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U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period Ended June 30, 2014

o Transition  Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Transition Period from __________ to _________

Commission file number: 001-32624

(Exact name of small business issuer as specified in its charter)

 

609 Castle Ridge Road, Suite 335

 

(512) 579-3560

(Issuer's Telephone Number, Including Area Code)

 

(512) 579-3560

(former name, address and fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x

As of August 8, 2014, the number of shares outstanding of the Registrant's $.01 par value common stock was 8,115,378.

 

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PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

FieldPoint Petroleum Corporation

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to these unaudited condensed consolidated financial statements.

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FieldPoint Petroleum Corporation

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

FieldPoint Petroleum Corporation

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

FieldPoint Petroleum Corporation

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.	Nature of Business, Organization and Basis of Preparation and Presentation

FieldPoint Petroleum Corporation (the “Company”, “FieldPoint”, “our”, or “we”) is incorporated under the laws of the state of Colorado.  The Company is engaged in the acquisition, operation and development of oil and natural gas properties, which are located in Louisiana, New Mexico, Oklahoma, Texas, and Wyoming.

The condensed consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted.  However, in the opinion of management, all adjustments (which consist only of normal recurring adjustments) necessary to present fairly the financial position and results of operations for the periods presented have been made.  These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the Company's Form 10-K filing for the year ended December 31, 2013.

Recently Issued Accounting Pronouncements – In April 2014, FASB issued the Accounting Standards Update No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This standard revises the definition of a discontinued operation to limit the circumstances under which a disposal or classification as held for sale qualifies for presentation as a discontinued operation. Amendments in this standard require expanded disclosures concerning a discontinued operation and the disposal of an individually-material component of an entity not qualifying as a discontinued operation. The standard is effective for annual and interim periods beginning on or after December 15, 2014 and should be applied prospectively, with early adoption permitted. We currently do not expect this standard to have any impact on our consolidated financial statements.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 on revenue from contracts with customers. Under this new standard, revenue is recognized at the time a good or service is transferred to a customer for the amount of consideration received for that specific good or service. The standard is effective for interim and annual periods beginning after December 16, 2016, and early adoption is not permitted. Adoption is allowed by either the full retrospective or modified retrospective approach. We are currently evaluating which approach we will apply and the impact, if any, that this standard will have on our consolidated financial statements.

2.	Oil and Natural Gas Properties

In January 2014, the Company drilled and completed a successful development well in Lee County, Texas. The net cost to the Company was approximately $1,000,000.

In May 2014, the Company completed the Ranger 11A-1H in Bastrop County, Texas.  The Company has a 25% working interest and 18.75% net revenue interest in the well.  The net cost to drill and complete the well was approximately $875,000.  The well was successfully completed and is in production.

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On June 1, 2014, the Company executed and closed on the first transaction with Riley Exploration Group, LLC ("Riley").  Pursuant to the terms of the exploration agreement FieldPoint assigned 6 net Taylor sand wells in the Serbin Field to Riley in return for 7 net wells in the same field.  In addition, FieldPoint assigned to Riley 240 net acres in exchange for 239 net acres. This was a non-cash contribution of interests with substantially the same fair value. Operations in the field transferred from FieldPoint to Riley for these leases.  FieldPoint and Riley plan to jointly re-develop these leases by plugging the legacy wells and drilling new horizontal wells.

3.	Earnings Per Share

Basic earnings per share are computed based on the weighted average number of shares of common stock outstanding during the period.  Diluted earnings per share take common stock equivalents (such as options and warrants) into consideration using the treasury stock method.  The Company had 7,955,210 and 7,960,775 warrants outstanding with an exercise price of $4.00 at June 30, 2014, and 2013, respectively.  The dilutive effect of the warrants for the three and six months ended June 30, 2014 and 2013 is presented below.

4.	Related Party Transactions

The Company leased office space from the estate of its former president through January 2014 for $2,500 a month. Rent expense for this month-to-month lease was $15,000 for the six month period ended June 30, 2013 and $7,500 for the three month period ended June 30, 2013. Beginning February 1, 2014, the Company no longer rents office space from the estate.

During the six month period ended June 30, 2014, the Company paid a relative of a Board member $28,000 for petroleum engineering services. There were no comparable payments during the three month period ended June 30, 2014, or during the three and six month periods ended June 30, 2013.

5.	Long-Term Debt

The Company has a line of credit with a bank with a borrowing base of $11,000,000 at June 30, 2014, and December 31, 2013.  The credit line was amended on March 19, 2014 on substantially identical terms, except that the requirement for a personal guarantee by the former President and CEO was removed, and the maturity date was extended to October 18, 2016. The amount outstanding under this line of credit was $7,240,000 and $6,740,000 as of June 30, 2014 and December 31, 2013, respectively. The agreement requires monthly interest-only payments until maturity on October 18, 2016. The line of credit provides for certain financial covenants and ratios which include a current ratio, leverage ratio, and interest coverage ratio requirements.  The Company was in compliance with debt covenants as of June 30, 2014.

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6.	Stockholders’ Equity

The Company issued a stock warrant dividend of one warrant per one common share outstanding as of 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 following table summarizes the warrant activity for the six months ending June 30, 2014:

7.	Commodity Derivatives

On March 27, 2014, we entered into the following commodity positions to hedge our oil production price risk, effective from April 1, 2014, to September 30, 2014. These positions were outstanding at June 30, 2014:

The following table summarizes the fair value of our open commodity derivatives as of June 30, 2014 and December 31, 2013:

 

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The following table summarizes the change in fair value of our commodity derivatives:

 

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:

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Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At June 30, 2014, we had no Level 1 measurements.

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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 June 30, 2014, all of our commodity derivatives were valued using Level 2 measurements.

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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 June 30, 2014, we had no Level 3 measurements.

8.	Commitments

In January 2014, the Company entered into a two year lease for office space in Austin, Texas. Lease payments are approximately $3,000 per month through January, 2016.

The Company entered into an “at will” employment agreement with Phillip Roberson as President and CFO for a three year period beginning July 1, 2014, with a beginning base salary of $200,000 annually. As a signing bonus, Mr. Roberson will be entitled to receive 50,000 shares of common stock, of which 10,000 shares will be immediately received and vested. An additional 10,000 shares will be received and vested at the six month, twelve month, eighteen month, and twenty four month anniversary dates of the commencement date. Once the signing bonus grant has been fully vested and paid, Mr. Roberson will be entitled to receive, as part of his annual compensation, on his third anniversary date 5,000 shares, on his fourth anniversary date 6,000 shares, on his fifth anniversary date 7,000 shares, on his sixth anniversary date 8,000 shares, on his seventh anniversary date 9,000 shares, and each annual anniversary date thereafter 10,000 shares. Beginning January 1, 2015, the Board of Directors may in its sole discretion award an annual Performance Based Bonus Award to Mr. Roberson.

9.	Subsequent Events

Subsequent to June 30, 2014, the Company received approximately $168,000 in proceeds from the exercise of 42,077 warrants at $4.00 per share. An additional 1,400 warrants were exercised subsequent to June 30, 2014, at $4.00 per share; however, the proceeds have not yet been received.

In July 2014, the Company completed the Ranger 8A-2H and the Ranger 8A3-3H in Lee County, Texas. The Company has a 25% working interest and 18.75% net revenue interest in the wells.  The net cost to drill and complete the wells was approximately $850,000 per well.

On July 1, 2014, the Company executed a second closing with Riley Exploration Group, LLC.  Pursuant to the terms of the exploration agreement FieldPoint assigned 23 net Taylor sand wells in the Serbin Field to Riley in return for 20 net wells in the same field.  In addition, FieldPoint assigned Riley 759 net acres in exchange for 760 net acres.

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PART I

The following discussion should be read in conjunction with the Company’s Condensed Consolidated Financial Statements, and respective notes thereto, included elsewhere herein.  The information below should not be construed to imply that the results discussed herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future.  Such discussion represents only the best present assessment of the management of FieldPoint Petroleum Corporation.

General

FieldPoint Petroleum Corporation derives its revenues from its operating activities including sales of oil and natural gas and operating oil and natural gas properties.  The Company's capital for investment in producing oil and natural gas properties has been provided by cash flow from operating activities and from bank financing. The Company categorizes its operating expenses into the categories of production expenses and other expenses.

The Company completed drilling the Ranger 8A-1H well in the Taylor Serbin field in Texas. Production began February 1, 2014. The Company completed drilling the Ranger 11A-1H well in the Taylor Serbin field in Texas. Production began May 20, 2014.

In May 2014, the Company completed the Ranger 11A-1H in Bastrop County, Texas.  The Company has a 25% working interest and 18.75% net revenue interest in the well.  The net cost to drill and complete the well was approximately $875,000.  The well was successfully completed horizontally in the Taylor sand and is in production. In addition, the Company plans to drill the fourth well in the East Lusk field in New Mexico during the second quarter of 2015.

Results of Operations

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Oil and natural gas sales revenues increased 9% or $201,209 to $2,367,540 for the three-month period ended June 30, 2014 from the comparable 2013 period.  Average oil sales prices increased 9% to $92.74 for the three-month period ended June 30, 2014 compared to $88.38 for the period ended June 30, 2013.  Average natural gas sales prices decreased to $4.25 for the three-month period ended June 30, 2014 compared to $4.56 for the period ended June 30, 2013.  Increased oil and natural gas production accounted for an increase in revenue of approximately $112,000. Higher commodity prices for oil and natural gas account for an increase in revenue of approximately $89,000.  We anticipate volumes to increase in the coming quarters primarily due to an in-fill developmental well on our Quinoco Sulimar lease in Chavez County, New Mexico and at least two behind pipe recompletions in Andrews County, Texas in the second half of 2014.  Furthermore we anticipate additional drilling in the Serbin Field in 2014 and a fourth Bone Springs well in New Mexico in the second quarter of 2015.

Lease operating expenses increased 45% or $305,570 to $985,810 for the three month period ended June 30, 2014 from the comparable 2013 period.  This was primarily due to increases in costs associated with new field production in 2014, remediation and workover expenses mainly in our operated properties including Taylor Serbin, the Block A49 & Block 6 and Big Muddy fields and workover expenses in the Apache Bromide field initiated by the operator. Lifting costs per BOE increased $8.39 to $32.07 for the 2014 period compared to $23.68 for the three months ended June 30, 2013. We anticipate lease operating expenses to increase over the following quarters due to additional remedial repairs and workover expenses in the Taylor Serbin and Apache Bromide fields, as well as additional costs related to production from new wells in Texas and New Mexico.

Depletion and depreciation increased 27% or $133,000 to $623,500 for the three month period ended June 30, 2014 versus $490,500 in the 2013 comparable period.  This was primarily due to the addition of the new East Lusk #3 and the Ranger 8A and Ranger 11A wells since the prior period.

General and administrative overhead cost increased 28% or $77,923 to $355,982 for the three-month period ended June 30, 2014 from the three-month period ended June 30, 2013.  This was primarily attributable to increases in professional services and directors’ fees during the 2014 period.  At this time, the Company anticipates general and administrative expenses to remain stable or increase slightly in the coming quarters.

Other expenses, net for the quarter ended June 30, 2014, were $48,010 compared to other expense, net of $61,143 for quarter ended June 30, 2013.  During the three months ended June 30, 2014, the net decrease was primarily due to a $9,000 increase in other income and $6,200 increase in unrealized gain on commodity derivatives.

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Results of Operations

Oil and natural gas sales revenues increased 15% or $704,342 to $5,271,755 for the six month period ended June 30, 2014 from $4,567,413 for the comparable 2013 period. An overall increase in oil and natural gas production accounted for an increase in revenue of aproximately $429,000 while an increase in oil and natural gas commodity prices increased revenue by approximately $275,000. Sales volumes increased 10% on a BOE basis primarily due to production from new wells completed since the prior period. Average oil sales prices increased $3.84 to $92.89 for the six month period ended June 30, 2014 compared to $89.05 for the six month period ended June 30, 2013.  Average natural gas sales prices increased 13% to $5.50 for the six month period ended June 30, 2014 compared to $4.62 for the six month period ended June 30, 2013.  We anticipate volumes to increase in the coming quarters primarily due to an in-fill developmental well on our Quinoco Sulimar lease in Chavez County, New Mexico and at least two behind pipe recompletions in Andrews County, Texas in the second half of 2014.  Furthermore we anticipate additional drilling in the Serbin Field in 2014 and a fourth Bone Springs well in New Mexico in the second quarter of 2015.

Lease operating expenses increased 22% or $494,309 to $1,965,278 for the six month period ended June 30, 2014 from the comparable 2013 period.  This was primarily due to the costs associated with operating expenses on the new well completed in New Mexico during the third quarter of 2013 and two new wells completed in Texas in 2014, as well as increased workover expenses in the Taylor Serbin and Apache Bromide fields.  Lifting cost per BOE increased 11%, from $24.43 to $29.70 for the 2014 period.  We anticipate lease operating expense to increase over the following quarters due to additional remedial repairs and workover expenses and operating expenses related to the new wells completed in New Mexico and Texas.

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Depletion and depreciation expense increased 43% to $1,449,000, compared to $1,014,000 for the comparable 2013 period.  This was primarily due to the addition of the new East Lusk #3 and the Ranger 8A and 11A wells since the previous period.

Exploration expense was $2.73 on a BOE basis for the six month period ended June 30, 2013. The adjusted cost incurred to drill on the Riverdale lease in Texas was $164,204. The well was non-economic and the decision was made to plug and abandon the well. There was no comparable expense in the same period in 2014.

General and administrative overhead cost increased 63% or $329,479 to $851,534 for the six month period ended June 30, 2014 from the six month period ended June 30, 2013.  This was attributable primarily to an increase in salary expenses, board fees, and professional services.  In the coming quarters we anticipate general and administrative expenses to remain stable or increase slightly.

Other expense, net for the six months ended June 30, 2014, amounted to $161,719 compared to other expense, net of $120,557 for the comparable 2013 period.  The net increase was primarily due to a $40,000 unrealized loss on commodity derivatives during the 2014 period.

Liquidity and Capital Resources

Cash flow provided by operating activities was $2,842,062 for the six month period ended June 30, 2014, as compared to $2,114,195 of cash flow provided by operating activities in the comparable 2013 period.  The increase in cash flows from operating activities was primarily due to increases in accounts payable and oil and gas revenue payable offset by lower net income.

Cash flow used in investing activities was $2,938,140 for the six month period ended June 30, 2014 and $530,027 in the comparable 2013 period due to the additions to oil and natural gas properties and equipment in each period.

Cash flow provided by financing activities for the six month period ended June 30, 2014 included $500,000 from the draw on our line of credit plus $22,259 from the exercise of 5,565 of our outstanding publicly traded common stock purchase warrants at an exercise price of $4.00 per share. Cash flow provided by financing activities for the six month period ended June 30, 2013 was $89,600 from the exercise of 22,400 of our outstanding publicly traded common stock purchase warrants at an exercise price of $4.00 per share.

We may continue to raise financing through draws from our line of credit which has a borrowing base of $11,000,000.  We anticipate our operating cash flow and other capital resources, including our Citibank revolving credit facility, if needed, will adequately fund planned capital expenditures and other capital uses over the near term.

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PART I

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We periodically enter into certain commodity price risk management transactions to manage our exposure to oil and natural gas price volatility.  These transactions may take the form of futures contracts, swaps or options.  All data relating to our derivative positions is presented in accordance with authoritative guidance.  Accordingly, unrealized gains and losses related to the change in fair value of derivative contracts that qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and natural gas sales revenues as the associated production occurs.  Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations.  While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management activities.  On March 27, 2014, we entered into a commodity derivative position effective April 1, 2014. The collars have a floor of $87.50 and a ceiling of $105.00 for 200 barrels of oil per day from April 1, 2014, to September 30, 2014. We had a realized loss of $882 and a net unrealized loss of $40,000 on commodity derivative transactions during the six month period ending June 30, 2014. We had no realized or unrealized gains or losses on derivative positions during the six month period ending June 30, 2013.

PART I

Item 4.

CONTROLS AND PROCEDURES

a)	Disclosure Controls and Procedures

Our Principal Executive Officer, Roger D. Bryant, and our Principal Financial Officer, Phillip H. Roberson, have established and are currently maintaining disclosure controls and procedures for the Company.  The disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure.

The Principal Executive Officer and the Principal Financial Officer conducted a review and evaluation of the effectiveness of the Company’s disclosure controls and procedures and have concluded, based on their evaluation as of the end of the period covered by this Report, that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed by the Company is accumulated and communicated to management, including our principal executive officer and our principal financial officer, to allow timely decisions regarding required disclosure and we refer you to Exchange Act Rule 13a-15(e).

b)	Changes in Internal Control over Financial Reporting

There have been no changes to the Company’s system of internal controls over financial reporting during the quarter ended June 30, 2014, that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting.  As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.

 

c)	Limitations of Any Internal Control Design

Our principal executive and financial officers do not expect that our disclosure controls or internal controls will prevent all error and all fraud.  Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objectives and our principal executive and financial officers have determined that our disclosure controls and procedures are effective at doing so, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute assurance that the objectives of the system are met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.  Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.  Additionally, controls can be circumvented if there exists in an individual a desire to do so.  There can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

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PART II

OTHER INFORMATION

None.

None.

None.

None.

None.

None.

 

	Exhibits
	10.1	Executive Employment Agreement
	31.1	Certifications of Chief Executive Officer
	31.2	Certifications of Chief Financial Officer
	32.1	Certification of Chief Executive Officer Pursuant to U.S.C. Section 1350
	32.2	Certification of Chief Financial Officer Pursuant to U.S.C. Section 1350
	101.INS	XBRL Instance Document
	101.SCH	XBRL Schema Document
	101.CAL	XBRL Calculation Linkbase Document
	101.LAB	XBRL Label Linkbase Document
	101.PRE	XBRL Presentation Linkbase Document
	101.DEF	XBRL Definition Linkbase Document

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SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

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