Attached files
| file | filename |
|---|---|
| 8-K/A - PEDEVCO CORP | pedevco8ka030714.htm |
| EX-99.3 - RESERVE REPORT - PEDEVCO CORP | ex99-3.htm |
| EX-23.1 - CONSENT OF GBH CPAS, PC. - PEDEVCO CORP | ex23-1.htm |
| EX-99.2 - UNAUDITED PRO FORMA COMBINED BALANCE SHEET - PEDEVCO CORP | ex99-2.htm |
| EX-23.2 - CONSENT OF SOUTH TEXAS RESERVOIR ALLIANCE LLC. - PEDEVCO CORP | ex23-2.htm |
Exhibit 99.1
PEDEVCO CORP.
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF OIL AND GAS PROPERTIES ACQUIRED FROM CONTINENTAL RESOURCES, INC.
On March 7, 2014, Red Hawk Petroleum, LLC (“Red Hawk”), a wholly-owned subsidiary of PEDEVCO Corp. (the “Company”), completed the acquisition of approximately 27,990 net acres of oil and gas properties and interests in 40 wells located in the Niobrara formation of the DJ Basin, Colorado (the “Acquired Assets”) from Continental Resources, Inc. (the “Continental”).
Following are the audited statements of revenues and direct operating expenses of the Acquired Assets for the years ended December 31, 2013 and 2012. 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 Continental; therefore, the assets, liabilities, indirect operating costs and other expenses applicable to the operations were not allocated to the properties acquired.
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Report of Independent Registered Public Accounting Firm
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2
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Statements of Revenues and Direct Operating Expenses of Oil and Gas Properties Acquired From Continental Resources, Inc. for the Years Ended December 31, 2013 and 2012
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3
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Notes to Statements of Revenues and Direct Operating Expenses of Oil and Gas Properties Acquired from Continental Resources, Inc.
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4
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Supplementary Reserve Information (unaudited)
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7
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1
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 Continental Resources, Inc. for the years ended December 31, 2013 and 2012. 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 combined revenues and direct operating expenses of the oil and gas properties acquired from Continental Resources, Inc. for the years ended December 31, 2013 and 2012, in conformity with accounting principles generally accepted in the United States.
/s/ GBH CPAs, PC
GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
May 21, 2014
2
PEDEVCO CORP.
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF OIL AND GAS PROPERTIES
ACQUIRED FROM CONTINENTAL RESOURCES, INC.
|
For the Years Ended
|
||||||||
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December 31,
|
||||||||
|
2013
|
2012
|
|||||||
|
Revenues
|
$ | 5,687,407 | $ | 6,954,649 | ||||
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Direct operating expenses
|
657,726 | 262,572 | ||||||
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Revenues in excess of direct operating expenses
|
$ | 5,029,681 | $ | 6,692,077 | ||||
See accompanying notes to the statements of revenues and direct operating expenses.
3
PEDEVCO CORP.
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF OIL AND GAS PROPERTIES ACQUIRED FROM CONTINENTAL RESOURCES, INC.
1. PROPERTIES ACQUIRED AND RELATED TRANSACTIONS
Acquisition of Assets from Continental Resources, Inc.
On January 21, 2014, Red Hawk Petroleum, LLC (“Red Hawk”), a wholly-owned subsidiary of PEDEVCO Corp. (the “Company”), entered into a Purchase and Sale Agreement (“Purchase Agreement”) with Continental Resources, Inc. (“Continental”), pursuant to which the Company agreed to acquire Continental’s interests (the “Continental Acquisition”) in approximately 28,727 net acres of oil and gas properties and interests in 40 wells located in the Niobrara formation of the DJ Basin, Colorado, including approximately 2,200 net acres in the Wattenberg Area, for $30 million in cash (subject to customary post-closing adjustments).
The Company paid $1.5 million of the purchase price as a deposit upon entering into the Purchase Agreement (the “Deposit”). The final purchase price after adjustments was $28,521,822, resulting in $27,031,822 due to Continental after applying the Deposit (the “Final Purchase Price”) (representing an adjusted total of 27,990 net acres at closing).
On March 7, 2014, the Company completed the Continental Acquisition and used a portion of funds from the initial closing of a $50 million financing facility with RJ Credit LLC. and other lenders of which $34.5 million was borrowed initially to pay the Final Purchase Price to acquire Continental's properties. As described below, the Note Purchase Agreement further provided that the Company convey 50% of the lease acreage and working interests acquired from Continental to RJ Resources Corp. ("RJ Corp.") as additional consideration for the financing.
The following table summarizes the allocation of the purchase price to the net assets acquired:
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Fair value at March 7, 2014
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||||
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Accounts receivable – oil and gas
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$
|
445,749
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||
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Inventory
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396,482
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|||
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Oil and gas properties, subject to amortization
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26,039,697
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|||
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Oil and gas properties, not subject to amortization
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2,694,029
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|||
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Total assets
|
|
29,575,957
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||
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Current liabilities
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(948,848)
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|||
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Asset retirement obligations
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(105,287)
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|||
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Total liabilities
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(1,054,135)
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|||
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Final purchase price
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$
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28,521,822
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Note Purchase Agreement and Sale of Secured Promissory Notes
On March 7, 2014, the Company entered into a $50 million financing facility between the Company, BRe BCLIC Primary, BRe BCLIC Sub, BRe WNIC 2013 LTC Primary, BRe WNIC 2013 LTC Sub, and RJ Credit LLC (“RJC”), as investors (collectively, the “Investors”), and BAM Administrative Services LLC, as agent for the Investors (the “Agent”). Pursuant to the Note Purchase, the Company initially issued the Investors' Secured Promissory Notes in the aggregate amount of $34.5 million (the “Initial Notes”) and provided for an additional $15.5 million available under the financing agreement to fund the Company’s future drilling costs.
The Initial Notes bear interest at the rate of 15% per annum, payable monthly in arrears, on the first business day of each month beginning April 1, 2014 (in connection with the Initial Notes), provided that upon the occurrence of an event of default, the Initial Notes bear interest at the lesser of 30% per annum and the maximum legal rate of interest allowable by law. We can prepay all or any portion of the principal amount of Initial Notes, without premium or penalty. The Initial Notes include customary events of default.
The Initial Notes are due and payable on March 6, 2017 (the “Maturity Date”), and may be repaid in full without premium or penalty at any time. Additionally, we are required on the third business day of each month, commencing on April 1, 2014, to prepay the Initial Notes in an amount equal to the lesser of (a) the outstanding principal amount of the Initial Notes or (b) twenty-five percent (25%) of the aggregate of all net revenues actually received by us and our subsidiaries (other than net revenues received by Asia Sixth, unless and to the extent received by us in the United States) or for the immediately preceding calendar month (or such pro rata portion of the first month the payment is required). The Initial Notes also provide that RJC is to be repaid (i) accrued interest, only after all of the other Investors are repaid any accrued interest due and (ii) principal, only after all of the other Investors are repaid the full amount of principal due under their Initial Notes, and (iii) that any funding in connection with Subsequent Notes will be made solely by RJC.
4
The amount outstanding under the Initial Notes is secured by a first priority security interest in all of our subsidiaries, assets, property, real property, intellectual property, securities and proceeds therefrom, granted in favor of the agent for the benefit of the Investors. Additionally, the Company granted a mortgage and security interest in all of our and our subsidiaries real property as located in the state of Colorado (including those assets acquired pursuant to the Continental Acquisition (the “Acquired Assets”)) and the state of Texas. Additionally, our obligations under the Initial Notes, Note Purchase Agreement and related agreements were guaranteed by our wholly-owned and majority owned direct and indirect subsidiaries.
As additional consideration for RJC providing the loan evidenced by its Initial Notes and agreeing to provide the funding from the Subsequent Notes, on March 7, 2014, the Company entered into the following transactions in favor of RJC and its affiliate RJ Corp.
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●
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Red Hawk Purchase - A Purchase and Sale Agreement between Pacific Energy Development Corp.’s (the Company’s wholly-owned subsidiary, “PEDCO”), the Company’s wholly-owned subsidiary, Red Hawk, and RJ Corp. (the “Red Hawk Purchase”); which required the Company to convey 50% of the mineral interests and leases acquired in the Continental Acquisition to RJ Corp. The agreement also provided that for three years from March 7, 2014, RJ Corp. does not have the right to propose or conduct any operations on the property acquired pursuant to the Red Hawk Purchase, unless (a) approved by Red Hawk, or (b) unless Red Hawk fails to execute the portion of the then current capital expenditure plan related to such applicable assets, provided that RJ Corp. may not (i) propose to drill more wells on such lands during the calendar year covered by such capital expenditure plan than are prescribed in the portion of such applicable capital expenditure plan and (ii) propose or conduct any operations on such lands during the following calendar year in excess of the operations budgeted for in the portion of such applicable capital expenditure plan.
|
|
●
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Asia Sixth Purchase - The Asia Sixth Purchase Agreement between PEDCO and RJ Corp. (the “Asia Sixth Purchase”); the principal terms of which required the conveyance of 50% of the Company’s 51% interest in Asia Sixth once acquired by PEDCO and if any part of the $10 million deposit previously paid by the Company in connection with the Shares Subscription Agreement is returned to the Company, 50% of any such returned funds will be paid to RJ Corp.
|
|
●
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Membership Purchase and Plan of Merger - A Membership Interest Purchase Agreement between PEDCO and RJ Corp. (the “Membership Purchase”), pursuant to which (i) PEDCO transferred 50% ownership of PEDCO MSL Merger Sub, LLC, a Nevada limited liability company (“MSL Merger Sub”), which was wholly-owned by PEDCO to RJ Corp., (ii) PEDCO’s wholly-owned subsidiary, Pacific Energy Development MSL, LLC (“PEDCO MSL”) merged with and into MSL Merger Sub, with MSL Merger Sub being the surviving entity in the merger, and (iii) MSL Merger Sub changed its name to Pacific Energy Development MSL, LLC. The effective result of the Membership Purchase and Plan of Merger was that RJ Corp. now owns 50% of PEDCO MSL, which owns all of the interests in the Mississippian Asset.
|
As a result of the transactions effected by the Red Hawk Purchase, Asia Sixth Purchase, Membership Purchase and Plan of Merger, RJ Corp. acquired ownership of 50% of all of the Company’s oil and gas assets and properties acquired in connection with the Continental Acquisition, rights to 50% of the Company's right to acquire Asia Sixth which owns the oil and gas assets and properties in Kazakhstan pursuant to the Shares Subscription Agreement, and effective ownership of 50% of the Mississippian Asset. In return, the Company received the financing agreement to acquire the Continental Assets and provide for future drilling funds and obtain a strategic partner to fund its own portion of the drilling costs for the development of the Company’s properties.
In connection with the financing with RJ Corp, the Company allocated a portion of the proceeds from the financing to the promissory notes and a portion to the sales of (i) 50% of the Acquired Assets, (ii) 50% of the Company's investment in Asia Sixth and (iii) 50% of the Mississippian Asset on a relative fair value basis. To the extent the proceeds of the financing exceed the portion allocated to the debt the Company recorded a debt discount. To the extent the sales price attributable to the assets was less than the net book value, the Company recorded a loss on sale of assets.
The components of this transaction are as follows:
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March 7, 2014
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||||
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Gross proceeds from issuance of Initial Notes
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$ | 34,500,000 | ||
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Deferred financing costs – paid underwriting fees
|
(5,381,755 | ) | ||
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Original debt issue discount
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(1,725,000 | ) | ||
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Net Proceeds
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$ | 27,393,245 | ||
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Allocation of proceeds to debt and sale of properties:
|
||||
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Allocation of proceeds to sale of assets (recorded as additional debt issue discount)
|
||||
|
Allocated to Acquired Assets sold
|
8,747,058 | |||
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Allocated to Mississippian Assets sold
|
1,615,488 | |||
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Allocated to Asia Sixth interest sold
|
3,055,374 | |||
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Net proceeds allocated to sales of properties
|
13,417,920 | |||
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Net proceeds allocated to Initial Notes
|
21,082,080 | |||
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Total Proceeds
|
$ | 34,500,000 | ||
5
Accordingly, total debt discount including the original issue discount and the amount allocated to the sale of assets was $15,142,920. In addition, additional deferred financing costs for the issuance of 1,000,000 warrants to a placement agent with a fair value of $1,519,601 was recorded.
2. BACKGROUND AND BASIS OF PRESENTATION
The statements of revenues and direct operating expenses of the Acquired Assets, for each of the two years ended December 31, 2013 and 2012 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 Continental; 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 Continental are included herein. Because the Acquired Assets were not a separate legal entity, 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 of Continental. 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 it been the Company’s business due to the differing size, structure, and accounting policies of the Company and Continental. 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.
Costs Incurred
There were no additional acquisition costs, exploration costs or development costs during the periods presented in the Statements of Revenues and Direct Operating Expenses.
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, 2013 through the financial statement issuance date for subsequent event disclosure consideration and has disclosed all necessary transactions.
6
SUPPLEMENTARY RESERVE INFORMATION (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, 2013 and 2012 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 2013 and 2012, the reserve estimates set forth below were prepared by South Texas Reservoir Alliance, LLC (“STXRA”), a related party, using reserve definitions and pricing requirements prescribed by the SEC. STXRA is a professional engineering firm certified by the Texas Board of Professional Engineers (Registration number F-13460).
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, 2013 and 2012.
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)
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(Mmcf)
|
|||||||
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Proved Developed Producing
|
216.6
|
391.6
|
||||||
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Proved Developed Non-Producing
|
-
|
-
|
||||||
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Total Proved Developed
|
216.6
|
391.6
|
||||||
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Proved Undeveloped
|
3,692.8
|
7,622.0
|
||||||
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Total Proved as of December 31, 2013
|
3,909.4
|
8,013.6
|
||||||
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2013
|
||||||||
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Oil
|
Gas
|
|||||||
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(MBbls)
|
(Mmcf)
|
|||||||
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Total Proved Reserves:
|
||||||||
|
Beginning of year
|
3,939.4
|
8,069.8
|
||||||
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Extensions and discoveries
|
21.0
|
30.6
|
||||||
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Revisions of previous estimates
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-
|
-
|
||||||
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Purchase of minerals in place
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-
|
-
|
||||||
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Production
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(51.0
|
)
|
(86.8)
|
|||||
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End of year proved reserves
|
3,909.4
|
8,013.6
|
||||||
7
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
Proved reserves at December 31, 2012 are set forth below (in thousands):
|
2012
|
||||||||
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Oil
|
Gas
|
|||||||
|
(MBbls)
|
(Mmcf)
|
|||||||
|
Proved Developed Producing
|
150.2
|
292.3
|
||||||
|
Proved Developed Non-Producing
|
-
|
-
|
||||||
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Total Proved Developed
|
150.2
|
292.3
|
||||||
|
Proved Undeveloped
|
3,788.8
|
7,777.5
|
||||||
|
Total Proved as of December 31, 2012
|
3,939.0
|
8,069.8
|
||||||
|
2012
|
||||||||
|
Oil
|
Gas
|
|||||||
|
(MBbls)
|
(Mmcf)
|
|||||||
|
Total Proved Reserves:
|
||||||||
|
Beginning of year
|
3,983.9
|
8,149.8
|
||||||
|
Extensions and discoveries
|
21.0
|
30.0
|
||||||
|
Revisions of previous estimates
|
-
|
-
|
||||||
|
Purchase of minerals in place
|
-
|
-
|
||||||
|
Production
|
(65.9
|
)
|
(110.0
|
)
|
||||
|
End of year proved reserves
|
3,939.0
|
8,069.8
|
||||||
PV-10 of Estimated Quantities of Proved Oil and Gas (Unaudited)
The following table is a summary of PV-10 attributable to the Acquired Assets at December 31, 2012.
|
Category
|
Net Oil Reserves (MBbls)
|
Net Gas Reserves (Mmcf)
|
Net Present Value Undiscounted (in millions)
|
Net Present Value Discounted 10% (in millions) | ||||||||||||
|
Proved Developed Producing Reserves
|
150.2
|
292.3
|
$
|
9,710
|
$ |
6,825
|
||||||||||
|
Proved Undeveloped Reserves
|
3,788.8
|
7,777.5
|
$
|
125,181
|
$ |
31,599
|
||||||||||
|
Combined Proved Reserves
|
3,939.0
|
8,069.8
|
$
|
134,891
|
$ |
38,424
|
||||||||||
The following table is a summary of PV-10 attributable to the Acquired Assets at December 31, 2013.
|
Category
|
Net Oil Reserves (MBbls)
|
Net Gas Reserves (Mmcf)
|
Net Present Value Undiscounted (in millions)
|
Net Present Value Discounted 10% (in millions) | ||||||||||||
|
Proved Developed Producing Reserves
|
216.6
|
391.6
|
$
|
13,254
|
$ |
9,210
|
||||||||||
|
Proved Undeveloped Reserves
|
3,692.8
|
7,622.0
|
$
|
123,301
|
$ |
34,511
|
||||||||||
|
Combined Proved Reserves
|
3,909.4
|
8,013.6
|
$
|
136,555
|
$ |
43,721
|
||||||||||
The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent (10%). PV-10 is considered a non-GAAP financial measure as defined by the SEC. PV-10 differs from Standardized Measure because it does not include the effect of income taxes. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
8
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the standardized measure of discounted future net cash flows set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2013 and 2012, respectively. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2013. The average prices utilized for purposes of estimating our proved reserves were $87.35 per barrel of oil and $8.39 per Mcf of natural gas for our properties, adjusted by property for energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of our reserves. Accordingly, significant changes to these estimates can be expected as future information becomes available.
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, 2013 (in thousands):
|
($ 000's)
|
||||
|
For the year ended December 31, 2013
|
||||
|
Future cash inflows
|
$
|
408,724
|
||
|
Future production costs
|
(94,631
|
)
|
||
|
Future development costs
|
(148,446
|
)
|
||
|
Future income tax expense
|
(64,822
|
)
|
||
|
Future net cash flows
|
100,825
|
|||
|
10% annual discount
|
(86,188
|
)
|
||
|
Standardized measure of discounted future net cash flows
|
$
|
14,637
|
||
Changes in Standardized Measure of Discounted Future Cash Flows
|
($ 000's)
|
||||
|
Beginning of year
|
$
|
17,491
|
||
|
Sales and transfers of oil and gas produced, net of production costs
|
(5,836
|
)
|
||
|
Net changes in prices and production costs
|
6,753
|
|||
|
Extensions, discoveries, additions and improved recovery, net of related costs
|
3,606
|
|||
|
Development costs incurred
|
3,808
|
|||
| Changes in estimated future development costs | (3,312 | ) | ||
|
Revisions of estimated development costs
|
-
|
|||
|
Revisions of previous quantity estimates
|
891
|
|||
|
Accretion of discount
|
3,842
|
|||
|
Net change in income taxes
|
(8,152
|
)
|
||
|
Purchases of reserves in place
|
-
|
|||
|
Sales of reserves in place
|
-
|
|||
|
Changes in timing and other
|
(4,454
|
) | ||
|
End of year
|
$
|
14,637
|
||
9
The following table sets forth the standardized measure of discounted future net cash flows relating to the proved reserves as of December 31, 2012 (in thousands):
|
($ 000's)
|
||||
|
For the year ended December 31, 2012
|
||||
|
Future cash inflows
|
$
|
411,776
|
||
|
Future production costs
|
(123,697
|
)
|
||
|
Future development costs
|
(153,191
|
)
|
||
|
Future income tax expense
|
(52,794
|
)
|
||
|
Future net cash flows
|
82,094
|
|||
|
10% annual discount
|
(64,603
|
)
|
||
|
Standardized measure of discounted future net cash flows
|
$
|
17,491
|
||
Changes in Standardized Measure of Discounted Future Cash Flows
|
($ 000's)
|
||||
|
Beginning of year
|
$
|
20,822
|
||
|
Sales and transfers of oil and gas produced, net of production costs
|
(5,947)
|
|||
|
Net changes in prices and production costs
|
(1,234
|
) | ||
|
Extensions, discoveries, additions and improved recovery, net of related costs
|
-
|
|||
|
Development costs incurred
|
5,637
|
|||
| Changes in estimated future development costs | (4,485 | ) | ||
|
Revisions of estimated development costs
|
-
|
|||
|
Revisions of previous quantity estimates
|
1,604
|
|||
|
Accretion of discount
|
3,413
|
|||
|
Net change in income taxes
|
(7,620
|
)
|
||
|
Purchases of reserves in place
|
-
|
|||
|
Sales of reserves in place
|
-
|
|||
|
Changes in timing and other
|
5,301
|
|||
|
End of year
|
$
|
17,491
|
||
10