Exhibit 99.1
PEDEVCO CORP.
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF OIL AND GAS PROPERTIES ACQUIRED FROM GOLDEN GLOBE ENERGY (US), LLC.
On February 23, 2015, Red Hawk Petroleum, LLC (“Red Hawk”), a wholly-owned subsidiary of PEDEVCO Corp. (the “Company”), completed the acquisition of approximately 12,977 net acres of oil and gas properties and interests in 53 gross wells located in the Denver - Julesburg Basin, Colorado (the “Acquired Assets”) from Golden Globe Energy (US), LLC (“GGE”).
Following are the audited statements of revenues and direct operating expenses of the Acquired Assets for the years ended December 31, 2014 and 2013. Complete financial and operating information related to the Acquired Assets, including balance sheet and cash flow information, are not presented because the Acquired Assets were maintained as an asset and not a separate company in the accounting records of a predecessor company; therefore, the assets, liabilities, indirect operating costs and other expenses applicable to the operations were not allocated to the properties acquired.
| Report of Independent Registered Public Accounting Firm | | | 2 | |
| Statements of Revenues and Direct Operating Expenses of Oil and Gas Properties Acquired From Golden Globe Energy (US), LLC for the Years Ended December 31, 2014 and 2013 | | | 3 | |
| Notes to Statements of Revenues and Direct Operating Expenses of Oil and Gas Properties Acquired from Golden Globe Energy (US), LLC. | | | 4 | |
| Supplemental Information on Oil and Gas Producing Activities (unaudited) | | | 7 | |
Report of Independent Registered Public Accounting Firm
To the Board of Directors
PEDEVCO CORP.
Danville, CA
We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas properties acquired from Golden Globe Energy (US), LLC for the years ended December 31, 2014 and 2013. These financial statements are the responsibility of PEDEVCO CORP.’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
The accompanying financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and is not intended to be a complete financial presentation of the properties described above.
In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the oil and gas properties acquired from Golden Globe Energy (US), LLC for the years ended December 31, 2014 and 2013, in conformity with accounting principles generally accepted in the United States.
/s/ GBH CPAs, PC
GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
April 30 , 2015
PEDEVCO CORP.
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF OIL AND GAS PROPERTIES
ACQUIRED FROM GOLDEN GLOBE ENERGY (US), LLC.
(amounts in thousands)
| | For the Years Ended | |
| | December 31, | |
| | 2014 | | | 2013 | |
| | | | | | | | |
| Revenues | $ | 4,182 | | | $ | 5,687 | |
| Direct operating expenses | | 1,173 | | | | 657 | |
| Revenues in excess of direct operating expenses | $ | 3,009 | | | $ | 5,030 | |
See accompanying notes to the statements of revenues and direct operating expenses.
PEDEVCO CORP.
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF OIL AND GAS PROPERTIES ACQUIRED FROM GOLDEN GLOBE ENERGY (US), LLC.
1. PROPERTIES ACQUIRED AND RELATED TRANSACTIONS
Acquisition of Assets from Golden Globe (US), LLC
On February 23, 2015 (the “Closing”), Red Hawk Petroleum, LLC (“Red Hawk”), a wholly-owned subsidiary of PEDEVCO Corp. (the “Company”), completed the acquisition of approximately 12,977 net acres of oil and gas properties and interests in 53 gross wells located in the Denver-Julesburg Basin, Colorado (the “Acquired Assets”) from Golden Globe Energy (US), LLC (“GGE”).
As consideration for the acquisition of the Acquired Assets, the Company (i) issued to GGE 3,375,000 restricted shares of the Company’s $0.001 par value per share common stock and 66,625 restricted shares of the Company’s newly-designated Amended and Restated Series A Convertible Preferred Stock (the “Series A Preferred”), (ii) assumed approximately $8.35 million of subordinated notes payable from GGE pursuant to an Assumption and Consent Agreement and an Amendment to Note and Security Agreement, and (iii) provided GGE with a one-year option to acquire the Company’s interest in its Kazakhstan opportunity for $100,000 pursuant to a Call Option Agreement. The effective date of the transaction was January 1, 2015, with the exception of all revenues and refunds attributable to GGE’s approximate 49.7% interest in each of the Loomis 2-1H, Loomis 2-3H and Loomis 2-6H wells, which revenues and refunds the Company owns from the date of first production, which are estimated through January 2015 to total approximately $700,000.
The following tables summarize the purchase price and allocation of the purchase price to the net assets acquired (in thousands):
| Purchase Price on February 23, 2015: | | | |
| Fair value of common stock issued | | $ | 2,734 | |
| Fair value of Series A Preferred stock issued | | | 28,402 | |
| Assumption of subordinated notes payable | | | 8,353 | |
| Proceeds from Kazakhstan option issued | | | 5,000 | |
| Total purchase price | | $ | 44,489 | |
| | | | | |
| Fair value of net assets at February 23, 2015: | | | | |
| Accounts receivable – oil and gas | | | 1,678 | |
| Oil and gas properties, subject to amortization | | | 43,562 | |
| Total assets | | | 45,240 | |
| | | | | |
| Accounts payable | | | (664 | ) |
| Asset retirement obligations | | | (87 | ) |
| Total liabilities | | | (751 | ) |
| Net assets acquired | | $ | 44,489 | |
The Series A Preferred Issued
The 66,625 shares of Series A Preferred stock issued to GGE were issued in 4 tranches as follows: (i) 15,000 shares in Tranche One; (ii) 15,000 shares in Tranche Two; (iii) 11,625 shares in Tranche Three; and (iv) 25,000 shares in Tranche Four.
The 66,625 shares of Series A Preferred stock issued to GGE currently have the following features:
| ● | a liquidation preference senior to all of the Company’s common stock equal to $400 per share; |
| ● | a dividend, payable annually, of 10% of the liquidation preference; |
| ● | voting rights on all matters, with each share having 1 vote; and |
| ● | a conversion feature at GGE’s option, which must be approved by a majority of the shareholders’ of the Company which will allow the Series A Preferred stock to be converted into shares of the Company’s common stock on a 1,000:1 basis. |
Additionally, if the Company receives shareholders’ approval for the conversion feature the Series A Preferred features are also modified as follows:
| ● | the Series A Preferred shall automatically cease accruing dividends and all accrued and unpaid dividends will be automatically forfeited and forgiven; and |
| ● | the liquidation preference of the Series A Preferred will be reduced to $0.001 per share from $400 per share. |
The conversion feature also provides that GGE will be subject to a lock-up that prohibits it from selling the shares of common stock through the public markets for less than $1 per share (on an as-converted to common stock basis) until February 23, 2016, and in no event may GGE beneficially own more than 9.99% of our outstanding common stock or voting stock.
The Series A Preferred is redeemable at the option of the Company , if the Company repays the promissory notes issued to BRe BCLIC Primary, BRe BCLIC Sub, BRe WINIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub, HEARTLAND Bank, and RJC, as investors (the “PEDEVCO Senior Loan Investors”), and BAM Administrative Services LLC, as agent for the investors, and any related collateral documents (collectively, the “PEDEVCO Senior Loan”) by November 23, 2015.
The Series A Preferred is redeemable as follows:
| ● | until November 23, 2015, the Company may redeem any or all of the Tranche One shares at a repurchase price of $500 per share; |
| ● | from November 24, 2015 until February 23, 2017, the Company may redeem any or all of the Tranche One shares and Tranche Two shares at a repurchase price of $650 per share; and |
| ● | from February 24, 2017 until February 23, 2018, the Company may redeem any or all remaining outstanding shares of Series A Preferred at a repurchase price of $800 per share. |
In addition, if the Company repays the PEDEVCO Senior Loan and redeems all of the Tranche One shares by November 23, 2015 the above redemption options are modified as follows:
| ● | the Tranche Four shares are automatically redeemed for $0 per share, and |
| ● | GGE may request (but not require) that we redeem |
| o | the Tranche Two shares at a redemption price of $650 per share for a period of 30 days following February 23, 2017, and |
| o | the Tranche Two Shares and 11,625 shares of the Tranche Three shares at a redemption price of $800 per share for a period of 30 days following February 23, 2018. |
In the event the Company or its Assigns do not redeem all the Series A Preferred shares, GGE has no recourse against the Company. However, if the Company or its assigns do not redeem all the Series A Preferred shares, and the average closing price of the Company’s common stock over the 30 day period immediately preceding February 23, 2018 is below $0.80 per share, then the Company is required to issue to GGE up to an additional 10,000 shares of Series A Preferred, pro-rated based on the actual number of shares of Preferred Series A not redeemed and repurchased by the Company.
The Subordinated Notes Payable Assumed
The Company assumed approximately $8.35 million of subordinated notes payable from GGE in the transaction. The lender under the subordinated notes payable is RJ Credit LLC (“RJC”), which is one of the lenders under the PEDEVCO Senior Loan and is an affiliate of GGE. The note is due and payable on December 31, 2017, and bears interest at a rate of 12% per annum (24% upon an event of default). The accrued interest is payable on a monthly basis in cash. The assumed note is subordinate and subject to the terms and conditions of the PEDEVCO Senior Loan, as well as any of our future secured indebtedness from a lender with an aggregate principal amount of at least $20,000,000. Should the Company repay the PEDEVCO Senior Loan or replace it with a secured indebtedness from a lender with an aggregate principal amount of at least $20,000,000, RJC agreed to further amend the subordinated debt to adjust the frequency of interest payments or to eliminate the payments and replace them with a single payment of the accrued interest to be paid at maturity.
The subordinated note contains customary representations, warranties, covenants and requirements for the Company to indemnify RJC and its affiliates, related parties and assigns. The note also includes various covenants (positive and negative) binding the Company, including requiring that the Company provide RJC with quarterly (unaudited) and annual (audited) financial statements, restricting our creation of liens and encumbrances, or sell or otherwise disposing, the collateral under the note.
2. BACKGROUND AND BASIS OF PRESENTATION
The statements of revenues and direct operating expenses of the Acquired Assets, for each of the years ended December 31, 2014 and 2013 have been prepared in conformity with accounting principles generally accepted in the United States and in accordance with the rules of the Securities and Exchange Commission (the ��SEC”). Complete financial and operating information related to the properties, including balance sheet and cash flow information, are not presented because the properties were maintained as assets and not separate companies in the accounting records of predecessor companies; therefore, the assets, liabilities, indirect operating costs and other expenses applicable to the operations were not allocated to the properties acquired.
The accompanying audited statements include revenues from oil production and direct lease operating expenses associated with the Acquired Assets. For purposes of these statements, all interests identified in the agreement between the Company and GGE are included herein. Because the Acquired Assets were not a separate legal entity prior to GGE’s acquisition of the properties from the Company in March 2014, and were not a separate legal entity prior to the Company’s original acquisition of the properties from Continental Resources, Inc. (“Continental”) in March 2014 prior to the Company’s conveyance of the properties to GGE in March 2014, the accompanying statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that they do not reflect certain expenses that were incurred in connection with the ownership and operation of the Acquired Assets, including but not limited to, general and administrative expenses, interest expense, and income tax expense. These costs were not separately allocated to the Acquired Assets in the accounting records prior to either GGE’s acquisition of the properties from the Company in March 2014, the Company’s acquisition of the properties from Continental in March 2014, or by Continental prior to the Company’s acquisition of the properties in March 2014. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Acquired Assets had they been the Company’s business due to the differing size, structure, and accounting policies of the Company, GGE and Continental, which owned the properties prior to the Company’s and GGE’s acquisition of the same in March 2014. Furthermore, no balance sheet has been presented for the Acquired Assets, because its historical costs and related working capital balances are not segregated or easily obtainable, nor has information about the Acquired Assets operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical statements of revenues and direct operating expenses of the Acquired Assets are presented in lieu of the full financial statements required under Item 8-04 of Securities and Exchange Commission Regulation S-X.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of statements of revenues and direct operating expenses in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of revenue and expenses during the reporting periods. Although these estimates are based on management’s best available knowledge of current and future events, actual results could be different from those estimates.
Revenue Recognition
All revenue is recognized when persuasive evidence of an arrangement exists, the service or sale is complete, the price is fixed or determinable and collectability is reasonably assured. Revenue is derived from the sale of crude oil and natural gas. Revenue from crude oil and natural gas sales is recognized when the product is delivered to the purchaser and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected.
Direct Operating Expenses
Direct operating expenses are recognized when incurred and consist of the direct expenses of operating the Acquired Assets. The direct operating expenses include lease operating expenses, electricity, production and ad valorem taxes and transportation expenses, well work over costs and other field expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, facilities and insurance directly related to oil production activities of the business.
Recently Issued Accounting Pronouncements
The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its results of operations, financial position or cash flows.
Subsequent Events
The Company has evaluated all transactions from December 31, 2014 through the financial statement issuance date for subsequent event disclosure consideration and has disclosed all necessary transactions.
4. FAIR VALUE ACCOUNTING OF PREFERRED STOCK
The Company measures fair value in accordance with FASB ASC Topic 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined 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).
Three levels of inputs that may be used to measure fair value are:
Level 1 – Quoted prices in active markets for identical assets or liabilities.
Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 – Unobservable inputs that are supported by little or no market activity and that are financial instruments whose values are determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant judgment or estimation.
If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level of input that is significant to the fair value measurement of the instrument.
The following table sets forth by level within the fair value hierarchy our financial instruments that were accounted for at fair value as of February 23, 2015 (in thousands):
| | | Fair Value Measurements at February 23, 2015 | |
| | | Quoted Prices in Active Markets for Identical Assets | | | Significant Other Observable Inputs | | | Significant Unobservable Inputs | | | Total Carrying Value | |
| | | (Level 1) | | | (Level 2) | | | (Level 3) | | | | |
| | | | | | | | | | | | | |
| Series A Convertible Preferred Stock | | $ | - | | | $ | - | | | $ | 28,402 | | | $ | 28,402 | |
The Company believes there is no active market or significant other market data for the Series A Preferred stock as it is held by a limited number of closely held entities, therefore the Company has determined it should use Level 3 inputs.
Some of the significant assumptions are conversions of the various tranches under various scenarios, binomial lattice model, term, expected term and expected volatility.
Supplemental Information on Oil and Gas Producing Activities (UNAUDITED)
The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof for each of the years ended December 31, 2014 and 2013 attributable to the Acquired Assets. All of the reserves are located in the Niobrara formation of the Denver-Julesburg Basin (the “DJ Basin”) in Morgan and Weld Counties, Colorado. In 2014 and 2013, the reserve estimates set forth below were prepared by South Texas Reservoir Alliance, LLC (“STXRA”), an independent professional engineering firm certified by the Texas Board of Professional Engineers (Registration number F-1580), under the direction of Michael Rozenfeld of STXRA. STXRA, and its employees, have no material interest in our Company. STXRA also performs internal reservoir engineering services for the Company; participants in a joint venture with the Company for which no substantial activity has occurred to date; and periodically receives compensation for assistance in locating additional oil and gas properties.
The reserve estimates were prepared by STXRA using reserve definitions and pricing requirements prescribed by the SEC.
There are numerous uncertainties inherent in estimating quantities and values of proved reserves, in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The summaries shown below represent estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Acquired Assets. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Acquired Assets and any adjustments in the projected economic life of such business resulting from changes in product prices.
The following table sets forth certain data pertaining to the Acquired Assets’ proved, proved developed, and proved undeveloped reserves for each of the years ended December 31, 2014 and 2013.
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
Proved reserves at December 31, 2014 are set forth below (in thousands):
| | | 2014 | |
| | | Oil | | | Gas | |
| | | (MBbls) | | | (Mmcf) | |
| | | | | | | |
| Proved Developed Producing | | | 390.8 | | | | 827.6 | |
| Proved Developed Non-Producing | | | - | | | | - | |
| Total Proved Developed | | | 390.8 | | | | 827.6 | |
| Proved Undeveloped | | | 4,170.8 | | | | 8,902.1 | |
| Total Proved as of December 31, 2014 | | | 4,561.6 | | | | 9,729.7 | |
| | | 2014 | |
| | | Oil | | Gas | |
| | | (MBbls) | | (Mmcf) | |
| Total Proved Reserves: | | | | | |
| Beginning of year | | 1,954.7 | | 4,006.8 | |
| Extensions and discoveries | | 97.1 | | 180.6 | |
| Revisions of previous estimates | | 2,555.1 | | 5,614.5 | |
| Purchase of minerals in place | | - | | - | |
| Production | | (45.3 | ) | (72.2 | ) |
| End of year proved reserves | | 4,561.6 | | 9,729.7 | |
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
Proved reserves at December 31, 2013 are set forth below (in thousands):
| | | 2013 | |
| | | Oil | | Gas | |
| | | (MBbls) | | (Mmcf) | |
| | | | | | |
| Proved Developed Producing | | 108.3 | | 195.8 | |
| Proved Developed Non-Producing | | - | | - | |
| Total Proved Developed | | 108.3 | | 195.8 | |
| Proved Undeveloped | | 1,846.4 | | 3,811.0 | |
| Total Proved as of December 31, 2013 | | 1,954.7 | | 4,006.8 | |
| | | 2013 | |
| | | Oil | | Gas | |
| | | (MBbls) | | (Mmcf) | |
| Total Proved Reserves: | | | | | |
| Beginning of year | | 1,969.5 | | 4,034.9 | |
| Extensions and discoveries | | - | | - | |
| Revisions of previous estimates | | 49.4 | | 78.9 | |
| Purchase of minerals in place | | - | | - | |
| Production | | (64.2 | ) | (107.0 | ) |
| End of year proved reserves | | 1,954.7 | | 4,006.8 | |
Discounted Future Net Cash Flows
A summary of discounted future net cash flows relating to proved crude oil reserves is presented below:
The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of future production of reserves. Revisions of previous year estimates can have a significant impact on these results. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties.
Future income tax expense was computed by applying statutory rates, less the effects of tax credits for each period presented, to calculate the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties, after consideration of available net operating loss and percentage depletion carryovers.
The following table sets forth the standardized measure of discounted future net cash flows relating to the proved reserves as of December 31, 2014 (in thousands):
| | | ($ 000's) | |
| Future cash inflows | | $ | 441,806 | |
| Future production costs | | | (151,762 | ) |
| Future development costs | | | (153,891 | ) |
| Future income tax expense | | | (17,680 | ) |
| Future net cash flows | | | 118,473 | |
| 10% annual discount | | | (73,114 | ) |
| Standardized measure of discounted future net cash flows | | $ | 45,359 | |
Changes in Standardized Measure of Discounted Future Cash Flows
| | | ($ 000's) | |
| Beginning of year | | $ | 14,428 | |
| Sales and transfers of oil and gas produced, net of production costs | | | (3,009 | ) |
| Net changes in prices and production costs | | | (5,901 | ) |
| Extensions, discoveries, additions and improved recovery, net of related costs | | | 1,888 | |
| Development costs incurred | | | - | |
| Changes in estimated future development costs | | | (60,084 | ) |
| Revisions of estimated development costs | | | - | |
| Revisions of previous quantity estimates | | | 52,824 | |
| Accretion of discount | | | 2,186 | |
| Net change in income taxes | | | 223 | |
| Purchases of reserves in place | | | - | |
| Sales of reserves in place | | | - | |
| Changes in timing and other | | | 42,804 | |
| End of year | | $ | 45,359 | |
The following table sets forth the standardized measure of discounted future net cash flows relating to the proved reserves as of December 31, 2013 (in thousands):
| | | ($ 000's) | |
| Future cash inflows | | $ | 204,363 | |
| Future production costs | | | (72,088 | ) |
| Future development costs | | | (74,223 | ) |
| Future income tax expense | | | (8,571 | ) |
| Future net cash flows | | | 49,481 | |
| 10% annual discount | | | (35,053 | ) |
| Standardized measure of discounted future net cash flows | | $ | 14,428 | |
Changes in Standardized Measure of Discounted Future Cash Flows
| | | ($ 000's) | |
| Beginning of year | | $ | 12,680 | |
| Sales and transfers of oil and gas produced, net of production costs | | | (5,030) | |
| Net changes in prices and production costs | | | 16 | |
| Extensions, discoveries, additions and improved recovery, net of related costs | | | - | |
| Development costs incurred | | | - | |
| Changes in estimated future development costs | | | 2,063 | |
| Revisions of estimated development costs | | | - | |
| Revisions of previous quantity estimates | | | 974 | |
| Accretion of discount | | | 1,921 | |
| Net change in income taxes | | | 2,794 | |
| Purchases of reserves in place | | | - | |
| Sales of reserves in place | | | - | |
| Changes in timing and other | | | (990 | ) |
| End of year | | $ | 14,428 | |
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