Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
Dec. 31, 2013 | Mar. 27, 2014 | Jun. 30, 2013 | |
Document and Entity Information [Abstract] | ' | ' | ' |
Entity Registrant Name | 'FIELDPOINT PETROLEUM CORP | ' | ' |
Entity Central Index Key | '0000316736 | ' | ' |
Current Fiscal Year End Date | '--12-31 | ' | ' |
Entity Well-known Seasoned Issuer | 'No | ' | ' |
Entity Voluntary Filers | 'No | ' | ' |
Entity Current Reporting Status | 'Yes | ' | ' |
Entity Filer Category | 'Smaller Reporting Company | ' | ' |
Entity Public Float | ' | ' | $17,859,293 |
Entity Common Stock, Shares Outstanding | ' | 8,066,336 | ' |
Document Fiscal Year Focus | '2013 | ' | ' |
Document Fiscal Period Focus | 'FY | ' | ' |
Document Type | '10-K | ' | ' |
Amendment Flag | 'false | ' | ' |
Document Period End Date | 31-Dec-13 | ' | ' |
CONSOLIDATED_BALANCE_SHEETS
CONSOLIDATED BALANCE SHEETS (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
CURRENT ASSETS: | ' | ' |
Cash and cash equivalents | $2,648,487 | $1,408,075 |
Certificates of deposit | 44,721 | 44,702 |
Accounts receivable: | ' | ' |
Oil and natural gas sales | 1,078,333 | 1,193,495 |
Joint interest billings, less allowance for doubtful accounts of approximately $174,000 each period | 226,743 | 229,406 |
Income taxes receivable | 319,097 | 196,555 |
Deferred income tax asset-current | 64,000 | 171,000 |
Prepaid expenses and other current assets | 64,751 | 42,349 |
Total current assets | 4,446,132 | 3,285,582 |
PROPERTY AND EQUIPMENT: | ' | ' |
Oil and natural gas properties (successful efforts method) | 35,256,754 | 32,210,252 |
Other equipment | 62,836 | 52,113 |
Less accumulated depletion and depreciation | -14,802,894 | -12,412,517 |
Net property and equipment | 20,516,696 | 19,849,848 |
Total assets | 24,962,828 | 23,135,430 |
CURRENT LIABILITIES: | ' | ' |
Accounts payable and accrued expenses | 742,493 | 889,796 |
Oil and natural gas revenues payable | 240,588 | 286,234 |
Unrealized loss on commodity derivatives | 4,000 | 0 |
Total current liabilities | 987,081 | 1,176,030 |
LINE OF CREDIT | 6,740,000 | 6,740,000 |
DEFERRED INCOME TAXES | 2,973,000 | 2,442,000 |
ASSET RETIREMENT OBLIGATION | 1,712,685 | 1,595,935 |
Total liabilities | 12,412,766 | 11,953,965 |
COMMITMENTS AND CONTINGENCIES (Notes 9 and 10) | ' | ' |
STOCKHOLDERS' EQUITY: | ' | ' |
Common stock, $.01 par value, 75,000,000 shares authorized; 8,993,336 and 8,970,936 shares issued, respectively; and 8,066,336 and 8,043,936 outstanding, respectively | 89,933 | 89,709 |
Additional paid-in capital | 11,751,298 | 11,661,922 |
Retained earnings | 2,675,723 | 1,396,726 |
Treasury stock, 927,000 shares, each period, at cost | -1,966,892 | -1,966,892 |
Total stockholders' equity | 12,550,062 | 11,181,465 |
Total liabilities and stockholders' equity | $24,962,828 | $23,135,430 |
CONSOLIDATED_BALANCE_SHEETS_Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
Accounts receivable: | ' | ' |
Allowance for doubtful accounts of joint interest billings | $174,000 | $174,000 |
STOCKHOLDERS' EQUITY: | ' | ' |
Common stock, par value (in dollars per share) | $0.01 | $0.01 |
Common stock, shares authorized (in shares) | 75,000,000 | 75,000,000 |
Common stock, shares issued (in shares) | 8,993,336 | 8,970,936 |
Common stock, shares outstanding (in shares) | 8,066,336 | 8,043,936 |
Treasury stock, shares (in shares) | 927,000 | 927,000 |
CONSOLIDATED_STATEMENTS_OF_OPE
CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
REVENUE: | ' | ' |
Oil and natural gas sales | $10,325,380 | $10,240,628 |
Well operational and pumping fees | 25,877 | 68,265 |
Disposal fees | 189,974 | 93,996 |
Total revenue | 10,541,231 | 10,402,889 |
COSTS AND EXPENSES: | ' | ' |
Lease operating | 3,909,637 | 3,326,624 |
Depletion and depreciation | 2,395,000 | 2,092,000 |
Exploration expense | 152,650 | 0 |
Impairment of oil and natural gas properties | 485,999 | 204,190 |
Accretion of discount on asset retirement obligations | 96,000 | 91,000 |
General and administrative | 1,206,389 | 1,600,566 |
Total costs and expenses | 8,245,675 | 7,314,380 |
OPERATING INCOME | 2,295,556 | 3,088,509 |
OTHER INCOME (EXPENSE): | ' | ' |
Interest income | 2,783 | 2,389 |
Interest expense | -259,016 | -264,120 |
Unrealized loss on commodity derivatives | -4,000 | 0 |
Realized gain on commodity derivatives | 0 | 254,151 |
Gain on sale of oil and natural gas property | 4,000 | 204,000 |
Miscellaneous | 6,744 | 1,334 |
Total other income (expense) | -249,489 | 197,754 |
INCOME BEFORE INCOME TAXES | 2,046,067 | 3,286,263 |
INCOME TAX PROVISION - current | -129,070 | -312,000 |
INCOME TAX PROVISION - deferred | -638,000 | -862,000 |
TOTAL INCOME TAX PROVISION | -767,070 | -1,174,000 |
NET INCOME | $1,278,997 | $2,112,263 |
EARNINGS PER SHARE: | ' | ' |
BASIC (in dollars per share) | $0.16 | $0.26 |
DILUTED (in dollars per share) | $0.15 | $0.25 |
WEIGHTED AVERAGE SHARES OUTSTANDING: | ' | ' |
Basic (in shares) | 8,062,167 | 8,006,959 |
Diluted (in shares) | 8,385,253 | 8,452,429 |
CONSOLIDATED_STATEMENTS_OF_CHA
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (USD $) | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Treasury Stock [Member] | Total |
BALANCES at Dec. 31, 2011 | $89,101 | $4,573,580 | $6,179,824 | ($1,966,892) | $8,875,613 |
BALANCES (in shares) at Dec. 31, 2011 | 8,910,175 | ' | ' | 927,000 | ' |
At-the-market offering (in shares) | 60,761 | ' | ' | 0 | ' |
At-the-market offering | 608 | 192,981 | 0 | 0 | 193,589 |
Stock warrant dividend | 0 | 6,895,361 | -6,895,361 | 0 | 0 |
Net income | 0 | 0 | 2,112,263 | 0 | 2,112,263 |
BALANCES at Dec. 31, 2012 | 89,709 | 11,661,922 | 1,396,726 | -1,966,892 | 11,181,465 |
BALANCES (in shares) at Dec. 31, 2012 | 8,970,936 | ' | ' | 927,000 | ' |
Common stock issued from exercise of warrants | 224 | 89,376 | 0 | 0 | 89,600 |
Common stock issued from exercise of warrants (in shares) | 22,400 | ' | ' | 0 | ' |
Net income | 0 | 0 | 1,278,997 | 0 | 1,278,997 |
BALANCES at Dec. 31, 2013 | $89,933 | $11,751,298 | $2,675,723 | ($1,966,892) | $12,550,062 |
BALANCES (in shares) at Dec. 31, 2013 | 8,993,336 | ' | ' | 927,000 | ' |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' |
Net income | $1,278,997 | $2,112,263 |
Adjustments to reconcile net income to net cash provided by operating activities: | ' | ' |
Gain on sale of oil and natural gas properties | -4,000 | -204,000 |
Unrealized loss on commodity derivatives | 4,000 | 0 |
Depletion and depreciation | 2,395,000 | 2,092,000 |
Exploration expense | 152,650 | 0 |
Impairment of oil and natural gas properties | 485,999 | 204,190 |
Deferred income tax expense | 638,000 | 862,000 |
Accretion of discount on asset retirement obligations | 96,000 | 91,000 |
Changes in current assets and liabilities: | ' | ' |
Accounts receivable | 117,825 | -206,667 |
Income taxes receivable | -122,542 | 135,579 |
Prepaid expenses and other current assets | -22,402 | 79,396 |
Accounts payable and accrued expenses | -291,205 | -1,858,934 |
Oil and natural gas revenues payable | -45,646 | 27,105 |
Other | -19 | -233 |
Net cash provided by operating activities | 4,682,657 | 3,333,699 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' |
Additions to oil and natural gas properties and other equipment | -3,536,845 | -4,360,806 |
Proceeds from the sale of oil and natural gas properties | 5,000 | 204,000 |
Net cash used in investing activities | -3,531,845 | -4,156,806 |
CASH FLOWS FROM FINANCING ACTIVITIES: | ' | ' |
Sale of common stock | 0 | 193,589 |
Common stock issued from the exercise of warrants | 89,600 | 0 |
Net cash provided by financing activities | 89,600 | 193,589 |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 1,240,412 | -629,518 |
CASH AND CASH EQUIVALENTS, beginning of year | 1,408,075 | 2,037,593 |
CASH AND CASH EQUIVALENTS, end of the year | 2,648,487 | 1,408,075 |
SUPPLEMENTAL INFORMATION: | ' | ' |
Cash paid during the year for interest | 199,405 | 264,120 |
Cash paid during the year for income taxes | 334,595 | 5,410 |
Capital items in accounts payable | $143,902 | $210,518 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | ' | ||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ' | ||||||||
1 | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||||||||
Organization and Nature of Operations | |||||||||
FieldPoint Petroleum Corporation (the "Company", "we" or "our") is incorporated under the laws of the state of Colorado. We are engaged in the acquisition, operation and development of oil and natural gas properties, which are located in Louisiana, New Mexico, Oklahoma, South Central Texas and Wyoming as of December 31, 2013 and 2012. | |||||||||
Consolidation Policy | |||||||||
Our consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Bass Petroleum, Inc., and Raya Energy Corp. All material intercompany accounts and transactions have been eliminated in consolidation. | |||||||||
Cash and Cash Equivalents | |||||||||
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At times, we maintain deposit balances in excess of FDIC insurance limits. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on cash and cash equivalents. | |||||||||
Certificates of Deposit | |||||||||
Certificates of deposit have original maturities ranging from three months to one year and are recorded at fair value on the balance sheet in current assets. Changes in fair value during the period are classified as realized or unrealized holding gains in other income. | |||||||||
Oil and Natural Gas Properties | |||||||||
Our oil and natural gas properties consisted of the following at December 31: | |||||||||
2013 | 2012 | ||||||||
Mineral interests in properties: | |||||||||
Unproved properties | $ | 850,000 | $ | 850,000 | |||||
Proved properties | 14,250,230 | 15,098,352 | |||||||
Wells and related equipment and facilities | 20,156,524 | 16,261,900 | |||||||
Total costs | 35,256,754 | 32,210,252 | |||||||
Less accumulated depletion and depreciation | (14,763,266 | ) | (12,378,889 | ) | |||||
$ | 20,493,488 | $ | 19,831,363 | ||||||
We follow the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have found proved reserves. If we determine that the wells have not found proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determinations of whether the wells found proved reserves at December 31, 2013 or 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. | |||||||||
We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2013, we have capitalized no interest costs because our exploration and development projects generally last less than six months. Costs to maintain wells and related equipment are charged to expense as incurred. | |||||||||
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and depreciation are eliminated from the property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the amount received is treated as a reduction of the cost of the interest retained. | |||||||||
Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method of proved reserves using the unit conversion ratio of 6 Mcf of gas to 1 bbl of oil. Depletion and depreciation expense for oil and natural gas producing property and related equipment was $2,389,000 and $2,086,000 for the years ended December 31, 2013 and 2012, respectively. | |||||||||
Unproved oil and natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. No impairment of unproved properties was recorded during the years ended December 31, 2013 or 2012. | |||||||||
Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows, which is a non-recurring fair value measurement classified as Level 3 in the fair value hierarchy. We recorded an impairment on our proved oil and natural gas properties of $485,999 and $204,190 during the years ended December 31, 2013 and 2012, respectively. | |||||||||
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. | |||||||||
Oil and Natural Gas Sales Receivable | |||||||||
Oil and natural gas sales receivable principally consist of accrued oil and natural gas sales proceeds receivable and are typically collected within 35 days from the end of the month in which the related quantities are produced. We ordinarily do not require collateral for such receivables, nor do we charge interest on past due balances. We periodically review accounts receivable for collectability and reduce the carrying amount of the accounts receivable by an allowance. No such allowance was indicated at December 31, 2013 or 2012. As of December 31, 2013, our accounts receivable were primarily with several independent purchasers of our crude oil and natural gas production. At December 31, 2013, we had balances due from two customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These two customers accounted for 75% of accounts receivable at December 31, 2013. At December 31, 2012, we had balances due from two customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These two customers accounted for 63% of accounts receivable at December 31, 2012. In the event that one or more of these significant customers ceases doing business with us, we believe that there are potential alternative customers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost customers. | |||||||||
Joint Interest Billings Receivable and Oil and Natural Gas Revenues Payable | |||||||||
Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Company operates. The receivable is recognized when the cost is incurred and the related payable and the Company's share of the cost is recorded. We often have the ability to offset amounts due against the participant's share of production from the related property. | |||||||||
The Company uses the reserve for bad debt method of valuing doubtful joint interest billings receivable based on historical experience, coupled with a review of the current status of existing receivables. The balance of the reserve for doubtful accounts, deducted against joint interest billings receivable to properly reflect the realizable value was approximately $174,000 at December 31, 2013 and 2012. | |||||||||
Oil and natural gas revenues payable represents amounts due to third party revenue interest owners for their share of oil and natural gas revenue collected on their behalf by the Company. The payable is recorded when the Company recognizes oil and natural gas sales and records the related oil and natural gas sales receivable. | |||||||||
Other Property | |||||||||
Other assets classified as property and equipment are primarily office furniture and equipment and vehicles, which are carried at cost. Depreciation is provided using the straight-line method over estimated useful lives ranging from three to five years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $6,000 for each of the years ended December 31, 2013 and 2012. | |||||||||
Asset Retirement Obligations | |||||||||
Our financial statements reflect our asset retirement obligations, consisting of future plugging and abandonment expenditures related to our oil and natural gas properties, which can be reasonably estimated. The asset retirement obligation is recorded at fair value on a discounted basis as a liability at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheets. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations. | |||||||||
The following is a reconciliation of the Company's asset retirement obligations for the years ended December 31: | |||||||||
2013 | 2012 | ||||||||
Asset retirement obligation at January 1, | $ | 1,595,935 | $ | 1,515,002 | |||||
Accretion of discount | 96,000 | 91,000 | |||||||
Liabilities incurred during the year | 22,000 | 22,000 | |||||||
Liabilities settled during the year | (1,250 | ) | (32,067 | ) | |||||
Asset retirement obligation at December 31, | $ | 1,712,685 | $ | 1,595,935 | |||||
The entire balance was classified as a non-current liability at December 31, 2013 and 2012. | |||||||||
Income Taxes | |||||||||
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due, if any, plus net deferred taxes related to differences between the bases of assets and liabilities for financial and income tax reporting. Deferred tax assets and liabilities represent the future tax consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Valuation allowances are recognized to limit recognition of deferred tax assets where appropriate. Such allowances may be reversed when circumstances provide evidence that the deferred tax assets will more likely than not be realized. | |||||||||
Production Taxes and Ad Valorem Taxes | |||||||||
Production taxes and ad valorem taxes are included in production expense. Total production and ad valorem taxes were $1,194,443 and $1,297,165 for the years ended December 31, 2013 and 2012, respectively. | |||||||||
Use of Estimates and Certain Significant Estimates | |||||||||
The preparation of the Company's financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company's management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which as described above may affect the amount at which oil and natural gas properties are recorded. The Company's allowance for doubtful accounts is a significant estimate and is based on management's estimates of uncollectible receivables. The asset retirement obligations require estimates of future plugging and abandonment expenditures. It is at least reasonably possible these estimates could be revised in the near term and the revisions could be material. | |||||||||
Our estimates of proved reserves materially impact depletion and impairment expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems at our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment. | |||||||||
Our proved reserve estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil and natural gas actually produced. | |||||||||
Revenue Recognition | |||||||||
The Company uses the sales method of accounting for oil and natural gas revenues. Under this method, revenues are based on actual volumes of oil and natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Company is entitled based on its interest in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows. There were no material natural gas imbalances as of December 31, 2013 and 2012. | |||||||||
We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from those purchasers are collectible. | |||||||||
As previously discussed, we sold our crude oil and natural gas production to several independent purchasers. During the year ended December 31, 2013, we had sales of 10% or more of our total oil and natural gas sales revenue to two customers which represented 71% of total oil and natural gas sales revenue for the year ended December 31, 2013. During the year ended December 31, 2012, we had sales of 10% or more of our total oil and natural gas sales revenue to four customers which represented 64% of total oil and natural gas sales revenue for the year ended December 31, 2012. | |||||||||
Comprehensive Income | |||||||||
The Company has no elements of comprehensive income other than net income. | |||||||||
Share-Based Compensation | |||||||||
We measure and record compensation expense for all share-based payment awards to employees and directors based on estimated fair values. Additionally, compensation costs for share-based awards are recognized over the requisite grant-date service period based on the grant-date fair value. There were no outstanding share-based awards during 2013 or 2012. | |||||||||
Financial Instruments | |||||||||
The Company's financial instruments are cash, certificates of deposit, accounts receivable and payable and long-term debt. Management believes the fair values of these instruments, with the exception of the long-term debt, approximate the carrying values, due to the short-term nature of the instruments. Management believes the fair value of long-term debt also reasonably approximates its carrying value, based on expected cash flows and interest rates. |
OIL_AND_NATURAL_GAS_PROPERTIES
OIL AND NATURAL GAS PROPERTIES | 12 Months Ended | |
Dec. 31, 2013 | ||
OIL AND NATURAL GAS PROPERTIES [Abstract] | ' | |
OIL AND NATURAL GAS PROPERTIES | ' | |
2 | OIL AND NATURAL GAS PROPERTIES | |
The Company made no purchases of oil and natural gas properties during the years ended December 31, 2013 and 2012. The Company drilled a successful developmental well in New Mexico in 2013, for which the net cost to the Company was approximately $3,000,000. The Company also drilled a successful developmental well in New Mexico in 2012, for which the net cost to the Company was approximately $3,000,000. | ||
The Company sold its interest in the Stauss Field in October 2013 for net proceeds of $5,000. A gain of $4,000 was recognized on the sale as the property had been previously impaired. The Company sold its interest in the South Vacuum Field in October 2012 for net proceeds of $204,000. A gain of $204,000 was recognized in 2012 on the sale as the property had been fully impaired. | ||
The Irby #1 on the Riverdale Prospect in Goliad County, Texas, was drilled and deemed to be non-economic after analyzing the electric logs. The decision was made to plug and abandon the well and no other exploratory wells are planned for this prospect. Dry hole expenses of $152,650 were recognized for the twelve months ending December 31, 2013. No dry hole expenses were recognized in 2012. |
RELATED_PARTY_TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended | |
Dec. 31, 2013 | ||
RELATED PARTY TRANSACTIONS [Abstract] | ' | |
RELATED PARTY TRANSACTIONS | ' | |
3 | RELATED PARTY TRANSACTIONS | |
The Company leases office space from the estate of its former president. Rent expense for this month-to-month lease was $30,000 for each of the years ended December 31, 2013 and 2012, respectively. |
COMMODITY_DERIVATIVES
COMMODITY DERIVATIVES | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
COMMODITY DERIVATIVES [Abstract] | ' | ||||||||||||||||
COMMODITY DERIVATIVES | ' | ||||||||||||||||
4 | COMMODITY DERIVATIVES | ||||||||||||||||
On September 26, 2013, we entered into the following commodity positions to hedge our oil production price risk, through March 31, 2014. The following positions were outstanding at December 31, 2013: | |||||||||||||||||
Period | Volume (Barrels) | $/Barrel | |||||||||||||||
Daily | Total | Floor | Ceiling | ||||||||||||||
NYMEX –WTI Collars Jan – March 2014 | 200 | 18,000 | $ | 87 | $ | 108 | |||||||||||
The following table summarizes the fair value of our open commodity derivatives as of December 31, 2013 and 2012: | |||||||||||||||||
Liability Derivatives | |||||||||||||||||
Fair Value | |||||||||||||||||
Balance Sheet | December 31, | December 31, | |||||||||||||||
Location | 2013 | 2012 | |||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||
Commodity derivatives | Current Liabilities | $ | 4,000 | $ | - | ||||||||||||
The following table summarizes the change in fair value of our commodity derivatives: | |||||||||||||||||
12 Months Ended | |||||||||||||||||
Income Statement | December 31, | ||||||||||||||||
Location | 2013 | 2012 | |||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||
Unrealized loss on commodity derivatives | Other Income (Expense) | $ | (4,000 | ) | $ | - | |||||||||||
Realized gain on commodity derivatives | Other Income (Expense) | $ | - | $ | 254,151 | ||||||||||||
Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of collar contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations. | |||||||||||||||||
We are exposed to credit losses in the event of non-performance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate non-performance by the counterparties over the term of the commodity derivatives positions. | |||||||||||||||||
To estimate the fair value of our commodity derivatives positions, we use 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. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows: | |||||||||||||||||
· | Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2013, we had no Level 1 measurements | ||||||||||||||||
· | Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist of commodity collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2013, all of our commodity derivatives were valued using Level 2 measurements. | ||||||||||||||||
· | Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At December 31, 2013, we had no Level 3 measurements. | ||||||||||||||||
Realized gains and losses are included in other income (expense) on our consolidated statements of operations. No realized gains were recognized for the year ending December 31, 2013. Realized gains were $254,151 for the year ending December 31, 2012. |
LINE_OF_CREDIT
LINE OF CREDIT | 12 Months Ended | |
Dec. 31, 2013 | ||
LINE OF CREDIT [Abstract] | ' | |
LINE OF CREDIT | ' | |
5 | LINE OF CREDIT | |
The Company has a line of credit with a bank with a borrowing base of $11,000,000 at December 31, 2013 and 2012, respectively. The amount outstanding under this line of credit was $6,740,000 as of December 31, 2013 and 2012. The agreement requires monthly interest-only payments until maturity on October 18, 2016. The interest rate is based on a LIBOR or Prime option. The Prime option provides for the interest rate to be prime plus a margin ranging between 1.75% and 2.25% and the LIBOR option to be the 3-month LIBOR rate plus a margin ranging between 2.75% and 3.25%, both depending on the borrowing base usage. Currently, we have elected the LIBOR interest rate option in which our interest rate was approximately 3.50% as of December 31, 2013 and 2012, respectively. The commitment fee is .50% of the unused borrowing base. The line of credit provides for certain financial covenants and ratios which include a current ratio, leverage ratio, and interest coverage ratio requirements. We were in compliance with our covenants as of December 31, 2013 and 2012. The credit line was amended on March 19, 2014 on the substantially identical terms, except that the requirement for a personal guarantee by the President and CEO was removed, and extended the maturity date to October 18, 2016. |
INCOME_TAXES
INCOME TAXES | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
INCOME TAXES [Abstract] | ' | ||||||||
INCOME TAXES | ' | ||||||||
6 | INCOME TAXES | ||||||||
Our provision for income taxes comprised the following (expense) benefit during the years ended December 31: | |||||||||
2013 | 2012 | ||||||||
Current: | |||||||||
Federal | $ | (109,000 | ) | $ | (248,000 | ) | |||
State | (20,070 | ) | (64,000 | ) | |||||
Total current | (129,070 | ) | (312,000 | ) | |||||
Deferred: | |||||||||
Federal | (590,000 | ) | (842,000 | ) | |||||
State | (48,000 | ) | (20,000 | ) | |||||
Total deferred | (638,000 | ) | (862,000 | ) | |||||
Total income tax provision | $ | (767,070 | ) | $ | (1,174,000 | ) | |||
Total income tax (expense) benefit differed from the amounts computed by applying the U.S. Federal statutory tax rates and estimated state rates to pre-tax income for the years ended December 31, 2013 and 2012 as follows: | |||||||||
2013 | 2012 | ||||||||
Statutory rate | 34 | % | 34 | % | |||||
State taxes, net of federal benefit | 3 | % | 2 | % | |||||
Effective rate | 37 | % | 36 | % | |||||
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax bases of assets and liabilities. | |||||||||
Significant components of net deferred tax assets and liabilities are: | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Deferred tax assets: | |||||||||
Asset retirement obligation | $ | 393,000 | $ | 357,000 | |||||
Allowance for doubtful accounts | 63,000 | 63,000 | |||||||
Accrued compensation and other | - | 109,000 | |||||||
Unrealized loss on commodity derivatives | 1,000 | - | |||||||
Alternative minimum tax credit carryforward | 80,000 | - | |||||||
Total deferred tax assets | 537,000 | 529,000 | |||||||
Deferred tax liability: | |||||||||
Difference in depreciation, depletion and capitalization methods – oil and gas properties | (3,446,000 | ) | (2,800,000 | ) | |||||
Total deferred tax liabilities | (3,446,000 | ) | (2,800,000 | ) | |||||
Net deferred tax liability | $ | (2,909,000 | ) | $ | (2,271,000 | ) | |||
Our net deferred tax assets and liabilities are recorded as follows: | |||||||||
2013 | 2012 | ||||||||
Current asset | $ | 64,000 | $ | 171,000 | |||||
Non-current liability | (2,973,000 | ) | (2,442,000 | ) | |||||
Total | $ | (2,909,000 | ) | $ | (2,271,000 | ) | |||
The Company had no material uncertain tax positions as of December 31, 2013 and 2012. | |||||||||
The Company's policy regarding income tax interest and penalties is to record those items as general and administrative expense. During the years ended December 31, 2013 and 2012, there were no significant income tax interest and penalty items in the income statement, nor as a liability on the balance sheet at December 31, 2013 and 2012. | |||||||||
The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Generally, the Company is no longer subject to U.S. federal or state income tax examination by tax authorities for years before 2010. The Company is not currently involved in any income tax examinations. |
EARNINGS_PER_SHARE
EARNINGS PER SHARE | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
EARNINGS PER SHARE [Abstract] | ' | ||||||||
EARNINGS PER SHARE | ' | ||||||||
7 | EARNINGS PER SHARE | ||||||||
Basic earnings per share are computed based on the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share take common stock equivalents (such as options and warrants) into consideration using the treasury stock method. The Company distributed warrants as a dividend to stockholders as of the record date, March 23, 2012. The dilutive effect of the warrants for the twelve months ended December 31, 2013 and 2012 is presented below. | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Net income | $ | 1,278,997 | $ | 2,112,263 | |||||
Weighted average common stock outstanding | 8,062,167 | 8,006,959 | |||||||
Weighted average dilutive effect of stock warrants | 323,086 | 445,470 | |||||||
Dilutive weighted average shares | 8,385,253 | 8,452,429 | |||||||
Earnings per share: | |||||||||
Basic | $ | 0.16 | $ | 0.26 | |||||
Diluted | $ | 0.15 | $ | 0.25 |
STOCKHOLDERS_EQUITY
STOCKHOLDERS' EQUITY | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
STOCKHOLDERS' EQUITY [Abstract] | ' | ||||
STOCKHOLDERS' EQUITY | ' | ||||
8 | STOCKHOLDERS' EQUITY | ||||
We approved a stock warrant dividend of one warrant per one common share outstanding in the fourth quarter of 2011 with the record date of March 23, 2012. A total of 7,983,175 warrants were issued and have an exercise price of $4.00. The warrants are exercisable over 6 years from the record date. The Company has the right to call the warrants in the future if the market price of the common stock exceeds 150% of the exercise price of the warrant ($6.00). The fair value of the warrants of approximately $8,000,000 was reclassified from retained earnings to additional paid in capital to the extent of available retained earnings of $6,895,361 on the record date. A total of 22,400 warrants to purchase an equal number of common shares for proceeds of $89,600 were exercised during the year ended December 31, 2013. The following table summarizes the warrants outstanding at December 31, 2012 and December 31, 2013: | |||||
Warrants outstanding, December 31, 2012 | 7,983,175 | ||||
Warrants exercised | (22,400 | ) | |||
Warrants outstanding, December 31, 2013 | 7,960,775 | ||||
Effective May 16, 2012, we executed an At Market Issuance Sales Agreement with MLV & Co., LLC ("MLV") providing for an at-the-market offering of securities of up to 900,000 shares of common stock (the "ATM Offering"). The ATM Offering was undertaken pursuant to Rule 415 and a universal shelf Registration Statement on Form S-3 which was declared effective by the SEC on December 9, 2011. We paid a sales commission equal to 7% of the gross sales price per share sold in addition to other costs to register the securities. Effective June 25, 2012 to December 31, 2012, we sold through MLV 60,761shares of common stock pursuant to this agreement for gross proceeds of $257,358. Expenses associated with the sale of common shares were $63,769 which includes commissions and other offering costs. No shares were sold in the year ended December 31, 2013. The Board of Directors terminated the ATM Offering in February, 2014. |
ENVIRONMENTAL_ISSUES
ENVIRONMENTAL ISSUES | 12 Months Ended | |
Dec. 31, 2013 | ||
ENVIRONMENTAL ISSUES [Abstract] | ' | |
ENVIRONMENTAL ISSUES | ' | |
9 | ENVIRONMENTAL ISSUES | |
We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and natural gas wells and the operation thereof. In our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company. No claim has been made, nor are we aware of any liability which we may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations relating thereto. |
COMMITMENTS
COMMITMENTS | 12 Months Ended | |
Dec. 31, 2013 | ||
COMMITMENTS [Abstract] | ' | |
COMMITMENTS | ' | |
10 | COMMITMENTS | |
As of December 31, 2013 and 2012, we had a $30,000 outstanding standby letter of credit in favor of the State of Wyoming as a plugging bond. The letter of credit is collateralized by our line of credit with Citibank. | ||
On November 12, 2013, we engaged Stephens, Inc. ("Stephens") to provide general financial and Investment Banking advice. Pursuant to the agreement we began paying Stephens a retainer of $10,000 per month, paid monthly in advance beginning January 1, 2014. The agreement can be terminated by either party with thirty days' notice with no further obligation for a monthly retainer. The agreement provides for success fees in the range of 1% to 7% depending on the nature of the transaction. Furthermore, any amounts paid for the retainer would be credited against any investment banking fees due in the event of a successful transaction. | ||
On October 24, 2008, our Board of Directors approved a Performance Based Bonus Program (the "Bonus Program") for our President and Chief Executive Officer. The Bonus Program is calculated and paid annually based on four performance parameters: 1) annual reserve additions from drilling and acquisitions; 2) growth in annual production; 3) growth in annual year over year earnings (before taxes and bonus); and 4) other notable achievements as the Board may recognize from time to time which are not easily quantifiable in the first three parameters. Bonus awards of up to 50% of annual base salary may be achieved in each of the first three categories and up to 10% in the fourth category provided that the maximum bonus award for any year may not exceed 150% of base salary which is currently $280,000. No bonuses were awarded under the Bonus Program in 2013. The Bonus Program is no longer in effect due to the death of our former President, Ray Reaves. We awarded approximately $300,000 to our former President and Chief Executive Officer, Ray Reaves, under the Bonus Program in 2012. |
SUPPLEMENTAL_INFORMATION_ON_OI
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | ' | ||||||||
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | ' | ||||||||
11 | SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | ||||||||
The following table sets forth certain information with respect to the oil and natural gas producing activities of the Company: | |||||||||
Years Ended December 31, | |||||||||
2012 | 2011 | ||||||||
Costs incurred in oil and natural gas producing activities: | |||||||||
Acquisition of unproved properties | $ | - | $ | - | |||||
Acquisition of proved properties | - | - | |||||||
Exploration costs | 152,650 | - | |||||||
Development costs | 3,479,135 | 4,571,324 | |||||||
Total costs incurred | $ | 3,631,785 | $ | 4,571,324 | |||||
The following table summarizes changes in the estimates of the Company's net interest in total proved reserves of crude oil and condensate and natural gas and liquids, all of which are domestic reserves. There can be no assurance that such estimates will not be materially revised in subsequent periods. | |||||||||
Oil | Gas | ||||||||
(Barrels) | (MCF) | ||||||||
Balance, January 1, 2012 | 1,200,264 | 2,269,548 | |||||||
Revisions of previous estimates | 13,854 | 48,955 | |||||||
Extensions and discoveries | 115,093 | 209,930 | |||||||
Sale of reserves | - | - | |||||||
Purchase of minerals in place | - | - | |||||||
Production | (104,285 | ) | (180,098 | ) | |||||
Balance, December 31, 2012 | 1,224,926 | 2,348,335 | |||||||
Revisions of previous estimates | (202,450 | ) | (322,413 | ) | |||||
Extensions and discoveries | 99,988 | 143,343 | |||||||
Sale of reserves | - | - | |||||||
Purchase of minerals in place | - | - | |||||||
Production | (101,752 | ) | (179,737 | ) | |||||
Balance, December 31, 2013 | 1,020,712 | 1,989,528 | |||||||
Proved developed reserves, December 31, 2013 | 916,139 | 1,834,899 | |||||||
Proved developed reserves, December 31, 2012 | 983,900 | 1,898,705 | |||||||
Proved oil and natural gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The above estimated net interests in proved reserves are based upon subjective engineering judgments and may be affected by the limitations inherent in such estimation. The process of estimating reserves is subject to continual revision as additional information becomes available as a result of drilling, testing, reservoir studies and production history, and market prices for oil and natural gas. Significant fluctuations in market prices have a direct impact on recoverability and will result in changes in estimated recoverable reserves without regard to actual increases or decreases in reserves in place. | |||||||||
Year Ended December 31, 2012 | |||||||||
The average natural gas price used in our proved reserves estimate at December 31, 2012 was $2.60 per Mcf. The average oil price used in our proved reserves estimate at December 31, 2012 was $93.42 per barrel. We re-completed additional wells on the Apache Bromide lease during the year end 2012, and we drilled the East Lusk Federal well #2, which were the primary reasons for the quantities listed under extensions and discoveries. | |||||||||
Year Ended December 31, 2013 | |||||||||
The average natural gas price used in our proved reserves estimate at December 31, 2013 was $3.49 per Mcf. The average oil price used in our proved reserves estimate at December 31, 2013 was $90.14 per barrel. We drilled the East Lusk Federal well #3 and re-completed an additional well on the North Block lease during the year ended December 31, 2013, which were the primary reasons for the quantities listed under extensions and discoveries. Our consulting engineers decreased our proved reserves in the East Lusk Field due to a steeper than anticipated decline curve on the East Lusk Federal #2 and #3 wells. |
STANDARDIZED_MEASURE_OF_DISCOU
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) | ' | ||||||||
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) | ' | ||||||||
12 | STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) | ||||||||
The standardized measure of discounted future net cash flows at December 31, 2013 and 2012, relating to proved oil and natural gas reserves is set forth below. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect our expectations of actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. | |||||||||
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with prescribed accounting and SEC standards. Future cash inflows were computed by applying the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 31, 2013 and 2012, to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions. | |||||||||
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. | |||||||||
Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties. | |||||||||
Years Ended December 31, | |||||||||
(in thousands) | |||||||||
2013 | 2012 | ||||||||
Future cash inflows | $ | 101,289 | $ | 117,560 | |||||
Future production costs | (38,667 | ) | (43,641 | ) | |||||
Future development cost | (3,681 | ) | (5,022 | ) | |||||
Future income taxes | (18,115 | ) | (21,200 | ) | |||||
Future net cash flows | 40,826 | 47,697 | |||||||
10% annual discount | (20,455 | ) | (22,597 | ) | |||||
Standardized measure of discounted future net cash flows | $ | 20,371 | $ | 25,100 | |||||
The following are the principal sources of change in the standardized measure of discounted future net cash flows, in thousands: | |||||||||
Years Ended December 31, | |||||||||
2013 | 2012 | ||||||||
Balance, beginning of year | $ | 25,100 | $ | 25,913 | |||||
Sales of oil and natural gas produced, net of production costs | (6,416 | ) | (6,914 | ) | |||||
Sale of reserves | - | - | |||||||
Extensions and discoveries | 3,040 | 3,722 | |||||||
Net changes in prices and production costs | 525 | (2,400 | ) | ||||||
Net changes in future development costs | (1,227 | ) | (2,160 | ) | |||||
Revisions and other changes | (6,556 | ) | 2,861 | ||||||
Accretion of discount | 3,736 | 3,841 | |||||||
Net change in income taxes | 2,169 | 237 | |||||||
Balance, end of year | $ | 20,371 | $ | 25,100 |
SUBSEQUENT_EVENT_UNAUDITED
SUBSEQUENT EVENT (UNAUDITED) | 12 Months Ended | |
Dec. 31, 2013 | ||
SUBSEQUENT EVENT (UNAUDITED) [Abstract] | ' | |
SUBSEQUENT EVENT (UNAUDITED) | ' | |
13 | SUBSEQUENT EVENT (UNAUDITED) | |
Subsequent to December 31, 2013, the Company participated in a successful development well in the Taylor Serbin field, for which the net cost was approximately $1,000,000. We drew $500,000 from our line of credit to finance approximately half of the costs of this well. Production on the well began in late January 2014. | ||
As of February 1, 2014, the Company no longer rents office space from the estate of our former President, Ray Reaves. On January 24, 2014, the Company entered into a two year lease for office space in Austin, Texas, for approximately $3,000 per month. | ||
In January 2014, the Company entered into a consulting agreement with a relative of a Board member for petroleum engineering services related to our oil and natural gas properties. Services rendered under this agreement were $28,000 in January to March, 2014. | ||
On January 1, 2014 FieldPoint Petroleum Corp. ("FieldPoint") signed an exploration agreement ("the agreement") with Riley Exploration, LLC ("Riley"). The agreement provides for an Area of Mutual Interest ("AMI") and a 90 day due diligence period, after which both Companies will cross assign their working interest and vertical wells with a targeted ownership for FieldPoint of 25%. The agreement also provides for a development plan with the intent to drill up to twelve horizontal wells during the initial twelve month period after closing. FieldPoint may elect to be the drilling operator of every fifth well. The agreement also provides for a standard Joint Operating Agreement which allows either partner to participate or decline to participate in every well with no obligatory wells. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT1
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | ' | ||||||||
Organization and Nature of Operations | ' | ||||||||
Organization and Nature of Operations | |||||||||
FieldPoint Petroleum Corporation (the "Company", "we" or "our") is incorporated under the laws of the state of Colorado. We are engaged in the acquisition, operation and development of oil and natural gas properties, which are located in Louisiana, New Mexico, Oklahoma, South Central Texas and Wyoming as of December 31, 2013 and 2012. | |||||||||
Consolidation Policy | ' | ||||||||
Consolidation Policy | |||||||||
Our consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Bass Petroleum, Inc., and Raya Energy Corp. All material intercompany accounts and transactions have been eliminated in consolidation. | |||||||||
Cash and Cash Equivalents | ' | ||||||||
Cash and Cash Equivalents | |||||||||
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At times, we maintain deposit balances in excess of FDIC insurance limits. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on cash and cash equivalents. | |||||||||
Certificates of Deposit | ' | ||||||||
Certificates of Deposit | |||||||||
Certificates of deposit have original maturities ranging from three months to one year and are recorded at fair value on the balance sheet in current assets. Changes in fair value during the period are classified as realized or unrealized holding gains in other income. | |||||||||
Oil and Natural Gas Properties | ' | ||||||||
Oil and Natural Gas Properties | |||||||||
Our oil and natural gas properties consisted of the following at December 31: | |||||||||
2013 | 2012 | ||||||||
Mineral interests in properties: | |||||||||
Unproved properties | $ | 850,000 | $ | 850,000 | |||||
Proved properties | 14,250,230 | 15,098,352 | |||||||
Wells and related equipment and facilities | 20,156,524 | 16,261,900 | |||||||
Total costs | 35,256,754 | 32,210,252 | |||||||
Less accumulated depletion and depreciation | (14,763,266 | ) | (12,378,889 | ) | |||||
$ | 20,493,488 | $ | 19,831,363 | ||||||
We follow the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have found proved reserves. If we determine that the wells have not found proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determinations of whether the wells found proved reserves at December 31, 2013 or 2012. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties are charged to expense as incurred. | |||||||||
We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through December 31, 2013, we have capitalized no interest costs because our exploration and development projects generally last less than six months. Costs to maintain wells and related equipment are charged to expense as incurred. | |||||||||
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and depreciation are eliminated from the property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the amount received is treated as a reduction of the cost of the interest retained. | |||||||||
Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method of proved reserves using the unit conversion ratio of 6 Mcf of gas to 1 bbl of oil. Depletion and depreciation expense for oil and natural gas producing property and related equipment was $2,389,000 and $2,086,000 for the years ended December 31, 2013 and 2012, respectively. | |||||||||
Unproved oil and natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. No impairment of unproved properties was recorded during the years ended December 31, 2013 or 2012. | |||||||||
Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows, which is a non-recurring fair value measurement classified as Level 3 in the fair value hierarchy. We recorded an impairment on our proved oil and natural gas properties of $485,999 and $204,190 during the years ended December 31, 2013 and 2012, respectively. | |||||||||
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. | |||||||||
Oil and Natural Gas Sales Receivable | ' | ||||||||
Oil and Natural Gas Sales Receivable | |||||||||
Oil and natural gas sales receivable principally consist of accrued oil and natural gas sales proceeds receivable and are typically collected within 35 days from the end of the month in which the related quantities are produced. We ordinarily do not require collateral for such receivables, nor do we charge interest on past due balances. We periodically review accounts receivable for collectability and reduce the carrying amount of the accounts receivable by an allowance. No such allowance was indicated at December 31, 2013 or 2012. As of December 31, 2013, our accounts receivable were primarily with several independent purchasers of our crude oil and natural gas production. At December 31, 2013, we had balances due from two customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These two customers accounted for 75% of accounts receivable at December 31, 2013. At December 31, 2012, we had balances due from two customers which were greater than 10% of our accounts receivable related to crude oil and natural gas production. These two customers accounted for 63% of accounts receivable at December 31, 2012. In the event that one or more of these significant customers ceases doing business with us, we believe that there are potential alternative customers with whom we could establish new relationships and that those relationships will result in the replacement of one or more lost customers. | |||||||||
Joint Interest Billings Receivable and Oil and Natural Gas Revenues Payable | ' | ||||||||
Joint Interest Billings Receivable and Oil and Natural Gas Revenues Payable | |||||||||
Joint interest billings receivable represent amounts receivable for lease operating expenses and other costs due from third party working interest owners in the wells that the Company operates. The receivable is recognized when the cost is incurred and the related payable and the Company's share of the cost is recorded. We often have the ability to offset amounts due against the participant's share of production from the related property. | |||||||||
The Company uses the reserve for bad debt method of valuing doubtful joint interest billings receivable based on historical experience, coupled with a review of the current status of existing receivables. The balance of the reserve for doubtful accounts, deducted against joint interest billings receivable to properly reflect the realizable value was approximately $174,000 at December 31, 2013 and 2012. | |||||||||
Oil and natural gas revenues payable represents amounts due to third party revenue interest owners for their share of oil and natural gas revenue collected on their behalf by the Company. The payable is recorded when the Company recognizes oil and natural gas sales and records the related oil and natural gas sales receivable. | |||||||||
Other Property | ' | ||||||||
Other Property | |||||||||
Other assets classified as property and equipment are primarily office furniture and equipment and vehicles, which are carried at cost. Depreciation is provided using the straight-line method over estimated useful lives ranging from three to five years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $6,000 for each of the years ended December 31, 2013 and 2012. | |||||||||
Asset Retirement Obligations | ' | ||||||||
Asset Retirement Obligations | |||||||||
Our financial statements reflect our asset retirement obligations, consisting of future plugging and abandonment expenditures related to our oil and natural gas properties, which can be reasonably estimated. The asset retirement obligation is recorded at fair value on a discounted basis as a liability at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheets. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations. | |||||||||
The following is a reconciliation of the Company's asset retirement obligations for the years ended December 31: | |||||||||
2013 | 2012 | ||||||||
Asset retirement obligation at January 1, | $ | 1,595,935 | $ | 1,515,002 | |||||
Accretion of discount | 96,000 | 91,000 | |||||||
Liabilities incurred during the year | 22,000 | 22,000 | |||||||
Liabilities settled during the year | (1,250 | ) | (32,067 | ) | |||||
Asset retirement obligation at December 31, | $ | 1,712,685 | $ | 1,595,935 | |||||
The entire balance was classified as a non-current liability at December 31, 2013 and 2012. | |||||||||
Income Taxes | ' | ||||||||
Income Taxes | |||||||||
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due, if any, plus net deferred taxes related to differences between the bases of assets and liabilities for financial and income tax reporting. Deferred tax assets and liabilities represent the future tax consequences of those differences, which will either be taxable or deductible when the assets and liabilities are recovered or settled. Valuation allowances are recognized to limit recognition of deferred tax assets where appropriate. Such allowances may be reversed when circumstances provide evidence that the deferred tax assets will more likely than not be realized. | |||||||||
Production Taxes and Ad Valorem Taxes | ' | ||||||||
Production Taxes and Ad Valorem Taxes | |||||||||
Production taxes and ad valorem taxes are included in production expense. Total production and ad valorem taxes were $1,194,443 and $1,297,165 for the years ended December 31, 2013 and 2012, respectively. | |||||||||
Use of Estimates and Certain Significant Estimates | ' | ||||||||
Use of Estimates and Certain Significant Estimates | |||||||||
The preparation of the Company's financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company's management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Actual results could differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which as described above may affect the amount at which oil and natural gas properties are recorded. The Company's allowance for doubtful accounts is a significant estimate and is based on management's estimates of uncollectible receivables. The asset retirement obligations require estimates of future plugging and abandonment expenditures. It is at least reasonably possible these estimates could be revised in the near term and the revisions could be material. | |||||||||
Our estimates of proved reserves materially impact depletion and impairment expense. If proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in estimates of proved reserves may result from lower prices, evaluation of additional operating history, mechanical problems at our wells and catastrophic events such as explosions, hurricanes and floods. Lower prices also may make it uneconomical to drill wells or produce from fields with high operating costs. In addition, a decline in proved reserves may impact our assessment of our oil and natural gas properties for impairment. | |||||||||
Our proved reserve estimates are a function of many assumptions, all of which could deviate materially from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil and natural gas actually produced. | |||||||||
Revenue Recognition | ' | ||||||||
Revenue Recognition | |||||||||
The Company uses the sales method of accounting for oil and natural gas revenues. Under this method, revenues are based on actual volumes of oil and natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Company is entitled based on its interest in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows. There were no material natural gas imbalances as of December 31, 2013 and 2012. | |||||||||
We recognize revenue when crude oil and natural gas quantities are delivered to or collected by the respective purchaser. Title to the produced quantities transfers to the purchaser at the time the purchaser receives or collects the quantities. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for crude oil and natural gas purchases within thirty-five days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that accounts receivable from those purchasers are collectible. | |||||||||
As previously discussed, we sold our crude oil and natural gas production to several independent purchasers. During the year ended December 31, 2013, we had sales of 10% or more of our total oil and natural gas sales revenue to two customers which represented 71% of total oil and natural gas sales revenue for the year ended December 31, 2013. During the year ended December 31, 2012, we had sales of 10% or more of our total oil and natural gas sales revenue to four customers which represented 64% of total oil and natural gas sales revenue for the year ended December 31, 2012. | |||||||||
Comprehensive Income | ' | ||||||||
Comprehensive Income | |||||||||
The Company has no elements of comprehensive income other than net income. | |||||||||
Share-Based Compensation | ' | ||||||||
Share-Based Compensation | |||||||||
We measure and record compensation expense for all share-based payment awards to employees and directors based on estimated fair values. Additionally, compensation costs for share-based awards are recognized over the requisite grant-date service period based on the grant-date fair value. There were no outstanding share-based awards during 2013 or 2012. | |||||||||
Financial Instruments | ' | ||||||||
Financial Instruments | |||||||||
The Company's financial instruments are cash, certificates of deposit, accounts receivable and payable and long-term debt. Management believes the fair values of these instruments, with the exception of the long-term debt, approximate the carrying values, due to the short-term nature of the instruments. Management believes the fair value of long-term debt also reasonably approximates its carrying value, based on expected cash flows and interest rates. |
SUMMARY_OF_SIGNIFICANT_ACCOUNT2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract] | ' | ||||||||
Oil and Natural Gas Properties | ' | ||||||||
Our oil and natural gas properties consisted of the following at December 31: | |||||||||
2013 | 2012 | ||||||||
Mineral interests in properties: | |||||||||
Unproved properties | $ | 850,000 | $ | 850,000 | |||||
Proved properties | 14,250,230 | 15,098,352 | |||||||
Wells and related equipment and facilities | 20,156,524 | 16,261,900 | |||||||
Total costs | 35,256,754 | 32,210,252 | |||||||
Less accumulated depletion and depreciation | (14,763,266 | ) | (12,378,889 | ) | |||||
$ | 20,493,488 | $ | 19,831,363 | ||||||
Asset Retirement Obligations | ' | ||||||||
The following is a reconciliation of the Company's asset retirement obligations for the years ended December 31: | |||||||||
2013 | 2012 | ||||||||
Asset retirement obligation at January 1, | $ | 1,595,935 | $ | 1,515,002 | |||||
Accretion of discount | 96,000 | 91,000 | |||||||
Liabilities incurred during the year | 22,000 | 22,000 | |||||||
Liabilities settled during the year | (1,250 | ) | (32,067 | ) | |||||
Asset retirement obligation at December 31, | $ | 1,712,685 | $ | 1,595,935 |
COMMODITY_DERIVATIVES_Tables
COMMODITY DERIVATIVES (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
COMMODITY DERIVATIVES [Abstract] | ' | ||||||||||||||||
Commodity Derivative Positions to Hedge Oil Production Price risk | ' | ||||||||||||||||
On September 26, 2013, we entered into the following commodity positions to hedge our oil production price risk, through March 31, 2014. The following positions were outstanding at December 31, 2013: | |||||||||||||||||
Period | Volume (Barrels) | $/Barrel | |||||||||||||||
Daily | Total | Floor | Ceiling | ||||||||||||||
NYMEX –WTI Collars Jan – March 2014 | 200 | 18,000 | $ | 87 | $ | 108 | |||||||||||
Derivatives Not Designated as Hedging Instruments | ' | ||||||||||||||||
The following table summarizes the fair value of our open commodity derivatives as of December 31, 2013 and 2012: | |||||||||||||||||
Liability Derivatives | |||||||||||||||||
Fair Value | |||||||||||||||||
Balance Sheet | December 31, | December 31, | |||||||||||||||
Location | 2013 | 2012 | |||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||
Commodity derivatives | Current Liabilities | $ | 4,000 | $ | - | ||||||||||||
Change in Fair Value of Commodity Derivatives | ' | ||||||||||||||||
The following table summarizes the change in fair value of our commodity derivatives: | |||||||||||||||||
12 Months Ended | |||||||||||||||||
Income Statement | December 31, | ||||||||||||||||
Location | 2013 | 2012 | |||||||||||||||
Derivatives not designated as hedging instruments | |||||||||||||||||
Unrealized loss on commodity derivatives | Other Income (Expense) | $ | (4,000 | ) | $ | - | |||||||||||
Realized gain on commodity derivatives | Other Income (Expense) | $ | - | $ | 254,151 |
INCOME_TAXES_Tables
INCOME TAXES (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
INCOME TAXES [Abstract] | ' | ||||||||
Composition of Income Tax Provision | ' | ||||||||
Our provision for income taxes comprised the following (expense) benefit during the years ended December 31: | |||||||||
2013 | 2012 | ||||||||
Current: | |||||||||
Federal | $ | (109,000 | ) | $ | (248,000 | ) | |||
State | (20,070 | ) | (64,000 | ) | |||||
Total current | (129,070 | ) | (312,000 | ) | |||||
Deferred: | |||||||||
Federal | (590,000 | ) | (842,000 | ) | |||||
State | (48,000 | ) | (20,000 | ) | |||||
Total deferred | (638,000 | ) | (862,000 | ) | |||||
Total income tax provision | $ | (767,070 | ) | $ | (1,174,000 | ) | |||
Reconciliation of Tax Rate | ' | ||||||||
Total income tax (expense) benefit differed from the amounts computed by applying the U.S. Federal statutory tax rates and estimated state rates to pre-tax income for the years ended December 31, 2013 and 2012 as follows: | |||||||||
2013 | 2012 | ||||||||
Statutory rate | 34 | % | 34 | % | |||||
State taxes, net of federal benefit | 3 | % | 2 | % | |||||
Effective rate | 37 | % | 36 | % | |||||
Components of Deferred Tax Assets and Liability | ' | ||||||||
Significant components of net deferred tax assets and liabilities are: | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Deferred tax assets: | |||||||||
Asset retirement obligation | $ | 393,000 | $ | 357,000 | |||||
Allowance for doubtful accounts | 63,000 | 63,000 | |||||||
Accrued compensation and other | - | 109,000 | |||||||
Unrealized loss on commodity derivatives | 1,000 | - | |||||||
Alternative minimum tax credit carryforward | 80,000 | - | |||||||
Total deferred tax assets | 537,000 | 529,000 | |||||||
Deferred tax liability: | |||||||||
Difference in depreciation, depletion and capitalization methods – oil and gas properties | (3,446,000 | ) | (2,800,000 | ) | |||||
Total deferred tax liabilities | (3,446,000 | ) | (2,800,000 | ) | |||||
Net deferred tax liability | $ | (2,909,000 | ) | $ | (2,271,000 | ) | |||
Net Deferred Tax Assets and Liabilities, Balance Sheet Location | ' | ||||||||
Our net deferred tax assets and liabilities are recorded as follows: | |||||||||
2013 | 2012 | ||||||||
Current asset | $ | 64,000 | $ | 171,000 | |||||
Non-current liability | (2,973,000 | ) | (2,442,000 | ) | |||||
Total | $ | (2,909,000 | ) | $ | (2,271,000 | ) |
EARNINGS_PER_SHARE_Tables
EARNINGS PER SHARE (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
EARNINGS PER SHARE [Abstract] | ' | ||||||||
Schedule of Earnings Per Share, Basic and Diluted | ' | ||||||||
Basic earnings per share are computed based on the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share take common stock equivalents (such as options and warrants) into consideration using the treasury stock method. The Company distributed warrants as a dividend to stockholders as of the record date, March 23, 2012. The dilutive effect of the warrants for the twelve months ended December 31, 2013 and 2012 is presented below. | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Net income | $ | 1,278,997 | $ | 2,112,263 | |||||
Weighted average common stock outstanding | 8,062,167 | 8,006,959 | |||||||
Weighted average dilutive effect of stock warrants | 323,086 | 445,470 | |||||||
Dilutive weighted average shares | 8,385,253 | 8,452,429 | |||||||
Earnings per share: | |||||||||
Basic | $ | 0.16 | $ | 0.26 | |||||
Diluted | $ | 0.15 | $ | 0.25 |
STOCKHOLDERS_EQUITY_Tables
STOCKHOLDERS' EQUITY (Tables) | 12 Months Ended | ||||
Dec. 31, 2013 | |||||
STOCKHOLDERS' EQUITY [Abstract] | ' | ||||
Warrants Outstanding | ' | ||||
The following table summarizes the warrants outstanding at December 31, 2012 and December 31, 2013: | |||||
Warrants outstanding, December 31, 2012 | 7,983,175 | ||||
Warrants exercised | (22,400 | ) | |||
Warrants outstanding, December 31, 2013 | 7,960,775 |
SUPPLEMENTAL_INFORMATION_ON_OI1
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | ' | ||||||||
Oil and Natural Gas Producing Activities | ' | ||||||||
The following table sets forth certain information with respect to the oil and natural gas producing activities of the Company: | |||||||||
Years Ended December 31, | |||||||||
2012 | 2011 | ||||||||
Costs incurred in oil and natural gas producing activities: | |||||||||
Acquisition of unproved properties | $ | - | $ | - | |||||
Acquisition of proved properties | - | - | |||||||
Exploration costs | 152,650 | - | |||||||
Development costs | 3,479,135 | 4,571,324 | |||||||
Total costs incurred | $ | 3,631,785 | $ | 4,571,324 | |||||
Change in Estimates of Net Interest in Total Proved Reserves of Crude Oil and Condensate and Natural Gas and Liquids | ' | ||||||||
The following table summarizes changes in the estimates of the Company's net interest in total proved reserves of crude oil and condensate and natural gas and liquids, all of which are domestic reserves. There can be no assurance that such estimates will not be materially revised in subsequent periods. | |||||||||
Oil | Gas | ||||||||
(Barrels) | (MCF) | ||||||||
Balance, January 1, 2012 | 1,200,264 | 2,269,548 | |||||||
Revisions of previous estimates | 13,854 | 48,955 | |||||||
Extensions and discoveries | 115,093 | 209,930 | |||||||
Sale of reserves | - | - | |||||||
Purchase of minerals in place | - | - | |||||||
Production | (104,285 | ) | (180,098 | ) | |||||
Balance, December 31, 2012 | 1,224,926 | 2,348,335 | |||||||
Revisions of previous estimates | (202,450 | ) | (322,413 | ) | |||||
Extensions and discoveries | 99,988 | 143,343 | |||||||
Sale of reserves | - | - | |||||||
Purchase of minerals in place | - | - | |||||||
Production | (101,752 | ) | (179,737 | ) | |||||
Balance, December 31, 2013 | 1,020,712 | 1,989,528 | |||||||
Proved developed reserves, December 31, 2013 | 916,139 | 1,834,899 | |||||||
Proved developed reserves, December 31, 2012 | 983,900 | 1,898,705 |
STANDARDIZED_MEASURE_OF_DISCOU1
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2013 | |||||||||
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) | ' | ||||||||
Estimated Cash Flows from Future Production of Proved Reserves | ' | ||||||||
Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties. | |||||||||
Years Ended December 31, | |||||||||
(in thousands) | |||||||||
2013 | 2012 | ||||||||
Future cash inflows | $ | 101,289 | $ | 117,560 | |||||
Future production costs | (38,667 | ) | (43,641 | ) | |||||
Future development cost | (3,681 | ) | (5,022 | ) | |||||
Future income taxes | (18,115 | ) | (21,200 | ) | |||||
Future net cash flows | 40,826 | 47,697 | |||||||
10% annual discount | (20,455 | ) | (22,597 | ) | |||||
Standardized measure of discounted future net cash flows | $ | 20,371 | $ | 25,100 | |||||
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows | ' | ||||||||
The following are the principal sources of change in the standardized measure of discounted future net cash flows, in thousands: | |||||||||
Years Ended December 31, | |||||||||
2013 | 2012 | ||||||||
Balance, beginning of year | $ | 25,100 | $ | 25,913 | |||||
Sales of oil and natural gas produced, net of production costs | (6,416 | ) | (6,914 | ) | |||||
Sale of reserves | - | - | |||||||
Extensions and discoveries | 3,040 | 3,722 | |||||||
Net changes in prices and production costs | 525 | (2,400 | ) | ||||||
Net changes in future development costs | (1,227 | ) | (2,160 | ) | |||||
Revisions and other changes | (6,556 | ) | 2,861 | ||||||
Accretion of discount | 3,736 | 3,841 | |||||||
Net change in income taxes | 2,169 | 237 | |||||||
Balance, end of year | $ | 20,371 | $ | 25,100 |
SUMMARY_OF_SIGNIFICANT_ACCOUNT3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Oil and Natural Gas Properties [Abstract] | ' | ' |
Unproved properties | $850,000 | $850,000 |
Proved properties | 14,250,230 | 15,098,352 |
Wells and related equipment and facilities | 20,156,524 | 16,261,900 |
Total costs | 35,256,754 | 32,210,252 |
Less accumulated depletion and depreciation | -14,763,266 | -12,378,889 |
Oil and Gas Producing Activities, Net, Total | 20,493,488 | 19,831,363 |
Term threshold for cost capitalization | '6 months | ' |
Unit-of-production method, conversion ratio | '6 Mcf of gas to 1 bbl of oil | ' |
Depletion and depreciation expense for oil and natural gas producing property and related equipment | 2,389,000 | 2,086,000 |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' |
Impairment of Oil and Gas Properties | 0 | 0 |
Collection period of oil and gas receivable | '35 days | ' |
Concentration Risk [Line Items] | ' | ' |
Reserve for doubtful accounts | 174,000 | 174,000 |
Depreciation expense for other property and equipment | 6,000 | 6,000 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ' | ' |
Asset Retirement Obligation, Beginning Balance | 1,595,935 | 1,515,002 |
Accretion of discount | 96,000 | 91,000 |
Liabilities incurred during the year | 22,000 | 22,000 |
Liabilities settled during the year | -1,250 | -32,067 |
Asset Retirement Obligation, Ending Balance | 1,712,685 | 1,595,935 |
Production Taxes and Ad Valorem Taxes | 1,194,443 | 1,297,165 |
Material natural gas imbalances | 0 | 0 |
Share-based awards | 0 | 0 |
Maximum [Member] | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Useful lives | '3 years | ' |
Minimum [Member] | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Useful lives | '5 years | ' |
Oil and Natural Gas Sales Receivable [Member] | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Number of major customer | 2 | 2 |
Oil and Natural Gas Sales Receivable [Member] | Credit Concentration Risk [Member] | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Concentration risk (in hundredths) | 75.00% | 63.00% |
Sales [Member] | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Number of major customer | 2 | 4 |
Sales [Member] | Customer Concentration Risk [Member] | ' | ' |
Concentration Risk [Line Items] | ' | ' |
Concentration risk (in hundredths) | 71.00% | 64.00% |
Loving Property [Member] | ' | ' |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | ' | ' |
Impairment of Oil and Gas Properties | $485,999 | $204,190 |
OIL_AND_NATURAL_GAS_PROPERTIES1
OIL AND NATURAL GAS PROPERTIES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
OIL AND NATURAL GAS PROPERTIES [Abstract] | ' | ' |
Drilling cost | $3,000,000 | $3,000,000 |
Proceeds from the sale of oil and natural gas properties | 5,000 | 204,000 |
Gain recognized on sale of property | 4,000 | 204,000 |
Dry hole expenses | $152,650 | $0 |
RELATED_PARTY_TRANSACTIONS_Det
RELATED PARTY TRANSACTIONS (Details) (President [Member], USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
President [Member] | ' | ' |
Related Party Transaction [Line Items] | ' | ' |
Leases rent expense paid to president | $30,000 | $30,000 |
COMMODITY_DERIVATIVES_Details
COMMODITY DERIVATIVES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Fair value of open commodity derivatives [Abstract] | ' | ' |
Derivative Liability, Fair Value, Net, Total | $4,000 | $0 |
Realized gain on derivatives | 0 | 254,151 |
Nondesignated [Member] | Current Liabilities [Member] | ' | ' |
Fair value of open commodity derivatives [Abstract] | ' | ' |
Derivative Liability, Fair Value, Net, Total | 4,000 | 0 |
NYMEX -WTI Collars Jan - March 2014 [Member] | ' | ' |
Commodity derivative positions to hedge our oil production price risk | ' | ' |
Daily Volume (in Barrels) | 200 | ' |
Total Volume (in Barrels) | 18,000 | ' |
Floor (in dollars per Barrel) | 87 | ' |
Ceiling (in dollars per Barrel) | 108 | ' |
Commodity Contract [Member] | Nondesignated [Member] | Other Income (Expense) [Member] | ' | ' |
Fair value of open commodity derivatives [Abstract] | ' | ' |
Unrealized gain (loss) on commodity derivatives | -4,000 | 0 |
Realized gain on derivatives | $0 | $254,151 |
LINE_OF_CREDIT_Details
LINE OF CREDIT (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Line of Credit Facility [Line Items] | ' | ' |
Borrowing base | $11,000,000 | $11,000,000 |
Outstanding under line of credit | $6,740,000 | $6,740,000 |
Maturity date | 18-Oct-16 | ' |
Description of variable rate basis | '3-month LIBOR rate plus | ' |
Current interest rate (in hundredths) | 3.50% | 3.50% |
Commitment fee (in hundredths) | 0.50% | ' |
Prime Rate [Member] | Minimum [Member] | ' | ' |
Line of Credit Facility [Line Items] | ' | ' |
Basis spread on variable rate (in hundredths) | 1.75% | ' |
Prime Rate [Member] | Maximum [Member] | ' | ' |
Line of Credit Facility [Line Items] | ' | ' |
Basis spread on variable rate (in hundredths) | 2.25% | ' |
LIBOR Rate [Member] | Minimum [Member] | ' | ' |
Line of Credit Facility [Line Items] | ' | ' |
Basis spread on variable rate (in hundredths) | 2.75% | ' |
LIBOR Rate [Member] | Maximum [Member] | ' | ' |
Line of Credit Facility [Line Items] | ' | ' |
Basis spread on variable rate (in hundredths) | 3.25% | ' |
INCOME_TAXES_Details
INCOME TAXES (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Current [Abstract] | ' | ' |
Federal | ($109,000) | ($248,000) |
State | -20,070 | -64,000 |
Total current | -129,070 | -312,000 |
Deferred [Abstract] | ' | ' |
Federal | -590,000 | -842,000 |
State | -48,000 | -20,000 |
Total deferred | -638,000 | -862,000 |
Total income tax provision | -767,070 | -1,174,000 |
Effective Income Tax Rate Reconciliation [Abstract] | ' | ' |
Statutory rate (in hundredths) | 34.00% | 34.00% |
State taxes, net of federal benefit (in hundredths) | 3.00% | 2.00% |
Effective rate (in hundredths) | 37.00% | 36.00% |
Deferred tax assets [Abstract] | ' | ' |
Asset retirement obligation | 393,000 | 357,000 |
Allowance for doubtful accounts | 63,000 | 63,000 |
Accrued compensation and other | 0 | 109,000 |
Unrealized loss on commodity derivatives | 1,000 | 0 |
Alternative minimum tax credit carryforward | 80,000 | 0 |
Total deferred tax assets | 537,000 | 529,000 |
Deferred tax liability [Abstract] | ' | ' |
Difference in depreciation, depletion and capitalization methods - oil and gas properties | -3,446,000 | -2,800,000 |
Total deferred tax liabilities | -3,446,000 | -2,800,000 |
Net deferred tax liability | -2,909,000 | -2,271,000 |
Balance Sheet Location [Abstract] | ' | ' |
Current asset | 64,000 | 171,000 |
Non-current liability | -2,973,000 | -2,442,000 |
Total | -2,909,000 | -2,271,000 |
Unrecognized tax benefit due to uncertain tax positions | 0 | 0 |
Income tax interest and penalty expense | 0 | 0 |
Accrued income tax interest and penalty | $0 | $0 |
EARNINGS_PER_SHARE_Details
EARNINGS PER SHARE (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Schedule of earnings per share, basic and diluted [Abstract] | ' | ' |
Net income | $1,278,997 | $2,112,263 |
Weighted average common stock outstanding (in shares) | 8,062,167 | 8,006,959 |
Weighted average dilutive effect of stock warrants (in shares) | 323,086 | 445,470 |
Dilutive weighted average shares (in shares) | 8,385,253 | 8,452,429 |
Earnings per share [Abstract] | ' | ' |
Basic (in dollars per share) | $0.16 | $0.26 |
Diluted (in dollars per share) | $0.15 | $0.25 |
STOCKHOLDERS_EQUITY_Details
STOCKHOLDERS' EQUITY (Details) (USD $) | 12 Months Ended | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | 16-May-12 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | |
MLV & Co., LLC [Member] | MLV & Co., LLC [Member] | MLV & Co., LLC [Member] | Stock Warrant [Member] | Stock Warrant [Member] | Stock Warrant [Member] | |||
Class of Warrant or Right [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Stock warrant dividend rate | ' | ' | ' | ' | ' | 'one warrant per one common share | ' | ' |
Warrant dividend record date | ' | ' | ' | ' | ' | ' | ' | 23-Mar-12 |
Warrants issued (in shares) | ' | ' | ' | ' | ' | ' | ' | 7,983,175 |
Warrants exercise price (in dollars per share) | ' | ' | ' | ' | ' | ' | ' | $4 |
Warrants exercise period | ' | ' | ' | ' | ' | ' | ' | '6 years |
Warrants recall rate (in hundredths) | ' | ' | ' | ' | ' | ' | ' | 150.00% |
Warrants recall rate maximum (in dollars per share) | ' | ' | ' | ' | ' | ' | ' | $6 |
Warrants fair value | ' | ' | ' | ' | ' | ' | ' | $8,000,000 |
Fair value of warrants reclassified from retained earnings to additional paid in capital | ' | ' | ' | ' | ' | ' | ' | 6,895,361 |
Common stock issued, redemption of warrants | ' | ' | ' | ' | ' | ' | 89,600 | ' |
Warrants Outstanding [Rollforward] | ' | ' | ' | ' | ' | ' | ' | ' |
Warrants outstanding, beginning balance (in shares) | 7,983,175 | ' | ' | ' | ' | ' | ' | ' |
Warrants exercised (in shares) | -22,400 | ' | ' | ' | ' | ' | ' | ' |
Warrants outstanding, ending balance (in shares) | 7,960,775 | 7,983,175 | ' | ' | ' | ' | ' | ' |
Subsidiary or Equity Method Investee [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum number of shares to be issued under Market Issuance Sales Agreement (in shares) | ' | ' | ' | ' | 900,000 | ' | ' | ' |
Percentage of gross sales price paid as sales commission (in hundredths) | ' | ' | ' | 7.00% | ' | ' | ' | ' |
Number of common shares sold pursuant to agreement (in shares) | ' | ' | 0 | 60,761 | ' | ' | ' | ' |
Gross proceeds from issue of share | 0 | 193,589 | ' | 257,358 | ' | ' | ' | ' |
Expenses associated with the sale of shares | ' | ' | ' | $63,769 | ' | ' | ' | ' |
COMMITMENTS_Details
COMMITMENTS (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Parameter | ||
Loss Contingencies [Line Items] | ' | ' |
Standby letter of credit, outstanding amount | $6,740,000 | $6,740,000 |
Monthly retainer fee for general financial and Investment Banking advice | 10,000 | ' |
Term of the executive agreement | '3 years | ' |
Number of performance parameter | 4 | ' |
Bonus as percentage of annual base salary three parameter (in hundredths) | 50.00% | ' |
Maximum bonus per fourth category (in hundredths) | 10.00% | ' |
Maximum bonus as percentage of annual base salary (in hundredths) | 150.00% | ' |
Base salary of President and Chief Executive Officer | 280,000 | ' |
Bonus paid to officer | 0 | 300,000 |
Maximum [Member] | ' | ' |
Loss Contingencies [Line Items] | ' | ' |
Success fee rates (in hundredths) | 7.00% | ' |
Minimum [Member] | ' | ' |
Loss Contingencies [Line Items] | ' | ' |
Success fee rates (in hundredths) | 1.00% | ' |
Financial Standby Letter of Credit [Member] | ' | ' |
Loss Contingencies [Line Items] | ' | ' |
Standby letter of credit, outstanding amount | $30,000 | $30,000 |
SUPPLEMENTAL_INFORMATION_ON_OI2
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2013 | Dec. 31, 2012 | |
Costs incurred in oil and natural gas producing activities [Abstract] | ' | ' |
Acquisition of unproved properties | $0 | $0 |
Acquisition of proved properties | 0 | 0 |
Exploration costs | 152,650 | 0 |
Development costs | 3,479,135 | 4,571,324 |
Total costs incurred | $3,631,785 | $4,571,324 |
Oil [Member] | ' | ' |
Proved Developed and Undeveloped Reserves [Abstract] | ' | ' |
Beginning Balance | 1,224,926 | 1,200,264 |
Revisions of previous estimates | -202,450 | 13,854 |
Extensions and discoveries | 99,988 | 115,093 |
Sale of reserves | 0 | 0 |
Purchase of minerals in place | 0 | 0 |
Production | -101,752 | -104,285 |
Ending Balance | 1,020,712 | 1,224,926 |
Proved Developed Reserves (Volume) | 916,139 | 983,900 |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' |
Average Sales Prices (in dollars per unit) | $90.14 | $93.42 |
Natural Gas [Member] | ' | ' |
Proved Developed and Undeveloped Reserves [Abstract] | ' | ' |
Beginning Balance | 2,348,335 | 2,269,548 |
Revisions of previous estimates | -322,413 | 48,955 |
Extensions and discoveries | 143,343 | 209,930 |
Sale of reserves | 0 | 0 |
Purchase of minerals in place | 0 | 0 |
Production | -179,737 | -180,098 |
Ending Balance | 1,989,528 | 2,348,335 |
Proved Developed Reserves (Volume) | 1,834,899 | 1,898,705 |
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ' | ' |
Average Sales Prices (in dollars per unit) | $3.49 | $2.60 |
STANDARDIZED_MEASURE_OF_DISCOU2
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) | ' | ' |
Discount rate used for standardized measure (in hundredths) | 10.00% | ' |
Estimated cash flows from future production of proved reserves [Abstract] | ' | ' |
Future cash inflows | $101,289 | $117,560 |
Future production costs | -38,667 | -43,641 |
Future development cost | -3,681 | -5,022 |
Future income taxes | -18,115 | -21,200 |
Future net cash flows | 40,826 | 47,697 |
10% annual discount | -20,455 | -22,597 |
Standardized measure of discounted future net cash flows | 20,371 | 25,100 |
Principal sources of change in the standardized measure of discounted future net cash flows [Roll Forward] | ' | ' |
Balance, beginning of year | 25,100 | 25,913 |
Sales of oil and natural gas produced, net of production costs | -6,416 | -6,914 |
Sale of reserves | 0 | 0 |
Extensions and discoveries | 3,040 | 3,722 |
Net changes in prices and production costs | 525 | -2,400 |
Net changes in future development costs | -1,227 | -2,160 |
Revisions and other changes | -6,556 | 2,861 |
Accretion of discount | 3,736 | 3,841 |
Net change in income taxes | 2,169 | 237 |
Balance, end of year | $20,371 | $25,100 |
SUBSEQUENT_EVENT_UNAUDITED_Det
SUBSEQUENT EVENT (UNAUDITED) (Details) (Subsequent Event [Member], USD $) | 0 Months Ended | |
Mar. 21, 2014 | Feb. 01, 2014 | |
Subsequent Event [Member] | ' | ' |
Subsequent Event [Line Items] | ' | ' |
Net cost of well development | $1,000,000 | ' |
Draw from line of credit to finance half the cost of well | 500,000 | ' |
Lease period for office space | ' | '2 years |
Monthly rent expense | ' | 3,000 |
Consultation service fees | $28,000 | ' |
Due diligence period (in days) | '90 days | ' |
Targeted ownership (in hundredths) | 25.00% | ' |