Project, Indonesia
SeeItem 1. Business, Operations, Budong-Budong, Onshore Indonesia.
The initial exploration term of the Budong PSC was due to expire on January 15, 2013. In September 2012, the operator of the Budong PSC, on behalf of us and the other co-venturer, submitted a request to BPMIGAS under the terms of the Budong PSC for a four-year extension of the initial six-year exploration term of the Budong PSC. In January 2013, we received written approval from SKK Migas of the four-year extension of the initial six-year exploration term.
In November 2012, the Indonesia constitutional court declared BPMIGAS, Indonesia’s oil and gas regulatory authority, to be unconstitutional. In January 2013, SKK Migas, the Special Task Force for oil and gas upstream sector, was formed to replace BPMIGAS. SKK Migas will supervise all oil and gas industry activities.
In December 2012, we signed a farmout agreement with the operator of the Budong PSC to acquire an additional 7.1 percent participating interest and to become operator of the Budong PSC. We assumed the role of interim operator effective January 16, 2013. Closing of this acquisition will increase our participating ownership interest in the Budong PSC to 71.5 percent with our cost sharing interest becoming 72 percent until first commercial production. The consideration for this transaction is that we will fund 100 percent of the costs of the first exploration well of the four-year extension to the Budong PSC. If the exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, our partner has the right to give notice that the consideration be paid in cash, or $3.2 million. The transfer of operatorship was approved by SKK Migas on March 25, 2013. The acquisition of the additional participating interest was approved by the Government of Indonesia on April 9, 2013.
We have satisfied all work commitments for the current exploration phase of the Budong PSC. However, the extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC.
Pursuant to the request for extension of the initial exploration term, the contract area held by the Budong PSC at the beginning of the extension period should be reduced, per the terms of the Budong PSC, from the current 55 percent to 20 percent of the original contract area. In January 2013, our partner, on our behalf, submitted a relinquishment proposal of 10 percent to SKK Migas. The retained area will contain all the areas of geological interest to the Budong PSC partners.
Operational activities during the year ended 2012 included a review of geological and geophysical data obtained from the drilling of LG-1 and KD-1 wells to upgrade the prospectivity of the block and to define a prospect for potential drilling in 2013. Based on multiple oil and gas shows encountered in both LG-1 and KD-1, we are working on an exploration program targeting the Pliocene and Miocene sands encountered in the previous two wells. We have completed remapping of both the Lariang and Karama Basins with eight leads in the Lariang Basin and five leads in the Karama Basin having been identified in the Pliocene, Middle-Late Miocene and Eocene sands. The identification of these leads is the basis for the four-year extension request of the first six-year exploration term. The partners have technically recommended the drilling of the Madjene prospect in the Lariang Basin targeting stacked Pliocene and Miocene clastic reservoirs for an exploration well in late 2013. Preliminary well planning activities commenced in October 2012.
During the year ended December 31, 2012, we had cash capital expenditures of $5.8 million mainly for deepening and plugging and abandonment costs of KD-1ST (2011: $18.2 million for drilling, construction and plugging and abandonment costs and $3.7 million for the purchase of the additional 10 percent equity interest). The 2013 budget for the Budong PSC is $13.9 million.
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Dussafu Project – Gabon
SeeItem 1. Business, Operations, Dussafu Marin, Offshore Gabon.
The Dussafu PSC partners and the Republic of Gabon, entered into the third exploration phase of the Dussafu PSC with an effective date of May 28, 2012. The DGH agreed to lengthen the third exploration phase to four years until May 27, 2016. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1.
Operational activities during 2012 included completion of the time processing of 545 square kilometers of seismic which was acquired in the fourth quarter of 2011 and well planning. The 3-D Pre-Stack Time Migration was completed in July 2012. Pre-Stack Depth processing and reprocessing of the 2005 Inboard 3-D seismic of approximately 1,300 square kilometers commenced in June 2012 with the time reprocessing and merging of the various 3-D surveys completed in September 2012. Initial velocity model building for the Pre-Stack Depth migration commenced and the Pre-Stack Depth processing project is expected to be completed in the second quarter of 2013.
Well planning progressed to drill an exploration well in the fourth quarter of 2012 on the Tortue prospect to target stacked pre-salt Gamba and Dentale reservoirs as well as a secondary post-salt Madiela clastic reservoir. DTM-1 was spud on November 19, 2012. DTM-1 was drilled with the Scarabeo 3 semi-submersible drilling unit, and was drilled in a water depth of 380 feet. On January 4, 2013, we announced that DTM-1 had reached a vertical depth of 11,260 feet within the Dental Formation. Log evaluation and pressure data indicate that we have an oil discovery of approximately 42 feet of pay in a 72 foot column within the Gamba Formation and 123 feet of pay in stacked reservoirs within the Dentale Formation. Additional technical evaluation is on-going.
The first appraisal sidetrack of DTM-1 (“DTM-1ST1”) spud January 12, 2013. DTM-1ST1 was drilled to a Total Depth of 11,385 feet in the Dental Formation, approximately 1,800 feet from DTM-1 wellbore and found 65 feet of pay in the primary Dentale reservoir. Several other stacked sands with oil shows were encountered; however, due to a stuck downhole tool, logging operations were terminated early before pressure data could be collected to confirm connectivity. The well can be re-entered, and the downhole tool has since been retrieved. DTM-1 and DTM-1ST1 were suspended pending future appraisal and development activities. The drilling rig was demobilized and released on February 21, 2013.
During the year ended December 31, 2012, we had cash capital expenditures of $11.7 million for seismic processing (2011: $40.1 million for well planning and drilling). The 2013 budget for the Dussafu PSC is $26.2 million.
Block 64 EPSA Project – Oman
SeeItem 1. Business, Operations, Block 64 EPSA, Oman.
Both the work and financial commitments on Block 64 EPSA have been fulfilled. Operational activities during the year ended December 31, 2012 included post well evaluation and review of geological and geophysical data obtained from the drilling of MFS-1 and AGN-1 wells. On March 12, 2013, we elected to not request an extension of the First Phase or enter the Second Phase of Block 64 EPSA and Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was considered to be impaired and a related impairment expense was recorded at December 31, 2012.
During the year ended December 31, 2012, we incurred $6.1 million for drilling and plugging and abandonment costs (2011: $10.2 million for well planning, drilling and plugging and abandonment costs). The 2013 budget for Block 64 EPSA is minimal, consisting of costs required to terminate operations and close the field office. Operations were terminated, and the field office was closed May 31, 2013. All activities associated with Oman have been reflected as discontinued operations in the accompanying financial statements.
WAB-21 Project – China
SeeItem 1. Business, Operations, WAB-21, South China Sea.
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In March 2011, CNOOC granted us an extension to May 2013 of Phase One of the Exploration Period for the WAB-21 contract area. The Joint Management Committee has approved an extension of the license until May 31, 2015. We are meeting with CNOOC in April 2013 to discuss the ratification of the extension. While no assurance can be given, we believe we will continue to receive contract extensions so long as the border disputes with Vietnam persist. Even though there continues to be increasing activity on the Vietnamese blocks which we believe confirms our view of WAB-21’s prospectivity, we impaired the carrying value of WAB-21 of $2.9 million at December 31, 2012 due to our continued inability to pursue an exploration program. However, we continue to seek permission to acquire regional 2-D seismic and localized 3-D seismic.
Operational activities during 2012 include costs related to maintenance of the license. The 2013 budget for WAB 21 is minimal, consisting of costs required to maintain the license.
Other Exploration Projects
The 2013 budget for new business development is $2.7 million.
Business Strategy
InItem 1. Business andItem 1A. Risk Factors, we discuss the situation in Venezuela and how the actions of the Venezuelan government have and continue to adversely affect our operations. The expectation that dividends from Petrodelta will be minimal over the next two years has restricted our available cash and had a significant adverse effect on our ability to obtain financing to acquire and develop growth opportunities elsewhere.
We will use our available cash and future access to capital markets to expand our diversified strategy in a number of countries that fit our strategic investment criteria. In executing our business strategy, we will strive to:
• | maintain financial prudence and rigorous investment criteria; |
• | access capital markets; |
• | continue to create a diversified portfolio of assets; |
• | preserve our financial flexibility; |
• | use our experience and skills to acquire new projects; and |
• | keep our organizational capabilities in line with our rate of growth. |
To accomplish our strategy, we intend to:
• | Diversify our Political Risk:Acquire oil and natural gas fields in a number of countries to diversify and reduce the overall political risk of our investment portfolio. |
• | Seek Operational and Financial Control: We desire control of major decisions for development, production, staffing and financing for each project for a period of time sufficient for us to ensure maximum returns on investments. |
• | Establish a Presence Through Joint Venture Partners and the Use of Local Personnel: We seek to establish a presence in the countries and areas we operate through joint venture partners to facilitate stronger governmental and business relationships. In addition, we use local personnel to help us take advantage of local knowledge and experience and to minimize costs. |
• | Commit Capital in a Phased Manner to Limit Total Commitments at Any One Time: We are willing to agree to minimum capital expenditures or development commitments at the outset of new projects, but we endeavor to structure such commitments to fulfill them over time under a prudent plan of development, allowing near-term operating cash flow to help fund further investment, thereby limiting our maximum cash exposure. We also seek to maximize available local financing capacity to develop the hydrocarbons and associated infrastructure. |
• | Provide Technical Expertise: We believe there is an advantage in being able to provide geological, geophysical and engineering expertise beyond what many companies or countries possess internally. |
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• | Maintain a Prudent Financing Plan: We intend to maintain our financial flexibility by closely monitoring spending, holding sufficient cash reserves, minimizing the use of restricted cash, actively seeking opportunities to reduce our weighted average cost of capital and increase our access to debt and equity markets. |
• | Manage Exploration Risks: We seek to manage the higher risk of exploration by diversifying our prospect portfolio, applying state-of-the-art technology for analyzing targets and focusing on opportunities in proven active hydrocarbon systems with infrastructure. |
• | Establish Various Sources of Production: We seek to establish new production from our exploration and development efforts in a number of diverse markets and expect to monetize production through operations or the farm-down or possible sale of assets. |
Results of Operations
The following discussion should be read with the results of operations for each of the years in the three-year period ended December 31, 2012 and the financial condition as of December 31, 2012 and 2011 in conjunction with our consolidated financial statements and related notes thereto.
Years Ended December 31, 2012 and 2011
We reported a net loss attributable to Harvest of $12.2 million, or $(0.33) diluted earnings per share, for the year ended December 31, 2012, compared with net income attributable to Harvest of $56.0 million, or $1.64 diluted earnings per share, for the year ended December 31, 2011.
Total expenses and other non-operating (income) expense (in millions):
Year Ended December 31, | ||||||||||||
2012 | 2011 (RESTATED) | Increase (Decrease) | ||||||||||
Depreciation and amortization | $ | 0.4 | $ | 0.4 | $ | — | ||||||
Exploration expense | 8.8 | 12.0 | (3.2 | ) | ||||||||
Impairment expense | 2.9 | 3.3 | (0.4 | ) | ||||||||
Dry hole costs | 0.7 | 40.0 | (39.3 | ) | ||||||||
General and administrative | 26.0 | 21.4 | 4.6 | |||||||||
Investment earnings and other | (0.3 | ) | (0.7 | ) | 0.4 | |||||||
Unrealized (gain) loss on warrant derivatives | 0.6 | (9.8 | ) | 10.4 | ||||||||
Interest expense | 1.6 | 7.2 | (5.6 | ) | ||||||||
Debt conversion expense | 3.6 | — | 3.6 | |||||||||
Loss on extinguishment of debt | 5.4 | 13.1 | (7.7 | ) | ||||||||
Other non-operating expense | 2.9 | 1.4 | 1.5 | |||||||||
Loss on exchange rates | 0.1 | 0.1 | — | |||||||||
Income tax expense (benefit) | (0.6 | ) | 1.1 | (1.7 | ) |
Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2012, we incurred $4.5 million of exploration costs for the processing and reprocessing of seismic data related to ongoing operations, $2.5 million related to other general business development activities, and $1.8 million related to lease maintenance. During the year ended December 31, 2011, we incurred $9.5 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $2.2 million related to lease maintenance.
During the year ended December 31, 2012, we impaired $2.9 million related to the carrying value of WAB-21. During the year ended December 31, 2011, we impaired $3.3 million related to the carrying value of West Bay.
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During the year ended December 31, 2012, we expensed to dry hole costs $0.7 million related to the drilling of the KD-1 well on the Budong PSC. During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on Budong PSC and $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC. SeeItem 1. Business, Operations, Budong-Budong, Onshore Indonesia – Drilling and Development Activity.
The increase in general and administrative costs in the year ended December 31, 2012 from the year ended December 31, 2011, was primarily due to increases in employee related costs ($3.3 million, of which $2.2 million was non-cash related to equity compensation), public relations ($0.1 million) and audit fees ($2.0 million) offset by a decrease in general office expense and overhead ($0.4 million), contract services ($0.2 million) and travel costs ($0.2 million).
The decrease in investment earnings and other in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the receipt during the year ended December 31, 2011 of payment for transition services provided on the Antelope Project after closing of the sale.
The decrease in unrealized gain on warrant derivatives in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the change in fair value for our warrant derivative liabilities: $3.18 per warrant at December 31, 2012 and $3.04 per warrant at December 31, 2011.
The decrease in interest expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to the conversion of $31.5 million of our 8.25 percent senior convertible notes in the year ended December 31, 2012, offset by our $79.8 million senior unsecure note offering in October 2012, repayment in May 2011 of our $60 million term loan facility, and interest capitalized to oil and gas properties of $3.0 million.
During the year ended December 31, 2012, we incurred debt conversion expense of $2.9 million related to the issuance of 0.4 million common shares issued as an inducement for completing the exchange and legal and other professional fees ($0.7 million).
During the year ended December 31, 2012, we incurred a loss on extinguishment of debt of $5.4 million related to the early conversion of our 8.25 percent senior convertible notes. The loss on extinguishment of debt includes the difference between the carrying value of the 8.25 percent senior convertible notes and the amount received for the 11 percent senior unsecured notes ($5.0 million), expensing of deferred financing costs related to the 8.25 percent senior convertible notes ($0.1 million) and issuance of 30,000 shares of Harvest common stock issued in exchange for a waiver agreement ($0.3 million). During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.4 million), and the cost to redeem 4.4 million unvested warrants issued in connection with the term loan facility.
The loss on exchange rates for the year ended December 31, 2012 was consistent with the year ended December 31, 2011.
The increase in other non-operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the SPA for the sale of our 32 percent interest in Petrodelta.
The change in income tax expense in the year ended December 31, 2012 from the year ended December 31, 2011 is due to a net operating loss incurred in 2012 while we had taxable income in 2011 as a result of the sale of interest in the Antelope Project.
Equity in Earnings from Equity Affiliates
For the year ended December 31, 2012, net income from equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes ($170.8 million) offset by lower prices ($29.6 million). Royalties, which is a function of revenue, increased $49.0 million due to the increase in revenue (net increase in revenue of $141.2 million at 30 percent royalty). Windfall Profits Tax, which is a function of volume and price received per barrel, increased $53.8 million due to an increase in volumes (2012: 13.2 MBls vs.
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2011: 11.4 MBls) offset by lower price received per barrel (2012: $95.91 per barrel vs. 2011: $98.52 per barrel). The increase in operating expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to increased oil production and also includes $3.8 million of additional expense related to the labor law which was recorded in December 2012. The decrease in workover expense in the year ended December 31, 2012 from the year ended December 31, 2011 was due to fewer workovers being performed. Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from equity affiliate) for the year ended December 31, 2012 was not materially different with the effective tax rate for the year ended December 31, 2011.
Discontinued Operations
As a result of the decision to not request an extension of the First Phase or enter the Second Phase of the Block 64 EPSA, Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. Operations in Oman were terminated, and the field office was closed May 31, 2013. We have no continuing involvement in Oman. The net loss of $12.7 million from our Oman operations for the year ended December 31, 2012 included $6.4 million related impairment expense, $4.9 million related to dry hole costs and $1.1 million of general and administrative expenses. The net loss of $11.4 million for the year ended December 31, 2011 included $9.7 million of dry hole costs and $1.0 million of general and administrative expenses.
On May 17, 2011, we closed the transaction to sell the Antelope Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in discontinued operations in the second quarter of 2011.
During the year ended December 31, 2012, we incurred $0.1 million of expense related to settlement of royalty payments to the Mineral Management Services and write-offs of $5.2 million of accounts and note receivable and $3.6 million of accounts payable and carry obligation related to the settlement of all outstanding claims with a private third party on the Antelope Project. SeeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 3 – Summary of Significant Accounting Policies, Notes Receivable.
Oman operations and the Antelope Project have been classified as discontinued operations. Net loss on the dispositions is shown in the table below:
Years Ended December 31, | ||||||||
2012 | 2011 | |||||||
(in thousands) | ||||||||
Revenue applicable to discontinued operations: | ||||||||
Oman operations | $ | — | $ | — | ||||
Antelope Project | — | 6,488 | ||||||
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Revenue from discontinued operations | $ | — | $ | 6,488 | ||||
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Net income (loss) from discontinued operations: | ||||||||
Oman operations | $ | (12,711 | ) | $ | (11,371 | ) | ||
Antelope Project | (1,699 | ) | 97,616 | |||||
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Net income (loss) from discontinued operations | $ | (14,410 | ) | $ | 86,245 | |||
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Years Ended December 31, 2011 and 2010
We reported net income attributable to Harvest of $56.0 million, or $1.64 diluted earnings per share, for the year ended December 31, 2011, compared with net income attributable to Harvest of $14.4 million, or $0.39 diluted earnings per share, for the year ended December 31, 2010.
Total expenses and other non-operating (income) expense (in millions):
Year Ended December 31, | Increase (Decrease) | |||||||||||
2011 (RESTATED) | 2010 (RESTATED) | |||||||||||
Depreciation and amortization | $ | 0.4 | $ | 0.5 | $ | (0.1 | ) | |||||
Exploration expense | 12.0 | 7.1 | 4.9 | |||||||||
Impairment expense | 3.3 | — | 3.3 | |||||||||
Dry hole costs | 40.0 | — | 40.0 | |||||||||
General and administrative | 21.4 | 25.2 | (3.8 | ) | ||||||||
Investment earnings and other | (0.7 | ) | (0.6 | ) | (0.1 | ) | ||||||
Unrealized gain on warrant derivatives | (9.8 | ) | (0.3 | ) | (9.5 | ) | ||||||
Interest expense | 7.2 | 3.8 | 3.4 | |||||||||
Loss on extinguishment of debt | 13.1 | — | 13.1 | |||||||||
Other non-operating expense | 1.4 | 4.0 | (2.6 | ) | ||||||||
Loss on exchange rates | 0.1 | 1.6 | (1.5 | ) | ||||||||
Income tax expense (benefit) | 1.1 | (0.2 | ) | 1.3 |
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Our accounting method for oil and gas properties is the successful efforts method. During the year ended December 31, 2011, we incurred $9.5 million of exploration costs for the acquisition, processing and reprocessing of seismic data related to ongoing operations, $0.3 million related to other general business development activities, and $2.2 million related to lease maintenance. During the year ended December 31, 2010, we incurred $5.2 million of exploration costs for seismic, geological and geophysical, $1.6 million related to other general business development activities and $0.3 million related to lease maintenance. Included in the $5.2 million of exploration costs is the one-time charge of $1.2 million for acquisition of seismic data for the Budong PSC related to our partner in the Budong PSC exercising their option to increase the carry obligation.
During the year ended December 31, 2011, we impaired $3.3 million related to the carrying value of West Bay. During the year ended December 31, 2010, we did not impair any oil and gas properties costs.
During the year ended December 31, 2011, we expensed to dry hole costs $14.0 million related to the drilling of the LG-1 on the Budong PSC and $26.0 million related to the drilling of the KD-1 and KD-1ST on the Budong PSC. SeeItem 1. Business, Operations, Budong-Budong, Onshore Indonesia – Drillingand Development Activity.
The decrease in general and administrative costs in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to lower general office expense and overhead ($2.4 million), employee related costs ($1.5 million) and public relations ($0.3 million) offset by higher travel costs ($0.3 million) and contract services ($0.1 million). The employee related costs include $0.5 million of special consideration bonuses related to the sale of our Antelope Project.
The increase in investment earnings and other in the year ended December 31, 2011 from the year ended December 31, 2010 was due to income earned on transition services provided on the Antelope Project after closing of the sale.
The increase in unrealized gain on warrant derivative in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the change in fair value for our warrant derivative liabilities: $3.04 per warrant at December 31, 2011 and $7.37 weighted average price per warrant at December 31, 2010.
The increase in interest expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to the interest associated with our $32 million convertible debt offering in February 2010, our $60 million term loan facility occurring in October 2010 and amortization of discount on the term loan facility related to the warrants issued in connection with the $60 million term loan facility offset by interest capitalized to oil and gas properties of $2.3 million.
During the year ended December 31, 2011, we incurred a loss on extinguishment of debt related to early payment of our $60 million term loan facility. The loss on extinguishment of debt includes the write off of the discount on debt ($10.6 million), prepayment premium of 3.5 percent of the amount outstanding ($2.1 million), expensing of financing costs related to the term loan facility ($0.4 million), and the cost to redeem 4.4 million unvested warrants issued in connection with the term loan facility.
The decrease in loss on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 is due to the Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. There was no Bolivar/U.S. Dollar exchange rate devaluations in the year ended December 31, 2011.
The decrease in other non-operating expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to costs incurred related to our strategic alternative process and evaluation which resulted in the sale of our Antelope Project.
The increase in income tax expense in the year ended December 31, 2011 from the year ended December 31, 2010 was due to higher income tax assessed in 2011 in the Netherlands offset by a U.S. tax refund received in 2010.
For the year ended December 31, 2011, net income from equity affiliates reflects an increase in Petrodelta’s revenue from oil sales due to higher sales volumes and prices which was partially offset by
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the amended Windfall Profits Tax. The increase in operating expense and workovers in the year ended December 31, 2011 from the year ended December 31, 2010 was due to increased oil production and having a workover rig on location for the full year of 2011. Petrodelta took possession of the workover rig in September 2010 and operated it for only four months in the year ending December 31, 2010. The decrease in gain on exchange rates in the year ended December 31, 2011 from the year ended December 31, 2010 was due to there not being a Bolivar/U.S. Dollar currency exchange rate devaluation during 2011. There was a Bolivar/U.S. Dollar currency exchange rate devaluation announced on January 8, 2010. The decrease in Petrodelta’s effective tax rate (inclusive of the adjustments to reconcile to reported net income from equity affiliate) in the year ended December 31, 2011 from the year ended December 31, 2010 was primarily due to the tax effects of the currency devaluation in 2010 partially offset by an increase in current tax on increased earnings.
At December 31, 2009, we fully impaired the carrying value of our equity investment in Fusion. Accordingly, we did not record net losses incurred by Fusion of $0.2 million ($0.1 million net to our 49 percent interest) in the year ended December 31, 2011 (2010: $2.4 million [$1.2 million net to our 49 percent interest]), as doing so would have caused our equity investment to go into a negative position. However, we have recognized a $1.4 million gain on the sale of Fusion in the year ended December 31, 2011.
Discontinued Operations
As a result of the decision to not request an extension of the First Phase or enter the Second Phase of the Block 64 EPSA, Block 64 was relinquished effective May 23, 2013. The carrying value of Block 64 EPSA of $6.4 million was written off to impairment expense at December 31, 2012. Operations in Oman were terminated, and the field office was closed May 31, 2013. We have no continuing involvement in Oman. The net loss of $11.4 million from our Oman operations for the year ended December 31, 2011 included $9.7 million of dry hole costs and $1.0 million of general and administrative expenses. The net loss of $2.0 million for the year ended December 31, 2010 included $1.2 million of exploration expense and $0.7 million of general and administrative expenses.
On May 17, 2011, we closed the transaction to sell our Antelope Project. The sale had an effective date of March 1, 2011. We received cash proceeds of approximately $217.8 million which reflects increases to the purchase price for customary adjustments and deductions for transaction related costs. We do not have any continuing involvement with the Antelope Project. The related gain on the sale was reported in the second quarter of 2011.
Oman operations and the Antelope Project have been classified as discontinued operations. Net loss on the dispositions is shown in the table below:
Years Ended December 31, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Revenue applicable to discontinued operations: | ||||||||
Oman operations | $ | — | $ | — | ||||
Antelope Project | 6,488 | 10,696 | ||||||
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Revenue from discontinued operations | $ | 6,488 | $ | 10,696 | ||||
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Net income (loss) from discontinued operations: | ||||||||
Oman operations | $ | (11,371 | ) | $ | (1,952 | ) | ||
Antelope Project | 97,616 | 3,712 | ||||||
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Net income (loss) from discontinued operations | $ | 86,245 | $ | 1,760 | ||||
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Net income from discontinued operations for the year ended December 31, 2011 includes $106.0 million gain on the sale of our Antelope Project, $3.8 million for employee severance and special accomplishment bonuses, and $5.7 million of U.S. income tax related to the sale of our Antelope Project. Severance costs for key employees include 58,000 stock appreciation rights (“SAR”) granted at an exercise price of $4.595 per SAR. These SARs are exercisable by the key employee for up to one year after termination.
Risks, Uncertainties, Capital Resources and Liquidity
Our financial statements for the year ended December 31, 2012 have been prepared under the assumption that we will continue as a going concern. Our independent registered public accounting firm has included in their audit report an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Our current capital resources may not be sufficient to support our liquidity requirements through 2013. However, we believe certain cost reduction measures could be put into place which would not jeopardize our operations and future growth plans. In addition, we could delay the discretionary portion of our capital spending to future periods and/or sell or farm down assets as necessary to maintain the liquidity required to run our operations, as warranted. There are no assurances that we will be successful in selling or farming-down our assets.
Our ability to continue as a going concern depends upon the success of our planned exploration and development activities and the ability to secure additional financing as needed to fund our current operations. There can be no guarantee of future capital acquisition, fundraising or exploration success or that we will realize the
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value of our unevaluated exploratory well costs. We believe that we will continue to be successful in securing any funds necessary to continue as a going concern. However, our current cash position and our ability to access additional capital may limit our available opportunities or not provide sufficient cash for operations.
We may be able to meet future liquidity needs through the issuance of additional equity securities, and/or short or long-term debt financing, although there can be no assurance that such financing will be available to us or on terms that are acceptable to us, farm-downs or possible sales of assets.
The long-term continuation of our business plan through 2013 and beyond is dependent upon the generation of sufficient cash flow to offset expenses. We will be required to obtain additional funding through public or private financing, farm-downs, further reduce operating costs, and/or possible sales of assets. Failure to generate sufficient cash flow by raising additional capital through debt or equity financings, reducing operating costs, or by farm-downs and/or selling of assets further could have a material adverse effect on our ability to meet our short- and long-term liquidity needs and achieve our intended long-term business objectives.
The oil and gas industry is a highly capital intensive and cyclical business with unique operating and financial risks. InItem 1A. Risk Factors, we discuss a number of variables and risks related to our exploration projects and our minority equity investment in Petrodelta that could significantly utilize our cash balances, affect our capital resources and liquidity.
The environments in which we operate are often difficult and the ability to operate successfully depends on a number of factors including our ability to control the pace of development, our ability to apply “best practices” in drilling and development, and the fostering of productive and transparent relationships with local partners, the local community and governmental authorities. Financial risks include our ability to control costs and attract financing for our projects. In addition, often the legal systems of certain countries are not mature and their reliability can be uncertain. This may affect our ability to enforce contracts and achieve certainty in our rights to develop and operate oil and natural gas projects, as well as our ability to obtain adequate compensation for any resulting losses. Our strategy depends on our ability to have significant influence over operations and financial control.
Our operations are subject to various risks inherent in foreign operations. These risks may include, among other things, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection, civil unrest, strikes and other political risks, increases in taxes and governmental royalties, being subject to foreign laws, legal systems and the exclusive jurisdiction of foreign courts or tribunals, renegotiation of contracts with governmental entities, changes in laws and policies, including taxes, governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations. Our international operations may also be adversely affected by the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws, laws and policies of the United States affecting foreign policy, foreign trade, taxation and the possible inability to subject foreign persons to the jurisdiction of the courts in the United States.
There are also a number of variables and risks related to our minority equity investment in Petrodelta that could significantly utilize our cash balances, and affect our capital resources and liquidity. Petrodelta’s capital commitments are determined by its business plan, and Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. The total capital required to develop the fields in Venezuela may exceed Petrodelta’s available cash and financing capabilities, and there may be operational or contractual consequences due to this inability. Petrodelta’s ability to fully develop the fields in Venezuela will require a significant investment. Due to PDVSA’s liquidity constraints, PDVSA has not been providing the necessary monetary support and contractual adherence required by Petrodelta. If we are called upon to fund our share of Petrodelta’s operations, our failure to do so could be considered a default under the Conversion Contract and cause the forfeiture of some or all our shares in Petrodelta.
Petrodelta currently represents our only source of earnings. Petrodelta also has a material impact on our results of operations for any quarter or annual reporting period. SeeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 13 – Investment in Equity Affiliate – Petrodelta, S.A. Petrodelta operates under a business plan, the success of which relies heavily on the market price of oil. To the extent that market prices of oil decline, the business plan, and thus our equity investment and/or operations and/or profitability, could be adversely affected.
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Operations in Venezuela are subject to various risks inherent in foreign operations. It is possible the legal or fiscal framework for Petrodelta could change and the Venezuela government may not honor its commitments. Our ability to implement or influence Petrodelta’s business plan, assure quality control and set the timing and pace of development could also be adversely impacted. No assurance can be provided that events beyond our control will not adversely affect the value of our minority investment in Petrodelta.
Historically, our primary ongoing source of cash has been dividends from Petrodelta and the sale of oil and gas properties. SeeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 5 – Dispositions – Discontinued Operations. Currently, our source of cash is expected to be generated by accessing debt and/or equity markets, farm-downs, or possible sales of assets.
In the event that a sale of assets (farm-outs are not included in the definition of a sale of assets in the indenture) for more than $5.0 million in the aggregate occurs, we are required to offer to all noteholders of our 11 percent senior unsecured notes to purchase the maximum principal amount of our 11 percent senior unsecured notes that may be purchased out of the sale proceeds at an offer price in cash in an amount equal to 105.5 percent of the principal amount plus accrued and unpaid interest, if any. In the event of a change in control or a sale of Petrodelta, the noteholders of our 11 percent senior unsecured notes have the right to require us to repurchase all or any part of the 11 percent senior unsecured notes at a repurchase price equal to 101 percent in the case of a change in control or 105.5 percent in the case of a sale of Petrodelta plus accrued interest. We assessed the prepayment requirements and concluded they qualified as an embedded derivative. We considered the probabilities of these events occurring and determined that the derivative had an immaterial value at December 31, 2012.
Between Petrodelta’s formation in October 2007 and June 2010, Petrodelta declared and paid dividends of $105.5 million to HNR Finance, B.V. (“HNR Finance”), a wholly owned subsidiary of Harvest Holding ($84.4 million net to our 32 percent interest). On November 12, 2010, Petrodelta’s board of directors declared a dividend of $30.6 million, $12.2 million net to HNR Finance ($9.8 million net to our 32 percent interest). The dividend was ratified by Petrodelta’s shareholders on March 14, 2011. Due to Petrodelta’s liquidity constraints caused by PDVSA’s insufficient monetary support and contractual adherence, this dividend has not yet been received, although it is due and payable. Petrodelta’s board of directors declared this dividend and has never indicated that the dividend is not payable, nor that it will not be paid. The dividend receivable is classified as a long-term receivable at December 31, 2012 due to the uncertainty in the timing of payment. There is uncertainty whether Petrodelta will declare and/or pay additional dividends in the future. SeeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 18 – Related Party Transactions for a discussion of our obligations to our non-controlling interest holder, Vinccler, for any dividend received from Petrodelta. We have and will continue to monitor our investment in Petrodelta. Should the dividend receivable not be collected, or facts and circumstances surrounding our investment change, our results of operations and our investment in Petrodelta could be adversely impacted.
Our cash is being used to fund oil and gas exploration projects, debt, interest, and general and administrative costs. We require capital principally to fund the exploration and development of new oil and gas properties. As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. We entered the third exploration phase of the Dussafu PSC on May 28, 2012. The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1. SeeItem 1. Business, Operations, Dussafu Marin, Offshore Gabon – General. In January 2013, the Budong PSC partners were granted a four year extension of the initial six year exploration term of the Budong PSC to January 15, 2016. The extension of the initial exploration term includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC $3.2 million. SeeItem 1. Business, Operations, Budong-Budong, Onshore Indonesia – General. The Budong PSC work commitments are discretionary, and we have the ability to control the pace of expenditures.
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In March 2012, we announced that we had entered into an equity distribution agreement with Knight Capital America, L.P., a subsidiary of Knight Capital Group, Inc., relating to an “at-the-market” (“ATM”) offering of shares of our common stock. Due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012, we are not eligible to use a Form S-3 Registration Statement; therefore, we can no longer access our ATM.
Accumulated Undistributed Earnings of Foreign Subsidiaries
As of December 31, 2012, the book-tax outside basis difference in our foreign subsidiary that has been indefinitely reinvested was approximately $331 million. No U.S. taxes have been recorded on these earnings. In general, it is our practice and intention to reinvest the earnings of our non-U.S. subsidiaries in those operations. All of our current exploration activity is outside of the U.S. We currently intend to utilize our unremitted foreign earnings to fund international projects, including the development of our properties in Gabon, Indonesia and South America.
Under ASC 740-30-25-17, no deferred tax liability must be recorded if sufficient evidence shows that the subsidiary has invested or will invest the undistributed earnings or that the earnings will be remitted in a tax-free manner. Management must consider numerous factors in determining timing and amounts of possible future distribution of these earnings to the parent company and whether a U.S. deferred tax liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company and the subsidiaries, remittance restrictions imposed by foreign governments or financial agreements and tax consequences of the remittance, including possible application of U.S. foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue Service (“IRS”) or IRS regulations.
If we were to make a distribution of our foreign earnings in the form of dividends, we would likely be subject to U.S. income taxes. Pursuant to ASC 740-30-50-2, we have estimated that the potential U.S. tax cost if we were to repatriate all of our currently unremitted foreign earnings through a dividend would be approximately $113 million based upon our foreign tax credit position in the U.S.
Working Capital.The net funds raised and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
Year Ended December 31, | ||||||||||||
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2012 | 2011 (RESTATED) | 2010 (RESTATED) | ||||||||||
Net cash used in operating activities | $ | (26,405 | ) | $ | (55,243 | ) | $ | (8,126 | ) | |||
Net cash provided by (used in) investing activities | (23,789 | ) | 112,216 | (56,231 | ) | |||||||
Net cash provided by (used in) financing activities | 63,875 | (56,730 | ) | 90,743 | ||||||||
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Net increase in cash | $ | 13,681 | $ | 243 | $ | 26,386 | ||||||
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Working Capital | 40,537 | 62,618 | 133,015 | |||||||||
Current Ratio | 2.0 | 3.1 | 5.7 | |||||||||
Total Cash, including restricted cash | 73,627 | 60,146 | 58,703 | |||||||||
Total Debt | 74,839 | 31,535 | 78,291 |
The decrease in working capital of $22.1 million at December 31, 2012 from December 31, 2011 was primarily due to decreases in receivables, increases in cash payments for capital expenditures and accrued expenses and decreases in accounts payable.
Cash Flow from Operating Activities. During the year ended December 31, 2012, net cash used in operating activities was approximately $26.4 million (2011: $55.2 million). The $28.8 million decrease in use of cash was primarily due to decreases in accounts payable and accrued interest and increases in accrued expenses offset by decreases in receivables.
Cash Flow from Investing Activities.Our cash capital expenditures for property and equipment are summarized in the following table:
December 31, | ||||||||
2012 | 2011 (RESTATED) | |||||||
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Budong PSC | $ | 5.8 | $ | 21.9 | ||||
Dussafu PSC | 11.7 | 40.1 | ||||||
Block 64 EPSA | 6.1 | 10.2 | ||||||
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Total additions of property and equipment | 23.6 | 72.2 | ||||||
Assets Held for Sale – Antelope Project(1) | — | 33.9 | ||||||
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Total additions of property and equipment | $ | 23.6 | $ | 106.1 | ||||
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(1) | SeeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Notes to Consolidated Financial Statements, Note 5 – Dispositions, Discontinued Operations. |
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During the year ended December 31, 2012, we:
• | Deposited with a U.S. bank $1.0 million as collateral for a Standby Letter of Credit issued in support of a performance bond for a joint study and had $1.2 million of restricted cash released to us; and |
• | Advanced $0.5 million to Petrodelta for continuing operations costs, and Petrodelta repaid $0.1 million. |
During the year ended December 31, 2011, we:
• | Received $217.8 million for the sale of our Antelope Project (seeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Notes to Consolidated Financial Statements, Note 5 – Dispositions, Discontinued Operations); |
• | Received $1.0 million for the sale of pipe inventory associated with the Antelope Project; |
• | Received $1.4 million from the sale of our equity investment in Fusion Geophysical, LLC; |
• | Deposited with a U.S. bank $1.2 million as collateral for a Standby Letter of Credit issued as a payment guarantee for drilling activities on Block 64 EPSA; and |
• | Advanced $0.8 million to Petrodelta for continuing operations costs, and Petrodelta repaid $0.1 million. |
Petrodelta’s capital commitments will be determined by its business plan. Petrodelta’s capital commitments are expected to be funded by internally generated cash flow. Our budgeted capital expenditures of $40.1 million for 2013, of which $33.7 million is non-discretionary, for U.S., Indonesia and Gabon operations will be funded through our existing cash balances, accessing equity and debt markets, and cost reductions. In addition, we could delay the discretionary portion of our capital spending to future periods or sell assets as necessary to maintain the liquidity required to run our operations, as warranted.
Cash Flow from Financing Activities.During the year ended December 31, 2012, we:
• | Received cash proceeds of $66.5 million from an offering of $79.8 million in aggregate principal amount of our 11.0 percent senior unsecured notes (seeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt); and |
• | Incurred $3.3 million in legal fees associated with financings. |
During the year ended December 31, 2011, we:
• | Repaid $60.0 million of our term loan facility (seeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 6 – Long-Term Debt); |
• | Recorded $2.5 million of tax benefits related to the difference between book and tax deductions allowed for equity compensation; and |
• | Incurred $0.2 million in legal fees associated with financings. |
Contractual Obligations
At December 31, 2012, we had the following lease commitments for office space in Houston, Texas, regional/technical offices in the United Kingdom and Singapore, and field offices in Jakarta, Indonesia; Port Gentil, Gabon; and Muscat, Oman that support field operations in those areas. In May 2013, we discontinued our operations in Oman.
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Location | Date Lease Signed | Term | Annual Expense | |||||||
Houston, Texas | April 2004 | 10 years | $ | 204,000 | ||||||
Houston, Texas | December 2008 | 5 years | 160,800 | |||||||
Caracas, Venezuela | October 2012 | 1 year | 224,400 | |||||||
London, U.K. | September 2010 | 5 years | 108,000 | |||||||
Singapore | October 2012 | 2 years | 84,000 | |||||||
Jakarta, Indonesia | April 2012 | 2 years | 98,500 | |||||||
Muscat, Oman | September 2011 | 2 years | 62,400 | |||||||
Gabon, Port Gentil | December 2012 | 2 years | 61,200 |
We have various contractual commitments pertaining to exploration, development and production activities. These contractual commitments are included in the Contractual Obligations table below under Oil and gas activities.
• | The third exploration phase of the Dussafu PSC has a $7.0 million ($4.7 million net to our 66.667 percent interest) work commitment over a four year period. This commitment was fulfilled with the drilling of DTM-1. |
Payments (in thousands) Due by Period | ||||||||||||||||||||
Contractual Obligations | Total | Less than 1 Year | 1-2 Years | 3-4 Years | After 4 Years | |||||||||||||||
Debt: | ||||||||||||||||||||
11.0% Senior Unsecured Notes Due 2014 | $ | 79,750 | $ | — | $ | 79,750 | $ | — | $ | — | ||||||||||
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Total Debt | 79,750 | — | 79,750 | — | — | |||||||||||||||
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Other obligations: | ||||||||||||||||||||
Interest payments | 15,620 | 8,773 | 6,847 | — | — | |||||||||||||||
Oil and gas activities | 8,200 | 112 | 8,088 | — | — | |||||||||||||||
Office leases | 1,459 | 773 | 537 | 149 | — | |||||||||||||||
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Total other obligations | 25,279 | 9,658 | 15,472 | 149 | — | |||||||||||||||
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Total contractual obligations | $ | 105,029 | $ | 9,658 | $ | 95,222 | $ | 149 | $ | — | ||||||||||
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The four-year extension of the initial exploration phase on the Budong PSC includes an exploration well, which if not drilled by January 2016, results in the termination of the Budong PSC. Also, if this exploration well is not drilled within 18 months of the date of approval from the Government of Indonesia of this transaction, we will be required to pay our partner in the Budong PSC $3.2 million. SeeItem 15. Exhibits and Financial Statement Schedules, Notes to Consolidated Financial Statements, Note 14 – Indonesia.
Senior Unsecured Notes
On October 11, 2012, we closed an offering of $79.8 million in aggregate principal amount of our 11.0 percent senior unsecured notes. Under the terms of the notes, interest is payable quarterly in arrears on January 1, April 1, July 1 and October 1, beginning January 1, 2013. The senior unsecured notes will mature on October 11, 2014. SeeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risks, Uncertainties, Capital Resources and Liquidity.
Effects of Changing Prices, Foreign Exchange Rates and Inflation
Our results of operations and cash flow are affected by changing oil prices. Fluctuations in oil prices may affect our total planned development activities and capital expenditure program.
Our net foreign exchange losses attributable to our international operations were minimal for the years ended December 31, 2012 and 2011. There are many factors affecting foreign exchange rates and resulting exchange gains and losses, most of which are beyond our control. It is not possible for us to predict the extent to which we may be affected by future changes in exchange rates and exchange controls.
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Venezuela imposed currency exchange restrictions in February 2003, and adjusted the official exchange rate in February 2004, March 2005, January 2010, January 2011 and February 2013. As a result of the February 2013 devaluation, Harvest Vinccler estimates the impact of the devaluation to be approximately $0.1 million gain on revaluation of its assets and liabilities, and Petrodelta estimates the impact of the devaluation to be approximately $54.8 million gain on revaluation of its assets and liabilities.
Harvest Vinccler and Petrodelta do not have currency exchange risk other than the official prevailing exchange rate that applies to their operating costs denominated in Bolivars (4.30 Bolivars per U.S. Dollar for 2012). However, during the year ended December 31, 2012, Harvest Vinccler exchanged approximately $1.5 million through SITME and received an average exchange rate of 5.16 Bolivars per U.S. Dollar. The monetary assets that are exposed to exchange rate fluctuations are cash, accounts receivable, prepaid expenses and other current assets. The monetary liabilities that are exposed to exchange rate fluctuations are accounts payable, accruals and other current liabilities. All monetary assets and liabilities incurred at the official Bolivar exchange rate are settled at the official Bolivar exchange rate. Petrodelta does not have, and has not had, any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate. Harvest Vinccler currently does not have any U.S. Dollars pending government approval for settlement for Bolivars at the official exchange rate or the SITME exchange rate.
SeeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Operations, Venezuela for a more complete discussion of the exchange agreements and their effects on our Venezuelan operations.
Within the United States and other countries in which we conduct business, inflation has had a minimal effect on us, but it is potentially an important factor with respect to results of operations in Venezuela. The inflation rate in Venezuela was 22.2 percent, 26.0 percent and 28.5 percent for January 2013, 2012, and 2011, respectively.
Critical Accounting Policies
Reporting and Functional Currency
The United States Dollar (“U.S. Dollar”) is the reporting and functional currency for all of our controlled subsidiaries and Petrodelta. Amounts denominated in non-U.S. Dollar currencies are re-measured into U.S. Dollars, and all currency gains or losses are recorded in the consolidated statements of operations and comprehensive income (loss). There are many factors that affect foreign exchange rates and the resulting exchange gains and losses, many of which are beyond our influence.
Investment in Equity Affiliates
We evaluate our investments in unconsolidated companies under ASC 323, “Investments – Equity Method and Joint Ventures.” Investments in which we have significant influence are accounted for under the equity method of accounting. Under the equity method, Investment in Equity Affiliates is increased by additional investments and earnings and decreased by dividends and losses. We review our Investment in Equity Affiliates for impairment whenever events and circumstances indicate a loss in investment value is other than a temporary decline.
There are many factors to consider when evaluating an equity investment for possible impairment. Currency devaluations, inflationary economies, and cash flow analysis are some of the factors we consider in our evaluation for possible impairment.
Capitalized Interest
We capitalize interest costs for qualifying oil and gas properties. The capitalization period begins when expenditures are incurred on qualified properties, activities begin which are necessary to prepare the property for production and interest costs have been incurred. The capitalization period continues as long as these events occur. The average additions for the period are used in the interest capitalization calculation.
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Property and Equipment
We follow the successful efforts method of accounting for our oil and gas properties. Under this method, oil and natural gas lease acquisition costs are capitalized when incurred. Unproved properties are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved reserves. Exploratory drilling costs are capitalized when drilling is completed if it is determined that there is economic producibility supported by either actual production, conclusive formation test or by certain technical data. If proved reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in production of crude oil and natural gas, are capitalized.
Depletion, depreciation, and amortization (“DD&A”) of the cost of proved oil and natural gas properties are calculated using the unit of production method. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is proved reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base is proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
Assets are grouped in accordance with ASC 932. The basis for grouping is reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Amortization rates are updated to reflect: 1) the addition of capital costs, 2) reserve revisions (upwards or downwards) and additions, 3) property acquisitions and/or property dispositions and 4) impairments.
We account for impairments of proved properties under the provisions of ASC 360, “Property, Plant, and Equipment”. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field level to the amortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the amortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
Reserves
In December 2009, we adopted the SEC’s Modernization of Oil and Gas Reporting and ASC 932. ASC 932 requires the unweighted average, first-day-of-the-month price during the 12-month period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes.
Proved reserves are those quantities of oil and gas which by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, government regulations, etc. Prices include consideration of changes in existing prices provided only by contractual arrangements and do not include adjustments based upon expected future conditions. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves which are less certain to be recovered than probable reserves and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.
The reserves included herein were estimated using deterministic methods and presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserve categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.
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The estimate of reserves is made using available geological and reservoir data as well as production performance data. These estimates are prepared by an independent third party petroleum engineering consulting firm and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits earlier. A material adverse change in the estimated volumes of proved reserves could have a negative impact on DD&A expense and could result in the recognition of an impairment.
Income Taxes
Deferred income taxes reflect the net tax effects, calculated at currently enacted rates, of (a) future deductible/taxable amounts attributable to events that have been recognized on a cumulative basis in the financial statements or income tax returns, and (b) operating loss and tax credit carry forwards. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
We do not provide deferred income taxes on undistributed earnings of our foreign subsidiaries for possible future remittances as all such earnings are permanently reinvested as part of our ongoing business.
New Accounting Pronouncements
In July 2012, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2012-02, which is included in ASC 350, “Intangibles – Goodwill and Other” (“ASC350”). This update gives an entity the option first to assess qualitative factors in assessing whether an asset is impaired. ASU No. 2012-02 is effective for annual and interim impairment test performed for fiscal years beginning after September 15, 2012. Early adoption is permitted. The adoption of ASU No. 2012-02 did not have a material impact on our consolidated financial position, results of operation or cash flows.
In January 2013, FASB issued ASU No. 2013-01, which is included in ASC 210, “Balance Sheet”, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (“ASU No. 2013-01”). This update clarifies that the scope of ASU 2011-11: “Disclosures about Offsetting Assets and Liabilities” applies only to derivatives accounted for under ASC 815 “Derivatives and Hedging”, included bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. ASU No. 2013-01 is effective for fiscal years and interim periods within those years, beginning on or after January 1, 2013. Entities should provide the required disclosures retrospectively for all comparative periods presented. The adoption of this guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash flows.
In February 2013, FASB issued ASU No. 2013-02, which is included in ASC 220, “Comprehensive Income”, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“ASU NO. 2013-02”). This update requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under USGAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under USGAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under USGAAP that provide additional detail about those amounts. The amendments of ASU No. 2013-02 do not change the current requirements for reporting net income or other comprehensive income in financial statements. ASU No. 2013-02 is effective for fiscal years and interim periods within those years, beginning on or after December 15, 2012. Early adoption is permitted. The adoption of this guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash flows.
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In February 2013, FASB issued ASU No. 2013-04, which is included in ASC 405, “Liabilities”, “Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”. This update provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation with the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in USGAAP. Examples of obligations within the scope to ASU No. 2013-04 include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. ASU No. 2013-04 is effective for fiscal years and interim periods within those years beginning after December 5, 2013. Entities should provide the required disclosures retrospectively for all comparative periods presented. The adoption of this guidance impacts presentation disclosures only and will not have an impact on our consolidated financial position, results of operation or cash flows.
In March 2013, FASB issued ASU No. 2013-05, which is included in ASC 830, “Foreign Currency Matters”, “Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity” (“ASU 2013-05”). This update resolves the diversity in practice regarding the release into net income of the cumulative translation adjustment upon derecognition of a subsidiary or group of assets within a foreign entity. ASU No. 2013-05 is effective for fiscal years and interim periods within those years beginning after December 5, 2013. ASU No. 2013-05 is not expected to have a material impact on our consolidated financial position, results of operation or cash flows.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
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