isramco10q033110.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| |
Check One
|
|
| |
x
|
Quarterly report under Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended March 31, 2010
|
| |
|
|
| |
|
or
|
| |
|
|
| |
o
|
Transition report under Section 13 or 15(d) of the Securities Exchange Act of 1934
|
Commission File Number 0-12500
ISRAMCO, INC
(Exact Name of registrant as Specified in its Charter)
|
Delaware
|
|
13-3145265
|
|
(State or other Jurisdiction of Incorporation or Organization)
|
|
I.R.S. Employer Number
|
2425 West Loop South, Suite 810, HOUSTON, TX 77027
(Address of Principal Executive Offices)
713-621-5946
(Registrant’s Telephone Number, Including Area Code)
Indicate by check whether the registrant: (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer x Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
The number of shares outstanding of the registrant’s Common Stock as May 10, 2010 was 2,717,691.
| |
|
Page
|
|
PART I - FINANCIAL INFORMATION:
|
|
| |
|
|
|
Item 1.
|
|
3 |
| |
|
3
|
| |
|
4
|
| |
|
5
|
| |
|
6
|
|
Item 2.
|
|
13
|
|
Item 3.
|
Quanititative and Qualitative Disclosures about Market Risk |
20 |
|
Item 4.
|
Controls and Procedures
|
20
|
| |
|
|
|
PART II. OTHER INFORMATION
|
|
| |
|
|
|
Item 1.
|
|
|
|
Item 1A.
|
|
21
|
|
Item 2.
|
|
21
|
|
Item 3.
|
|
21
|
|
Item 4.
|
(Removed and Reserved)
|
21
|
|
Item 5.
|
|
21
|
|
Item 6.
|
|
21
|
| |
|
22
|
Forward Looking Statements
CERTAIN STATEMENTS MADE IN THIS QUARTERLY REPORT ON FORM 10-Q ARE “FORWARD-LOOKING STATEMENTS” WITHIN THE MEANING OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995. FORWARD-LOOKING STATEMENTS CAN BE IDENTIFIED BY TERMINOLOGY SUCH AS “MAY”, “WILL”, “SHOULD”, “EXPECTS”, “INTENDS”, “ANTICIPATES”, “BELIEVES”, “ESTIMATES”, “PREDICTS”, OR “CONTINUE” OR THE NEGATIVE OF THESE TERMS OR OTHER COMPARABLE TERMINOLOGY AND INCLUDE, WITHOUT LIMITATION, STATEMENTS BELOW REGARDING EXPLORATION AND DRILLING PLANS, FUTURE GENERAL AND ADMINISTRATIVE EXPENSES, FUTURE GROWTH, FUTURE EXPLORATION, FUTURE GEOPHYSICAL AND GEOLOGICAL DATA, GENERATION OF ADDITIONAL PROPERTIES, RESERVES, NEW PROSPECTS AND DRILLING LOCATIONS, FUTURE CAPITAL EXPENDITURES, SUFFICIENCY OF WORKING CAPITAL, ABILITY TO RAISE ADDITIONAL CAPITAL, PROJECTED CASH FLOWS FROM OPERATIONS, OUTCOME OF ANY LEGAL PROCEEDINGS, DRILLING PLANS, THE NUMBER, TIMING OR RESULTS OF ANY WELLS, INTERPRETATION AND RESULTS OF SEISMIC SURVEYS OR SEISMIC DATA, FUTURE PRODUCTION OR RESERVES, LEASE OPTIONS OR RIGHTS, PARTICIPATION OF OPERATING PARTNERS, CONTINUED RECEIPT OF ROYALTIES, AND ANY OTHER STATEMENTS REGARDING FUTURE OPERATIONS, FINANCIAL RESULTS, OPPORTUNITIES, GROWTH, BUSINESS PLANS AND STRATEGY. BECAUSE FORWARD-LOOKING STATEMENTS INVOLVE RISKS AND UNCERTAINTIES, THERE ARE IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE EXPRESSED OR IMPLIED BY THESE FORWARD-LOOKING STATEMENTS. ALTHOUGH THE COMPANY BELIEVES THAT EXPECTATIONS REFLECTED IN THE FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CANNOT GUARANTEE FUTURE RESULTS, PERFORMANCE OR ACHIEVEMENTS. MOREOVER, NEITHER THE COMPANY NOR ANY OTHER PERSON ASSUMES RESPONSIBILITY FOR THE ACCURACY AND COMPLETENESS OF THESE FORWARD-LOOKING STATEMENTS. THE COMPANY IS UNDER NO DUTY TO UPDATE ANY FORWARD-LOOKING STATEMENTS AFTER THE DATE OF THIS REPORT TO CONFORM SUCH STATEMENTS TO ACTUAL RESULTS.
ITEM 1. Financial Statements
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
(Unaudited)
| |
|
As of
March 31, 2010
|
|
|
As of
December 31, 2009
|
|
|
ASSETS
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,977
|
|
|
$
|
2,907
|
|
|
Accounts receivable, net
|
|
|
5,599
|
|
|
|
7,424
|
|
|
Restricted and designated cash
|
|
|
827
|
|
|
|
827
|
|
|
Deferred tax assets
|
|
|
2,742
|
|
|
|
3,644
|
|
|
Derivative asset
|
|
|
4,354
|
|
|
|
3,421
|
|
|
Prepaid expenses and other
|
|
|
880
|
|
|
|
656
|
|
|
Total Current Assets
|
|
|
18,379
|
|
|
|
18,879
|
|
| |
|
|
|
|
|
|
|
|
|
Property and Equipment, at cost – successful efforts method:
|
|
|
|
|
|
|
|
|
|
Oil and Gas properties
|
|
|
220,460
|
|
|
|
220,138
|
|
|
Other
|
|
|
681
|
|
|
|
672
|
|
|
Total Property and Equipment
|
|
|
221,141
|
|
|
|
220,810
|
|
|
Accumulated depreciation, depletion and amortization
|
|
|
(80,485
|
)
|
|
|
(77,315
|
)
|
|
Net Property and Equipment
|
|
|
140,656
|
|
|
|
143,495
|
|
| |
|
|
|
|
|
|
|
|
|
Marketable securities, at market
|
|
|
5,301
|
|
|
|
4,713
|
|
|
Debt cost
|
|
|
259
|
|
|
|
322
|
|
|
Derivative asset
|
|
|
2,388
|
|
|
|
2,158
|
|
|
Deferred tax assets and other
|
|
|
6,700
|
|
|
|
6,751
|
|
|
Total assets
|
|
$
|
173,683
|
|
|
$
|
176,318
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
7,663
|
|
|
$
|
9,798
|
|
|
Short term debt and bank overdraft
|
|
|
912
|
|
|
|
336
|
|
|
Current maturities of long-term debt
|
|
|
17,950
|
|
|
|
12,000
|
|
|
Derivative liability
|
|
|
382
|
|
|
|
693
|
|
|
Accrued interest and due to related party
|
|
|
5,430
|
|
|
|
4,677
|
|
|
Deferred tax liabilities
|
|
|
-
|
|
|
|
-
|
|
|
Total current liabilities
|
|
|
32,337
|
|
|
|
27,504
|
|
| |
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
25,050
|
|
|
|
32,950
|
|
|
Accrued interest - related party
|
|
|
4,021
|
|
|
|
4,832
|
|
|
Long-term debt - related party
|
|
|
79,354
|
|
|
|
79,354
|
|
| |
|
|
|
|
|
|
|
|
|
Other Long-term Liabilities:
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
16,309
|
|
|
|
16,248
|
|
|
Derivative liability – non-current
|
|
|
1,031
|
|
|
|
1,697
|
|
|
Total other long-term liabilities
|
|
|
17,340
|
|
|
|
17,945
|
|
| |
|
|
|
|
|
|
|
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
|
|
|
|
Common stock $0.0l par value; authorized 7,500,000 shares; issued 2,746,958 shares; outstanding 2,717,691 shares
|
|
|
27
|
|
|
|
27
|
|
|
Additional paid-in capital
|
|
|
23,194
|
|
|
|
23,194
|
|
|
Accumulated deficit
|
|
|
(10,005
|
)
|
|
|
(11,362
|
)
|
|
Accumulated other comprehensive income
|
|
|
2,529
|
|
|
|
2,038
|
|
|
Treasury stock, 29,267 shares at cost
|
|
|
(164
|
)
|
|
|
(164
|
)
|
|
Total shareholders’ equity
|
|
|
15,581
|
|
|
|
13,733
|
|
|
Total liabilities and shareholders’ equity
|
|
$
|
173,683
|
|
|
$
|
176,318
|
|
See notes to the condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share amounts)
(Unaudited)
| |
|
Three Months Ended March 31,
|
|
|
|
|
2010
|
|
|
2009
|
|
| |
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
9,955
|
|
|
$
|
6,583
|
|
|
Office services to affiliate and other
|
|
|
202
|
|
|
|
182
|
|
|
Other
|
|
|
8
|
|
|
|
242
|
|
|
Total revenues
|
|
|
10,165
|
|
|
|
7,007
|
|
| |
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
|
Lease operating expense, transportation and taxes
|
|
|
4,900
|
|
|
|
3,665
|
|
|
Depreciation, depletion and amortization
|
|
|
3,170
|
|
|
|
4,507
|
|
|
Accretion expense
|
|
|
204
|
|
|
|
210
|
|
|
Loss from plug and abandonment
|
|
|
346
|
|
|
|
-
|
|
|
General and administrative
|
|
|
899
|
|
|
|
879
|
|
|
Total operating expenses
|
|
|
9,519
|
|
|
|
9,261
|
|
|
Operating income (loss)
|
|
|
646
|
|
|
|
(2,254
|
)
|
| |
|
|
|
|
|
|
|
|
|
Other expenses (income)
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
1,962
|
|
|
|
2,447
|
|
|
Net gain on derivative contracts
|
|
|
(3,373
|
)
|
|
|
(7,414
|
)
|
|
Total other income
|
|
|
(1,411
|
)
|
|
|
(4,967
|
)
|
| |
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
2,057
|
|
|
|
2,713
|
|
|
Income tax expense
|
|
|
(700
|
)
|
|
|
(923
|
)
|
| |
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,357
|
|
|
$
|
1,790
|
|
| |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Earnings per share – basic and diluted:
|
|
$
|
0.50
|
|
|
$
|
0.66
|
|
| |
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding-basic and diluted
|
|
|
2,717,691
|
|
|
|
2,717,691
|
|
See notes to the condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
| |
|
Three Months Ended March 31,
|
|
|
|
|
2010
|
|
|
2009
|
|
| |
|
|
|
|
|
|
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,357
|
|
|
$
|
1,790
|
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and impairment
|
|
|
3,170
|
|
|
|
4,507
|
|
|
Accretion expense
|
|
|
204
|
|
|
|
210
|
|
|
Unrealized and realized gain on marketable securities
|
|
|
-
|
|
|
|
(169
|
)
|
|
Changes in deferred taxes
|
|
|
700
|
|
|
|
923
|
|
|
Net unrealized loss (gain) on derivative contracts
|
|
|
(1,985
|
)
|
|
|
(2,833
|
)
|
|
Amortization of debt cost
|
|
|
63
|
|
|
|
63
|
|
|
Changes in components of working capital and other assets and liabilities
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
1,825
|
|
|
|
1,196
|
|
|
Prepaid expenses and other current assets
|
|
|
(225
|
)
|
|
|
(28
|
)
|
|
Related party
|
|
|
173
|
|
|
|
74
|
|
|
Accrued interest - related party
|
|
|
(232
|
)
|
|
|
160
|
|
|
Accounts payable and accrued liabilities
|
|
|
(2,232
|
)
|
|
|
(341
|
)
|
|
Net cash provided by operating activities
|
|
|
2,818
|
|
|
|
5,552
|
|
| |
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
Addition to property and equipment, net
|
|
|
(374
|
)
|
|
|
(47
|
)
|
|
Restricted cash and deposit, net
|
|
|
-
|
|
|
|
(25
|
)
|
|
Proceeds from sale of marketable securities
|
|
|
-
|
|
|
|
427
|
|
|
Net cash provided by (used in) investing activities
|
|
|
(374
|
)
|
|
|
355
|
|
| |
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
Repayment of long-term debt
|
|
|
(1,950
|
)
|
|
|
(4,950
|
)
|
|
Borrowings (repayments) of short - term debt, net
|
|
|
576
|
|
|
|
(926
|
)
|
|
Net cash used in financing activities
|
|
|
(1,374
|
)
|
|
|
(5,876
|
)
|
| |
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
1,070
|
|
|
|
31
|
|
|
Cash and cash equivalents at beginning of period
|
|
|
2,907
|
|
|
|
3,141
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
3,977
|
|
|
$
|
3,172
|
|
See notes to the condensed consolidated financial statements.
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 - Financial Statement Presentation
As used in these financial statements, the terms “Company” and “Isramco” refer to Isramco, Inc. and its subsidiaries, Jay Petroleum, L.L.C. (“Jay Petroleum”), Jay Management Company L.L.C. (“Jay Management”), IsramTec Inc. (“IsramTec”), Isramco Resources LLC, Isramco Energy LLC and Field Trucking and Services, LLC (”FTS”).
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the SEC instructions to Form 10-Q. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of only normal recurring adjustments) considered necessary for a fair presentation have been included. Results for the three-month period ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. For further information, refer to the consolidated financial statements and footnotes thereto included in Isramco’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
Use of Estimates
The preparation of the Company’s condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s condensed consolidated financial statements.
Consolidated interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The Company has evaluated events or transactions through the date of issuance of these condensed consolidated financial statements.
Risk Management Activities
The Company follows Accounting Standards Codification (ASC) 815, Derivatives and Hedging. From time to time, the Company may hedge a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain on derivative contracts” on the consolidated statements of operations.
Consolidation
The condensed consolidated financial statements include the accounts of Isramco and its wholly-owned subsidiaries: Jay Petroleum, Jay Management, IsramTec, Isramco Resources LLC and Isramco Energy LLC and FTS. Inter-company balances and transactions have been eliminated in consolidation.
Reclassifications
Certain prior year amounts in the condensed consolidated financial statements have been reclassified to conform to current year presentations
Recently Issued Accounting Pronouncements
In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows, but did impact the Company’s disclosures on fair value measurements. See Note 6, “Fair Value Measurements.”
In February 2010, FASB issued ASU No. 2010-09, Amendments to Certain Recognition and Disclosure Requirements (ASU 2010-09). This update amends Subtopic 855-10 and gives a definition to SEC filer, and requires SEC filers to assess for subsequent events through the issuance date of the financial statements. This amendment states that an SEC filer is not required to disclose the date through which subsequent events have been evaluated for a reporting period. ASU 2010-09 becomes effective upon issuance of the final update. The Company adopted the provisions of ASU 2010-09 for the period ended March 31, 2010.
In April 2010, the FASB issued ASU No. 2010-12, Accounting for Certain Tax Effects of the 2010 Health Care Reform Acts (ASU 2010-12). This update clarifies questions surrounding the accounting implications of the different signing dates of the Health Care and Education Reconciliation Act (signed March 30, 2010) and the Patient Protection and Affordable Care Act (signed March 23, 2010). ASU 2010-12 states that the FASB and the Office of the Chief Accountant at the SEC would not be opposed to view the two Acts together for accounting purposes. The Company is currently assessing the impact, if any, the adoption of ASU 2010-12 will have on the Company’s disclosures, operating results, financial position and cash flows.
Note 2 - Supplemental Cash Flow Information
Cash paid for interest and income taxes was as follows for the period ended March 31 (in thousands):
| |
|
2010
|
|
|
2009
|
|
|
Interest
|
|
$
|
2,122
|
|
|
$
|
2,209
|
|
| |
|
|
|
|
|
|
|
|
|
Income taxes
|
|
$
|
—
|
|
|
$
|
—
|
|
Note 3 - Derivative Contracts
At March 31, 2010, the Company had a $6.7 million commodity derivative asset, of which $4.4 million was classified as current, and a $1 million non-current derivative liability. For the three months ended March 31, 2010, the Company recorded a net derivative gain of $3.4 million ($2 million unrealized gain and a $1.4 million gain from net cash received on settled contracts).
At March 31, 2009, the Company had a $25.9 million commodity derivative asset, of which $13.9 million was classified as current. For the three months ended March 31, 2009, the Company recorded a net derivative gain of $7.4 million ($2.8 million unrealized gain and a $4.6 million gain from net cash proceeds on settled contracts).
Natural Gas
At March 31, 2010, the Company had the following natural gas swap positions:
|
|
|
Swaps
|
|
| Period |
|
Volume in
MMbtu’s
|
|
|
Price /
Price Range
|
|
|
Weighted
Average Price
|
|
|
April 2010 – December 2010
|
|
|
1,339,236
|
|
|
|
7.49-8.32
|
|
|
|
7.88
|
|
|
January 2011 – December 2011
|
|
|
764,820
|
|
|
|
8.22
|
|
|
|
8.22
|
|
|
January 2012 – March 2012
|
|
|
174,222
|
|
|
|
8.65
|
|
|
|
8.65
|
|
Crude Oil
At March 31, 2010, the Company had the following crude oil swap positions:
|
|
|
Swaps
|
|
| Period |
|
Volume in
Bbls
|
|
|
Price /
Price Range
|
|
|
Weighted
Average Price
|
|
|
April 2010 – December 2010
|
|
|
191,151
|
|
|
|
63.30-101.70
|
|
|
|
79.59
|
|
|
January 2011 – December 2011
|
|
|
240,336
|
|
|
|
79.50-91.05
|
|
|
|
86.55
|
|
|
January 2012 – December 2012
|
|
|
127,473
|
|
|
|
80.20-88.20
|
|
|
|
82.37
|
|
|
January 2013 – December 2013
|
|
|
89,400
|
|
|
|
85.15
|
|
|
|
85.15
|
|
|
January 2014 – December 2014
|
|
|
66,000
|
|
|
|
86.95
|
|
|
|
86.95
|
|
During the second quarter of 2008, the Company decided to mitigate a portion of it interest rate risk with interest rate swaps. These swap instruments reduce the Company’s exposure to market rate fluctuations by converting variable interest rates to fixed interest rates.
Under these swaps, the Company makes payments to, or receives payments from, the counterparties based upon the differential between a specified fixed price and a price related to the one-month London Interbank Offered Rate (“LIBOR”). These interest rate swaps convert a portion of our variable rate interest applicable to our “Scotia” debt (as defined in Note 8, “Long-term Debt” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We have elected to designate these positions for hedge accounting and therefore the unrealized gains and losses are recorded in accumulated other comprehensive loss. The Company measures hedge effectiveness by assessing the changes in the fair value or expected future cash flows of the hedged item.
The Company’s open interest rate swap positions, as described above, are as follows:
|
National amount (in thousands):
|
|
Start Date
|
|
Maturity Date
|
|
Weighted-Average
Interest Rate
|
|
| |
15,500 |
|
April 2009
|
|
February 2011
|
|
|
3.63 |
% |
| |
6,000 |
|
April 2009
|
|
February 2011
|
|
|
2.90 |
% |
Note 4 - Long-Term Debt and Interest Expense
Long-Term Debt as of March 31, 2010 and December 31, 2009 consisted of the following (in thousands):
| |
|
As of
March 31, 2010
|
|
|
As of
December 31, 2009
|
|
|
Libor + 2% Bank Revolving Credit Facility due 2011
|
|
|
13,950 |
|
|
|
14,950 |
|
|
Libor + 2% Bank Revolving Credit Facility due 2012
|
|
|
29,050 |
|
|
|
30,000 |
|
|
Libor + 6% Related party Debt
|
|
|
12,000 |
|
|
|
12,000 |
|
|
Libor + 5.5% Related party Debt
|
|
|
954 |
|
|
|
954 |
|
|
Libor + 6% Related party Debt
|
|
|
11,500 |
|
|
|
11,500 |
|
|
Libor + 6% Related party Debt
|
|
|
6,000 |
|
|
|
6,000 |
|
|
Libor + 6% Related party Debt
|
|
|
48,900 |
|
|
|
48,900 |
|
| |
|
|
122,354 |
|
|
|
124,304 |
|
|
Less: Current Portion of Long-Term Debt
|
|
|
(17,950 |
) |
|
|
(12,000 |
) |
|
Total
|
|
|
104,404 |
|
|
|
112,304 |
|
Senior Secured Revolving Credit Agreements
At March 31, 2010, the Company was in compliance with all of its debt covenants under its existing Credit Agreements.
Interest expense
The following table summarizes the amounts included in interest expense for the three month ended March 31, 2010 and 2009 (in thousands):
| |
|
Three Months Ended
March 31
|
|
| |
|
2010
|
|
|
2009
|
|
|
Current debt, long-term debt and other - banks corporation
|
|
$
|
497
|
|
|
$
|
787
|
|
|
Long-term debt – related parties
|
|
|
1,465
|
|
|
|
1,660
|
|
|
|
|
$
|
1,962
|
|
|
$
|
2,447
|
|
Note 5 - Comprehensive Income
Our comprehensive income for the three month period ended March 31, 2010 and 2009 was as follows:
| |
|
Three Months Ended
March 31
|
|
| |
|
2010
|
|
|
2009
|
|
|
Net income
|
|
$
|
1,357
|
|
|
$
|
1,790
|
|
|
Other comprehensive gain
|
|
|
|
|
|
|
|
|
|
Available-for-sale securities, net of taxes
|
|
|
388
|
|
|
|
323
|
|
|
Change in unrealized gains (loss) on hedging instruments, net of taxes
|
|
|
103
|
|
|
|
(52
|
)
|
|
Comprehensive income
|
|
$
|
1,848
|
|
|
$
|
2,061
|
|
Note 6 - Fair Value of Financial Instruments
Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820) the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.
The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 2010 and December 31, 2009. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for the three months ended March 31, 2010.
|
|
|
March 31, 2010
|
|
| |
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities
|
|
$ |
5,301
|
|
|
$ |
—
|
|
|
$ |
—
|
|
|
$ |
5,301
|
|
|
Commodity derivatives
|
|
|
—
|
|
|
|
6,742
|
|
|
|
—
|
|
|
|
6,742
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,301
|
|
|
$
|
6,742
|
|
|
$
|
—
|
|
|
$
|
12,043
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
—
|
|
|
|
1,031
|
|
|
$
|
—
|
|
|
$
|
1,031
|
|
|
Interest rate derivatives
|
|
|
—
|
|
|
|
382
|
|
|
|
—
|
|
|
|
382
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
—
|
|
|
$
|
1,413
|
|
|
$
|
—
|
|
|
$
|
1,413
|
|
|
|
|
December 31, 2009
|
|
| |
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities
|
|
$ |
4,713 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
4,713 |
|
|
Commodity derivatives
|
|
|
— |
|
|
|
5,579 |
|
|
|
— |
|
|
|
5,579 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
4,713 |
|
|
$ |
5,579 |
|
|
$ |
— |
|
|
$ |
10,292 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$ |
— |
|
|
|
1,852 |
|
|
$ |
— |
|
|
$ |
1,852 |
|
|
Interest rate derivatives
|
|
|
— |
|
|
|
538 |
|
|
|
— |
|
|
|
538 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
— |
|
|
$ |
2,390 |
|
|
$ |
— |
|
|
$ |
2,390 |
|
Marketable securities listed above are carried at fair value. The Company is able to value its marketable securities based on quoted fair values for identical instruments, which resulted in the Company reporting its marketable securities as Level 1.
Derivatives listed above include swaps that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain on derivative contracts” in the Company’s consolidated statements of operations, in case of commodity derivatives, and in “Other comprehensive income”, in case of interest rate derivatives. The Company is able to value these assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves.
As of March 31, 2010 and December 31, 2009, the Company’s derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Each of the counterparties to the Company’s derivative contracts is a lender in the Company’s Senior Credit Agreement. The Company did not post collateral under any of these contracts as they are secured under the Senior Credit Agreements.
Note 7 - Subsequent Events
The Company has evaluated subsequent events through May 10, 2010, which is the date the consolidated financial statements were issued.
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
THE FOLLOWING COMMENTARY SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL STATEMENTS AND RELATED NOTES CONTAINED ELSEWHERE IN THIS REPORT ON FORM 10-Q. THE DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS THAT INVOLVE RISKS AND UNCERTAINTIES. THESE STATEMENTS RELATE TO FUTURE EVENTS OR OUR FUTURE FINANCIAL PERFORMANCE. IN SOME CASES, YOU CAN IDENTIFY THESE FORWARD-LOOKING STATEMENTS BY TERMINOLOGY SUCH AS “MAY,” “WILL,” “SHOULD,” “EXPECT,” “PLAN,” “ANTICIPATE,” “BELIEVE,” “ESTIMATE,” “PREDICT,” “POTENTIAL,” “INTEND,” OR “CONTINUE,” AND SIMILAR EXPRESSIONS. THESE STATEMENTS ARE ONLY PREDICTIONS. OUR ACTUAL RESULTS MAY DIFFER MATERIALLY FROM THOSE ANTICIPATED IN THESE FORWARD-LOOKING STATEMENTS AS A RESULT OF A VARIETY OF FACTORS, INCLUDING, BUT NOT LIMITED TO, THOSE SET FORTH UNDER “RISK FACTORS” AND ELSEWHERE IN THIS REPORT ON FORM 10-Q. ISRAMCO INC. DISCLAIMS ANY OBLIGATION TO UPDATE SUCH FORWARD LOOKING STATEMENTS.
Overview
Isramco, Inc. (“”Isramco” or “we”) is an independent oil and natural gas company engaged in the exploration, development and production of oil and natural gas properties located onshore in the United States. Our properties are primarily located in Texas, New Mexico and Oklahoma. We also act as the operator of certain of these properties. Historically, we have grown through acquisitions, with a focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves, while lowering lease operating costs.
Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire additional properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, political issues, pipeline capacity constraints, inventory storage levels, basis differentials and other factors, and secondarily upon our commodity price hedging activities. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success. Our future drilling and development plans are subject to change based upon various factors, some of which are beyond our control, including results of operations, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling and other services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our operating plans and associated capital budgets in future periods, our financial position, cash flows and operating results could be adversely impacted.
Liquidity and Capital Resources
Our primary source of cash during the three months ended March 31, 2010 was cash flow from operating activities. The capital markets, as they relate to us, have been adversely impacted by the current financial crisis and concerns about the economic recession and its effect on commodity prices. Continued volatility in the capital markets could adversely impact our ability to replace our reserves, and eventually, our production levels.
Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we have acquired. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on the capital resources available and our success in finding and acquiring additional reserves. We expect to fund our future capital requirements through internally generated cash flows and borrowings under our Senior Credit Agreements. Long-term cash flows are subject to a number of variables, including the level of production and prices and our commodity price hedging activities, as well as various economic conditions that have historically affected the oil and natural gas industry.
| |
|
As of March 31,
|
|
As of December 31,
|
|
| |
|
2010
|
|
|
2009
|
|
|
Revolving Credit Facility
|
|
$
|
25,050
|
|
|
$
|
32,950
|
|
|
Long – term debt – related party
|
|
|
79,354
|
|
|
|
79,354
|
|
|
Current maturities of long-term debt, short-term debt and bank overdraft
|
|
|
18,862
|
|
|
|
12,366
|
|
|
Total debt
|
|
|
123,266
|
|
|
|
124,670
|
|
| |
|
|
|
|
|
|
|
|
|
Stockholders’ equity
|
|
|
15,581
|
|
|
|
13,733
|
|
| |
|
|
|
|
|
|
|
|
|
Debt to capital ratio
|
|
|
88.8
|
%
|
|
|
90
|
%
|
Under the credit facility available, we can borrow up to a maximum of $52,400 thousand, of which approximately $13,950 thousand is currently outstanding. Management currently believes that this availability is sufficient to provide the liquidity required to satisfy our anticipated working capital needs for 2010.
As of March 31, 2010, our total debt was $123,266 thousand, compared to total debt of $124,670 thousand at December 31, 2009. As of March 31, 2010, current debt included $17,950 thousand as current maturities of the Revolving Credit Facilities, of which $4,000 thousand was the result of management’s decision to continue payments to reduce debt below the borrowing base. As of December 31, 2009, current debt included $12,000 thousand as current maturities, of which $12,000 thousand was the result of management’s decision to continue payments to reduce debt below the borrowing base.
Cash Flow
Our primary sources of cash in the three months ended March 31, 2010 and 2009 were our operating activities. In the 2010 and 2009 period, cash received from operations were mainly offset by repayments made under our revolving credit facilities.
Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in commodity prices and our overall cash flow may result in an increase or decrease in our future capital expenditures and could influence our ability to reduce our long-term loans. Prices for oil and natural gas have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have also influenced prices throughout recent years.
| |
|
Three months Ended March 31,
|
|
| |
|
2010
|
|
|
2009
|
|
| |
|
(In thousands)
|
|
|
Cash flows provided by operating activities
|
|
$ |
2,818 |
|
|
$ |
5,552 |
|
|
Cash flows provided by (used in) investing activities
|
|
|
(374 |
) |
|
|
355 |
|
|
Cash flows used in financing activities
|
|
|
(1,374 |
) |
|
|
(5,876 |
) |
|
Net increase in cash
|
|
$ |
1,070 |
|
|
$ |
31 |
|
Operating Activities, During the first three months of 2010, compared to the first three months of 2009, net cash flow provided by operating activities decreased by $2,734 thousand to $2,818 thousand. This decrease was primarily attributable to a reduction in working capital of $1,752 thousand, net cash proceeds from commodity price hedging activities of $3,193 thousand and higher lease operating expenses all of which were partially offset by increased oil and natural gas revenues. The increase in revenues was primarily attributable to higher average oil and gas prices for the quarter ended March 31, 2010 of $77.75/bbl and $5.81/mcf, compared to $37.75/bbl and $3.92/mcf for the quarter ended March 31, 2009.
Investing Activities, Net cash flows provided by (used in) investing activities for the three months ended March 31, 2010 and 2009 were $(374) thousand and $355 thousand, respectively.
Financing Activities, Net cash flows used in financing activities were $(1,374) thousand and $(5,876) thousand for the three months ended March 31, 2010 and 2009, respectively.
Results of Operations
| |
|
Three Months Ended March 31,
|
|
| |
|
2010
|
|
|
2009
|
|
| |
|
(In thousands except per share
and MBOE amounts)
|
|
|
Financial Results
|
|
|
|
|
|
|
|
Oil and Gas sales
|
|
$
|
9,955
|
|
|
$
|
6,583
|
|
|
Other
|
|
|
210
|
|
|
|
424
|
|
|
Total revenues and other
|
|
|
10,165
|
|
|
|
7,007
|
|
| |
|
|
|
|
|
|
|
|
|
Cost and expenses
|
|
|
9,519
|
|
|
|
9,261
|
|
|
Other income
|
|
|
(1,411
|
)
|
|
|
(4,967
|
)
|
|
Income tax expense
|
|
|
700
|
|
|
|
923
|
|
|
Net Income
|
|
|
1,357
|
|
|
|
1,790
|
|
|
Earnings per common share – basic and diluted
|
|
$
|
0.50
|
|
|
$
|
0.66
|
|
|
Weighted average number of shares outstanding-basic and diluted
|
|
|
2,717,691
|
|
|
|
2,717,691
|
|
| |
|
|
|
|
|
|
|
|
|
Operating Results
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX (1)
|
|
$
|
5,408
|
|
|
$
|
7,044
|
|
|
Sales volumes (MMBOE)
|
|
|
199
|
|
|
|
232
|
|
| |
|
|
|
|
|
|
|
|
|
Average cost per MBOE:
|
|
|
|
|
|
|
|
|
|
Production (including transportation and taxes)
|
|
$
|
24.65
|
|
|
$
|
15.80
|
|
|
General and administrative
|
|
$
|
4.52
|
|
|
$
|
3.79
|
|
|
Depletion
|
|
$
|
15.95
|
|
|
$
|
19.44
|
|
|
(1)
|
See Adjusted EBITDAX for a description of Adjusted EBITDAX, which is not a Generally Accepted Accounting Principles (GAAP) measure, and a reconciliation of Adjusted EBITDAX to income from operations before income taxes, which is presented in accordance with GAAP.
|
Financial Results
Net Income, in the first quarter of 2010, our net income was $1,357 thousand, or $0.50 per share. This compares to net income of $1,790 thousand, or $0.66 per share, for the first quarter of 2009.
This decrease was primarily due to the impact of derivatives, a decrease in sales volumes of natural gas, oil and natural gas liquids (“NGLs”) caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells, along with the natural decline in production and higher lease operating expenses which were partially offset by higher natural gas, oil and NGLs sales revenues due to higher prices, lower depreciation, depletion and amortization expenses and lower interest expense.
Revenues, Volumes and Average Prices
Sales Revenues
| |
|
Three Months Ended March 31,
|
|
|
In thousands except percentages
|
|
2010
|
|
|
2009
|
|
|
D vs. 2009
|
|
|
Gas sales
|
|
$ |
3,382 |
|
|
$ |
2,663 |
|
|
|
27 |
% |
|
Oil sales
|
|
|
5,078 |
|
|
|
2,963 |
|
|
|
71 |
|
|
Natural gas liquid sales
|
|
|
1,495 |
|
|
|
957 |
|
|
|
56 |
|
|
Total
|
|
$ |
9,955 |
|
|
$ |
6,583 |
|
|
|
51 |
% |
Our sales revenues for the first quarter of 2010 increased by 51% when compared to same period in 2009, due to higher prices received for natural gas, oil and condensate and NGLs. This increase in revenue was partially offset by a decrease in our sales volumes caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells, along with the natural decline in production.
Volumes and Average Prices
| |
|
Three Months Ended March 31,
|
|
| |
|
2010
|
|
|
2009
|
|
|
D vs. 2009
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
Sales volumes Mmcf
|
|
|
582.6
|
|
|
|
679.4
|
|
|
|
(14
|
)%
|
|
Average Price per Mcf (1)
|
|
$
|
5.81
|
|
|
$
|
3.92
|
|
|
|
48
|
|
|
Total gas sales revenues (thousands)
|
|
$
|
3,382
|
|
|
$
|
2,663
|
|
|
|
27
|
%
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes MBbl
|
|
|
65.3
|
|
|
|
78.5
|
|
|
|
(17
|
)%
|
|
Average Price per Bbl (1)
|
|
$
|
77.75
|
|
|
$
|
37.75
|
|
|
|
106
|
|
|
Total oil sales revenues (thousands)
|
|
$
|
5,078
|
|
|
$
|
2,963
|
|
|
|
71
|
%
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes MBbl
|
|
|
36.4
|
|
|
|
40.2
|
|
|
|
(9
|
)%
|
|
Average Price per Bbl (1)
|
|
$
|
41.08
|
|
|
$
|
23.82
|
|
|
|
72
|
|
|
Total natural gas liquids sales revenues (thousands)
|
|
$
|
1,495
|
|
|
$
|
957
|
|
|
|
56
|
%
|
|
(1)
|
Amounts exclude the impact of cash paid/received on settled contracts, as we did not elect to apply hedge accounting
|
The company’s natural gas sales volumes decreased by 14%, crude oil sales volumes by 17% and natural gas liquids sales volumes by 9% for the first quarter of 2010 compared to the same period of 2009. This decrease was primarily caused by adverse weather conditions in Texas that restricted our ability to access, repair and maintain our wells, along with the natural decline in production.
Our average natural gas price for the first quarter of 2010 increased by 48%, or $1.89 per Mcf, when compared to the same period of 2009. Our average crude oil price for the first quarter of 2010 increased by 106%, or $40 per Bbl, when compared to the same period of 2009. Our average natural gas liquids price for the first quarter of 2010 increased by 72%, or $17.26 per Bbl, when compared to the same period of 2009.
Analysis of Oil and Gas Operations Sales Revenues
The following table provides a summary of the effects of changes in volumes and prices on Isramco’s sales revenues for the three months ended March 31, 2010 compared to the same period of 2009.
|
In thousands
|
|
Natural Gas
|
|
|
Oil
|
|
|
Natural gas liquids
|
|
|
2009 sales revenues
|
|
|
2,663
|
|
|
|
2,963
|
|
|
|
957
|
|
|
Changes associated with sales volumes
|
|
|
(379
|
)
|
|
|
(498
|
)
|
|
|
(90
|
)
|
|
Changes in prices
|
|
|
1,098
|
|
|
|
2,613
|
|
|
|
628
|
|
|
2010 sales revenues
|
|
$
|
3,382
|
|
|
$
|
5,078
|
|
|
$
|
1,495
|
|
Operating Expenses
| |
|
Three Months Ended March 31,
|
|
In thousands except percentages
|
|
2010
|
|
|
2009
|
|
|
D vs. 2009
|
|
Lease operating expense, transportation and taxes
|
|
$
|
4,900
|
|
|
$
|
3,665
|
|
|
|
34
|
%
|
|
Depreciation, depletion and amortization
|
|
|
3,170
|
|
|
|
4,507
|
|
|
|
(30
|
)
|
|
Accretion expense
|
|
|
204
|
|
|
|
210
|
|
|
|
(3
|
)
|
|
Loss from plug and abandonment
|
|
|
346
|
|
|
|
-
|
|
|
|
-
|
|
|
General and administrative
|
|
|
899
|
|
|
|
879
|
|
|
|
2
|
|
| |
|
$
|
9,519
|
|
|
$
|
9,261
|
|
|
|
3
|
%
|
During the first quarter of 2010, our operating expenses increased by 3% when compared to the first quarter of 2009, due to the following factors:
|
·
|
Lease operating expense, transportation cost and taxes increased by 34%, or $1,235 thousand, in 2010 when compared to 2009. This increase was the result of the costs associated with a plan we initiated in January 2010 to workover a number of our wells, along with the incremental costs involved in operating older, more mature fields that require additional repair and maintenance. Finally, the higher oil and gas sale prices we received increased the taxes paid during 2010. On a per unit basis, lease operating expenses (including transportation and taxes) increased by $8.85 per MBOE to $24.65 per MBOE in 2010 from $15.80 per MBOE in 2009.
|
|
·
|
Depreciation, Depletion &Amortization (DD&A) of the cost of proved oil and gas properties is calculated using the unit-of-production method. Our DD&A rate and expense are the composite of numerous individual field calculations. There are several factors that can impact our composite DD&A rate and expense, including but not limited to field production profiles, drilling or acquisition of new wells, disposition of existing wells, and reserve revisions (upward or downward) primarily related to well performance and commodity prices, and impairments. Changes in these factors may cause our composite DD&A rate and expense to fluctuate from period to period. DD&A decreased by 30%, or $1,337 thousand, in 2010 when compared to 2009, primarily due to higher prices (per MBOE) that impacted our estimated total reserves, which are the basis for the depletion calculation, lower oil and gas production, and the impact of a 2009 impairment of $5,751 thousand on the depletable base used to calculate DD&A. On a per unit basis, depletion expense decreased by $3.49 per MBOE to $15.95 per MBOE in 2010 from $19.44 per MBOE in 2009
|
|
·
|
Accretion expense for asset retirement obligations slightly decreased by 3%, or $6 thousand, in 2010 when compared to 2009. The decrease reflects the impact of the plugging and abandonment of several of our wells.
|
|
·
|
General and administrative expenses increased slightly by 2%, or $20 thousand, in 2010 when compared to 2009.
|
Other income
| |
|
Three Months Ended March 31,
|
|
In thousands except percentages
|
|
2010
|
|
|
2009
|
|
|
D vs. 2009
|
|
|
Interest expense, net
|
|
$
|
1,962
|
|
|
$
|
2,447
|
|
|
|
(20
|
)%
|
|
Net gain on derivative contracts
|
|
|
(3,373
|
)
|
|
|
(7,414
|
)
|
|
|
(55
|
)
|
| |
|
$
|
(1,411
|
)
|
|
$
|
(4,967
|
)
|
|
|
(72
|
)
|
Interest expense. Isramco’s interest expense decreased by 20%, or $485 thousand, for the first quarter of 2010 compared to the same period of 2009. This decrease is primarily due to the lower average outstanding balance of the loans which we obtained to fund the Five States acquisition in 2007 and the GFB acquisition in 2008, and to decreases in average LIBOR rates during 2009. The decrease was partially offset by the payments on interest rate swaps
Net loss (gain) on derivative contracts. We enter into derivative commodity instruments to economically hedge our exposure to price fluctuations on our anticipated oil and natural gas production. Consistent with the prior year, we have elected not to designate any positions as cash flow hedges for accounting purposes. Accordingly, we recorded the net change in the mark-to-market value of these derivative contracts in our consolidated statement of operations.
At March 31, 2010, the Company had a $6.7 million commodity derivative asset, of which $4.4 million was classified as current and a $1 million non-current derivative liability. For the three months ended March 31, 2009, the Company recorded a net derivative gain of $3.4 million ($2 million unrealized gain and a $1.4 million gain from net cash received on settled contracts).
At March 31, 2009, the Company had a $25.9 million derivative asset, of which $13.9 million was classified as current. For the three month ended March 31, 2009, the Company recorded a net derivative gain of $7.4 million ($2.8 million unrealized gain and a $4.6 million gain from net cash proceeds on settled contracts).
Adjusted EBITDAX.
To assess the operating results of Isramco, management analyzes income from operations before income taxes, interest expense, exploration expense, unrealized gain (loss) on derivative contracts and DD&A expense and impairments (“Adjusted EBITDAX”). Adjusted EBITDAX is not a GAAP measure. Isramco’s definition of Adjusted EBITDAX excludes exploration expense because exploration expense is not an indicator of operating efficiency for a given reporting period, but rather is monitored by management as a part of the costs incurred in exploration and development activities. Similarly, Isramco excludes DD&A expense and impairments from Adjusted EBITDAX as a measure of segment operating performance because capital expenditures are evaluated at the time capital costs are incurred. The Company’s definition of Adjusted EBITDAX also excludes interest expense to allow for assessment of segment operating results without regard to Isramco’s financing methods or capital structure. Adjusted EBITDAX is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make payments on its long term loans. Management believes that the presentation of Adjusted EBITDAX provides information useful in assessing the Company’s financial condition and results of operations.
However, Adjusted EBITDAX, as defined by Isramco, may not be comparable to similarly titled measures used by other companies. Therefore, Isramco’s consolidated Adjusted EBITDAX should be considered in conjunction with income (loss) from operations and other performance measures prepared in accordance with GAAP, such as operating income or cash flow from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect income from continuing operations and net cash provided by operating activities. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of Isramco’s results as reported under GAAP. Below is a reconciliation of consolidated Adjusted EBITDAX to income (loss) from operations before income taxes.
| |
|
Three Months Ended March 31,
|
|
In thousands except percentages
|
|
2010
|
|
|
2009
|
|
|
Income from operations before income taxes
|
|
$
|
2,057
|
|
|
$
|
2,713
|
|
|
Depreciation, depletion, amortization and impairment expense
|
|
|
3,170
|
|
|
|
4,507
|
|
|
Interest expense
|
|
|
1,962
|
|
|
|
2,447
|
|
|
Unrealized gain on derivative contract
|
|
|
(1,985
|
)
|
|
|
(2,833
|
)
|
|
Accretion Expenses
|
|
|
204
|
|
|
|
210
|
|
|
Consolidated Adjusted EBITDAX
|
|
$
|
5,408
|
|
|
$
|
7,044
|
|
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
Derivative Instruments and Hedging Activity
We are exposed to various risks, including energy commodity price risk. If oil and natural gas prices decline significantly our ability to finance our capital budget and operations could be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have adopted a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The type of derivative instrument that we typically utilize is swaps. The total volumes which we hedge through the use of our derivative instruments varies from period to period,
We are exposed to market risk on our open derivative contracts of non-performance by our counterparties. However, we do not expect such non-performance because our contracts are with major financial institutions with investment grade credit ratings. Each of the counterparties to our derivative contracts is a lender in our Senior Credit Agreement. We did not post collateral under any of these contracts as they are secured under the Senior Credit Agreement.
We are also exposed to interest rate risk on our variable interest rate debt. If interest rates increase, our interest expense would increase and our available cash flow would decrease. Periodically, we look to utilize interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. At March 31, 2010, we had two open positions that convert a portion of our variable rate interest of our Scotia debt (as defined in Note 8, “Long-term Debt” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009) to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. We continue to monitor our risk exposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy as situations present themselves.
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 1. Consolidated Financial Statements—Note 3, “Derivative contracts” for more details.
ITEM 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures.
In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II - Other Information
|
|
| |
|
|
|
Legal Proceedings
|
| |
|
| |
None
|
| |
|
|
|
Risk Factors
|
| |
None
|
|
|
Change in Securities & Use of Proceeds
|
| |
|
| |
None
|
| |
|
|
|
Default Upon Senior Securities
|
| |
|
| |
None
|
| |
|
|
|
Removed and Reserved
|
| |
|
| |
None
|
|
|
Other Information
|
| |
|
| |
On May 4, 2010, we and our Chief Financial Officer, Edy Francis, entered into an Amended and Restated Employment Agreement (“Agreement”), effective April 1, 2010, pursuant to which Mr. Francis will continue to be employed as our Chief Financial Officer and will be paid an annual base salary $84,600. He was paid a signing bonus of $50,000 as of execution of the Agreement. In addition, Mr. Francis is eligible for additional bonus and to participate in any profit sharing, option or similar plan to the extent and on the same basis as is awarded to other officers and executives of the Company. The Agreement has a specified term that extends through April 1, 2013. We can terminate the Agreement for any reason, for “Cause” or death or permanent disability (as such terms are defined in the Agreement). Mr. Francis can terminate only for “Good Reason” (as defined in the Agreement). If during the term we were to terminate the Agreement for any reason other than "Cause" or if Mr. Francis were to terminate for “Good Reason”, then the Company is to pay to Mr. Francis a severance payment equal to his base salary plus the value of all other benefits for six months. The Agreement also includes certain customary confidentiality provisions.
|
| |
|
|
|
Exhibits
|
|
Exhibits
|
|
| 10.1 |
|
|
31.1
|
|
|
31.2
|
|
|
32.1
|
|
|
32.2
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. .
| |
ISRAMCO, INC
|
|
| |
|
|
|
|
Date: MAY 10, 2010
|
By:
|
/s/ HAIM TSUFF
|
|
| |
|
HAIM TSUFF
|
|
| |
|
CHIEF EXECUTIVE OFFICER
|
|
| |
|
(PRINCIPAL EXECUTIVE OFFICER)
|
|
| |
|
|
| |
|
|
|
|
Date: MAY 10, 2010
|
By:
|
/s/ EDY FRANCIS
|
|
| |
|
EDY FRANCIS
|
|
| |
|
CHIEF FINANCIAL OFFICER
|
|
| |
|
(PRINCIPAL FINANCIAL AND ACCOUNTING OFFICER)
|
|